Water Management Manual

WATER MANAGEMENT identification and treatment of water-control problems for improved reservoir recovery efficiency

WATER MANAGEMENT MANUAL CONTENTS • Introduction • Table of Contents • Conformance Problems • Data Collection • Testing Methods and Equipment • Computer Programs • Treatment Options • Placement Techniques and Equipment • Conformance Treatment Evaluations

Conformance Technology

Introduction What Is Conformance Technology?

The Conformance Control Process

Conformance Technology is the application of processes to reservoirs and boreholes to reduce water production, enhance recovery efficiency, or satisfy a broad range of reservoir management and environmental objectives. Although the use of conformance processes may not result in increased production, such processes can often improve an operator’s profitability as a result of the following benefits:

The first step in effective conformance control is understanding potential conformance problems. Chapter 1 of this book reviews the characteristics of correct reservoir behavior and identifies both nearwellbore and reservoir-related conformance problems.

• longer productive well life • reduced lifting costs • reduced environmental concerns and costs • minimized treatment and disposal of water • reduced well maintenance costs Ideally, conformance control should be performed before a condition can result in serious damage. As with personal health, treating potential problems before they become serious is considerably less costly than allowing a condition to deteriorate until drastic actions must be taken. For example, just as changing lifestyle habits can reduce a person’s risk of heart disease, treating a well’s potential coning problem may prevent it from “bottoming out” in the future.

Historically, operators assessed the production of unwanted fluids based on individual wells. Recent experience, however, suggests that reservoir descriptions and reservoir evaluations can often provide valuable information that may result in more effective conformance control. Chapter 2 explains the principles of reservoir description and reservoir evaluation and provides information regarding static and dynamic reservoir properties and how these properties can affect the design of typical conformance treatments. Before an effective conformance treatment can be designed, the conformance problem must be thoroughly examined. Chapter 3 provides information regarding the production logs, cement logs, reservoir monitoring tools, downhole video equipment, and tracer surveys used for problem prediction, problem identification, and treatment evaluation.

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Introduction

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CONFORMANCE TECHNOLOGY

A simulator, such as the QuikLook simulator, can be used to help optimize the design of a conformance treatment and evaluate the chosen solution. A tool that can provide assistance during the diagnosis and treatment selection phases is Halliburton’s XERO water-control expert system. This PC-based program uses artificial intelligence techniques to identify the problem, select the proper fluid system for treating the problem, and recommend treatment designs based on the identified problem and built-in engineering calculations. Chapter 4 provides a detailed description of the QuikLook simulator and the XERO system. When a conformance problem is identified, engineers should choose an appropriate chemical system to treat the problem. Chapter 5 provides more specific information about water-based polymer systems and diesel systems.

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Introduction

When a chemical system has been selected, designers must focus their attention on selecting the appropriate placement techniques and equipment. Chapter 6 describes various placement techniques as well as the pumping, mixing, monitoring, and filtering systems typically used for conformance control. This chapter also provides information regarding the use of coiled tubing, which is becoming a popular alternative to the traditional workover rig. After a treatment has been performed, engineers can perform several tests to monitor the treatment’s success. Chapter 7 briefly summarizes treatment evaluation methods.

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HALLIBURTON

Contents

Introduction–Conformance Technology ............................................................. 0-1 What Is Conformance Technology? ........................................................................ 0-1 The Conformance Control Process ........................................................................ 0-1 Chapter 1–Conformance Problems .................................................................... 1-1 Recovery Mechanisms ........................................................................................... 1-1 Primary Recovery ........................................................................................... 1-1 Depletion (Solution Gas) Drive .................................................................................................. Segregation Drive without Counterflow ..................................................................................... Gravity Drainage (Segregation Drive with Counterflow) ............................................................ Waterdrive .................................................................................................................................

1-1 1-1 1-2 1-2

Secondary Recovery ...................................................................................... 1-3 Water-Injection Pressure Maintenance ...................................................................................... 1-3 Gas-Injection Pressure Maintenance ........................................................................................ 1-3

Problem Sources .................................................................................................... 1-3 Near-Wellbore Problems ................................................................................ 1-3 Casing Leaks ............................................................................................................................ Channels Behind Casing ........................................................................................................... Barrier Breakdown .................................................................................................................... Debris, Scale, and Bacteria ....................................................................................................... Completion Into or Near Water or Gas ......................................................................................

1-3 1-4 1-4 1-5 1-5

Reservoir-Related Problems .......................................................................... 1-5 Coning and Cresting ................................................................................................................. Channeling Through Higher Permeability .................................................................................. Fingering ................................................................................................................................... Fracturing Out of Zone .............................................................................................................. Fracture Communication Between Injector and Producer.......................................................... Lack of Communication Between Injector and Producer ...........................................................

1-5 1-6 1-6 1-6 1-6 1-6

Conclusions ............................................................................................................ 1-7 Bibliography ............................................................................................................ 1-7

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CONFORMANCE TECHNOLOGY

Chapter 2–Data Collection ................................................................................... 2-1 Well Testing ............................................................................................................ 2-1 Effect of Reservoir Nonidealities ................................................................... 2-1 Faults and Barriers .................................................................................................................... 2-1 Permeability Anisotropy ............................................................................................................. 2-2

Well Tests for Vertical Permeability ............................................................... 2-2 Vertical Interference and Pulse Tests ........................................................................................ 2-2 Formation Testers...................................................................................................................... 2-2

Layered Reservoirs ......................................................................................... 2-2 Natural Fractures ............................................................................................ 2-2 Multiple-Well Testing ....................................................................................... 2-3 Interference Tests ...................................................................................................................... 2-3 Pulse Tests ................................................................................................................................ 2-3

Reservoir Descriptions ........................................................................................... 2-3 Reservoir Heterogeneity and Conformance ................................................. 2-4 Solutions for Reservoir-Related Conformance Problems ........................... 2-7 Coning and Cresting ................................................................................................................. High-Permeability Channeling ................................................................................................... Fingering ................................................................................................................................... Induced Fractures ..................................................................................................................... Natural Fractures ...................................................................................................................... Permeability Barriers .................................................................................................................

2-7 2-9 2-9 2-9 2-10 2-10

Development Planning ................................................................................... 2-10 Field Development .................................................................................................................... 2-10 Production Planning .................................................................................................................. 2-11

Reservoir Monitoring .............................................................................................. 2-11 The Reservoir-Monitoring Process................................................................ 2-11 Seismic Data Acquisition ........................................................................................................... Seismic Processing ................................................................................................................... Seismic Data Interpretation ....................................................................................................... Well Log Analysis ...................................................................................................................... Well Test Analysis ..................................................................................................................... Geologic Model ......................................................................................................................... Seismic Verification ................................................................................................................... Simulation Model-Building ......................................................................................................... Reservoir Fluid Saturation Distribution ......................................................................................

2-11 2-12 2-12 2-12 2-12 2-12 2-12 2-13 2-13

Example ........................................................................................................... 2-13 Conclusions ............................................................................................................ 2-14 Bibliography ............................................................................................................ 2-14

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HALLIBURTON

Chapter 3–Testing Methods and Equipment ...................................................... 3-1 Fluorescent Dyes as Waterflood Tracers ................................................................ 3-1 Acknowledgment ............................................................................................ 3-1 Summary ......................................................................................................... 3-1 Manual for Tracer Test Design and Evaluation ............................................. 3-2 Abstract ..................................................................................................................................... Background Information ............................................................................................................ Information Necessary to Plan a Tracer Test ............................................................................. Calculation of Tracer Amounts ................................................................................................... Injection and Sampling .............................................................................................................. Chemical Analysis of Data ........................................................................................................

3-2 3-2 3-3 3-4 3-5 3-6

Logging Methods .................................................................................................... 3-9 FracPressure Analysis ................................................................................... 3-9 TracerScan Analysis ....................................................................................... 3-9 Logging Services .................................................................................................... 3-9 Openhole Logs ................................................................................................ 3-9 Nuclear Magnetic Resonance ........................................................................ 3-15 Cement Evaluation Logs ................................................................................ 3-17 Conventional Bond-Logging Tools ............................................................................................. 3-17 Ultrasonic Bond-Logging Tools .................................................................................................. 3-17

Casing Evaluation Logs ................................................................................. 3-22 Mechanical Logging Devices ..................................................................................................... Electromagnetic Phase-Shift Devices ....................................................................................... Ultrasonic Casing Tools ............................................................................................................. Pulsed Neutron Logs ................................................................................................................. Production Logging Tools ..........................................................................................................

3-23 3-24 3-26 3-31 3-41

Downhole Video Services .............................................................................. 3-53 Application in Oilwell Environments ........................................................................................... Detection of Fluid and Particulate Entry .................................................................................... Logging ..................................................................................................................................... Problem Identification and Remedial Treatment Planning .......................................................... In-Progress Monitoring .............................................................................................................. Post-Treatment Confirmation ..................................................................................................... Operating Limits ........................................................................................................................ Other Applications .....................................................................................................................

3-53 3-57 3-57 3-57 3-57 3-57 3-57 3-58

Conclusions ............................................................................................................ 3-59

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CONFORMANCE TECHNOLOGY

Chapter 4–Computer Programs .......................................................................... 61 Introduction ............................................................................................................ 4-1 QuikLook Simulator ................................................................................................ 4-1 Purpose and Philosophy of QuikLook .......................................................... 4-2 QuikLook Theory ............................................................................................. 4-3 Conformance Fluids Modeled by QuikLook ................................................. 4-3 WELLCAT Software......................................................................................... 4-3 General Data Requirements ........................................................................... 4-4 Validation of the QuikLook Simulator ........................................................... 4-4 Example 1—First SPE Comparative Study ............................................................................... 4-4 Example 2—Second SPE Comparative Study .......................................................................... 4-9

QuikLook as a Conformance Simulator ........................................................ 4-13 Case 1—Water Channeling in an Injector-Producer System (PermSeal Solution) ..................... 4-13 Case 2—Water Coning of a Single Gas Producer (H2Zero and PermSeal Solutions) ................ 4-20 Case 3—Water Coning of a Black-Oil Producer (PermSeal Solution) ....................................... 4-25

The XERO Program ............................................................................................... 4-31 Phase 1–Problem Identification ..................................................................... 4-31 Phase 2–Treatment Design ............................................................................ 4-39 Summary and Conclusions .................................................................................... 4-42 References ............................................................................................................. 4-43 Chapter 5–Treatment Options ............................................................................. 5-1 Water-Based Polymer Systems .............................................................................. 5-2 PermSeal Service ............................................................................................ 5-2 PermTrol Service ............................................................................................. 5-3 H2ZeroSM Service ............................................................................................. 5-3 Injectrol® Service ............................................................................................. 5-4 Example .................................................................................................................................... 5-4 Treatment Procedure ................................................................................................................. 5-5 Injectrol Sealants and Services ................................................................................................. 5-5

Relative Permeability Modifiers ..................................................................... 5-5 Kw-FracSM Stimulation Service .................................................................................................. 5-5 Oxol II RPM Removal Service ................................................................................................... 5-6

Squeeze Cementing ............................................................................................... 5-7 General Design Principles ............................................................................. 5-7 Lack of Proper Fluid Control ...................................................................................................... Improper Perforation Cleanup ................................................................................................... Low Placement Rates ............................................................................................................... No Knowledge of Where Cement Is Needed .............................................................................

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5-9 5-9 5-9 5-9

HALLIBURTON

Poor Injection Point Control ....................................................................................................... Effect of Bottomwater ................................................................................................................ Crossflow .................................................................................................................................. Poor Bonding ............................................................................................................................ Cement Flowback ..................................................................................................................... Multiple Injection Zones .............................................................................................................

5-9 5-9 5-9 5-9 5-9 5-10

MOC/One Cement ........................................................................................... 5-10 Conclusions ............................................................................................................ 5-10 Bibliography ............................................................................................................ 5-10 Chapter 6–Placement Techniques and Equipment............................................ 6-1 Placement Techniques ........................................................................................... 6-1 Placement in Injection vs. Production Wells ................................................ 6-1 Injection Wells ........................................................................................................................... 6-1 Production Wells ....................................................................................................................... 6-1

Controlling Fluid Movement ........................................................................... 6-2 K-MaxSM Service ....................................................................................................................... 6-2

Bullheading ..................................................................................................... 6-2 Mechanical Packer Placement ....................................................................... 6-4 Dual-Injection Placement ............................................................................... 6-4 Chemical Packers ........................................................................................... 6-5 Isoflow Placement........................................................................................... 6-5 Transient Placement ....................................................................................... 6-5 Service Equipment ................................................................................................. 6-6 Monitoring Systems........................................................................................ 6-6 Filtering Systems ............................................................................................ 6-6 Mixing and High-Pressure Pumping Systems.............................................. 6-6 Pumping Equipment Example ................................................................................................... 6-6

Coiled Tubing ................................................................................................... 6-9 Conclusions ............................................................................................................ 6-9 Chapter 7–Conformance Treatment Evaluations ............................................... 7-1 Introduction ............................................................................................................ 7-1 Numerical Methods ................................................................................................ 7-1 Production Data ..................................................................................................... 7-1 Injection Well Data (Hall Plot) ......................................................................... 7-1 Treatment Placement Calculations ......................................................................... 7-2 Pressure-Transient Testing to Determine Treatment Volume ...................... 7-3 Reservoir Simulation to Determine Treatment Volumes .............................. 7-5

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CONFORMANCE TECHNOLOGY

Coning and Cresting Calculations .......................................................................... 7-5 Vertical Rate Calculations .............................................................................. 7-5 Critical Rate Calculations .......................................................................................................... 7-5 Breakthrough Time Calculations ............................................................................................... 7-8 Water Cut/Water-Oil Ratio Calculations ..................................................................................... 7-9

Horizontal Well Cresting Calculations ........................................................... 7-11 Critical Rate Calculations .......................................................................................................... 7-11 Breakthrough Time and Calculations ......................................................................................... 7-12 Water Cut/Water-Oil Ratio Calculations ..................................................................................... 7-14

Chapter Abbreviations ............................................................................................ 7-15 Nomenclature .................................................................................................. 7-15 Subscripts ....................................................................................................... 7-15 Superscripts .................................................................................................... 7-15 Bibliography ............................................................................................................ 7-16 References ............................................................................................................. 7-16

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Chapter 1 By understanding correct reservoir behavior, engineers can better determine if current gas or water production is excessive or whether it could become excessive in the future. The production rates and ultimate recoveries of hydrocarbons and unwanted fluids from a reservoir depend on drive mechanisms, rock properties, fluid properties, structural relief, well locations, and reservoir management techniques. This chapter explains primary and secondary recovery mechanisms and describes common near-wellbore and reservoirrelated problems.

Recovery Mechanisms This section covers primary and secondary recovery mechanisms.

Primary Recovery The principal mechanisms driving hydrocarbon recovery are depletion, water drive, segregation, and gravity processes. For oil reservoirs, depletion (solution gas) drives result in the lowest recoveries (15 to 27%) and natural waterdrives result in the highest recoveries (35 to 70%), as shown in Figure 1.1 (Page 1-2). For dry gas reservoirs, depletion drive generally results in the highest recoveries (70 to 90%). Between these extremes are combination mechanisms involving limited wateror gas-cap drives, segregation conditions, and gravity drainage processes. The following paragraphs discuss each drive mechanism.

Chapter 1

Depletion (Solution Gas) Drive The depletion drive mechanism depends on solution gas and oil expansion as its source of energy to move fluids. In an undersaturated reservoir, the expansion of oil and dissolved gas is responsible for fluid production. As the pressure drops below the bubble point, the reservoir becomes saturated, and the liberated gas initially replaces the produced oil on an equal-volume basis, providing more reservoir energy than liquid expansion alone. Once the saturation of the gas reaches the point where it can flow, the gas is produced with the oil, which depletes the gas as a source of energy. As a result, more gas expansion is necessary per unit volume of oil produced. The relative permeability to oil is reduced, and the produced gas-oil ratio (GOR) increases rapidly.

Conformance Problems

Segregation Drive without Counterflow In high-relief geologic structures containing reservoirs with both oil and gas, the oil and gas may exist as stratified or segregated phases; for example, a gas cap may overlay an oil zone. In this type of reservoir, low vertical permeability or the presence of shale stringers or other impermeable zones suppresses the counterflow of oil and gas associated with gravity drainage processes. The primary drive mechanism is gas-cap expansion.

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Conformance Problems

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CONFORMANCE TECHNOLOGY

100

Percent of Original Reservoir Pressure

90 Waterdrive 80 70 60 50 Gas-Cap Drive 40 30 20 Solution Gas Drive 10 0 0

10

20

30 40 Percent of Original Oil Produced

50

60

Figure 1.1—For oil reservoirs, solution gas drives result in lowest recoveries. Natural waterdrives result in highest recoveries.

Although gas-cap depletion through coning or other means is harmful, this type of reservoir is often a candidate for pressure maintenance through gas injection into the gas cap.

Gravity Drainage (Segregation Drive with Counterflow) The development and expansion of a gas cap over an oil zone can result from an active fluid segregation process in which oil migrates downward because of gravity, and gas migrates upward from buoyancy effects. In this type of reservoir, the vertical permeability must favor hydrocarbon movement, and the volume of gas moving up must be equal to the amount of oil moving down. The rate of fluid segregation increases as the mobility of oil approaches that of gas. Depletion of the gas cap through coning or other means is especially detrimental to reservoir performance because this type of reservoir is not a candidate for gas injection into the gas cap.

Waterdrive Natural waterdrive reservoirs occur when an oil-bearing stratum is embedded into an aquifer or when a hydraulic connection exists between the reservoir and an outcrop that allows water infiltration. When enough water volume exists to replace the produced oil volume, the reservoir

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has an active waterdrive. If the primary movement of water is from the edge inward, approximately parallel to the bedding plane, the reservoir has an edgewater drive. If the primary water movement is upward from below, the reservoir has a bottomwater drive. Water usually provides a strong energy support mechanism, but it does so at a cost. Often, depending on the (1) completion length of the interval, (2) oil viscosity, (3) vertical permeability, (4) density difference between the oil and water, (5) distance between the perforations, and (6) water-oil contact, the water underlying the oil can eventually move into the well. Vertical water encroachment (bottomwater drive) occurs when water from an underlying aquifer, possibly connected to an outcrop, replaces the produced hydrocarbon volume. The upward moving water-oil contact resulting from reservoir depletion can eventually reach the perforations, causing water production. Horizontal water encroachment (edgewater drive) into an oil reservoir may result from a hydraulic connection with an outcrop, which can conduct large amounts of water. Generally, this effect appears as a constant-pressure boundary in the solution of the diffusivity equation for oil or gas. If permeability is heterogeneous, the drive water can channel through the higher-permeability streaks, bypassing much of the oil contained in the lower-

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Chapter 1

permeability layers. If the water is more mobile than the oil (the water-oil mobility ratio is greater than 1), the water can finger through the oil, again reducing sweep efficiency and bypassing oil.

Secondary Recovery In primary recovery, natural reservoir energy displaces oil to the production well. Any method that improves oil production beyond primary recovery is referred to as improved oil recovery (IOR). IOR processes that do not involve chemical reaction between the injected fluid and the oil in place are called secondary recovery methods. Pressure maintenance techniques such as water or gas injection are among the most widely applied secondary processes.

Water-Injection Pressure Maintenance During waterflooding, operators inject water into an oil reservoir to enhance recovery during the final stages of the primary recovery operation. When waterflooding is used, early breakthrough at the production well may occur if the water channels through high-permeability streaks. If the water is more mobile than the oil, fingering may also occur. Waterflood performance can be predicted based on the same techniques used to predict natural water influx, but additional calculations are required for the prediction of flood patterns and sweep efficiencies.

Engineers must also determine if fluid breakthrough is premature. In reservoirs with various natural drives and in enhanced recovery operations, an unwanted fluid is expected to break through eventually, even if the reservoir is ideal. Part of problem identification is determining if a problem actually exists or if everything has proceeded as planned. Engineers use such methods as reservoir simulation, volumetric analysis, decline curve analysis, and data comparisons to determine if the reservoir is depleted. They may also use a pressure-volume-temperature (PVT) analysis of the reservoir oil to determine if the produced gas is from a gas cap or dissolved gas.

Conformance Problem Sources Conformance problems are classified as either nearwellbore problems or reservoir-related problems. Some problems, however, could easily be placed in both categories. For example, barrier breakdown is related to fracturing out of zone and could be considered reservoir-related, but it is considered a near-wellbore problem. Similarly, although coning and cresting occur in the near-wellbore region and can result from a completion too near the water or gas zone, they are considered reservoir-related.

Near-Wellbore Problems Near-wellbore conformance problems include • casing leaks

Gas-Injection Pressure Maintenance

• channels behind casing

Operators use gas injection either to maintain reservoir pressure at a selected level or to supplement natural reservoir energy by reinjecting the produced gas. Complete or partial pressure-maintenance operations can result in increased hydrocarbon recovery and improved reservoir performance. However, gas-injection methods and mechanisms are generally similar to those of water injection; therefore, early gas breakthrough caused by channeling or fingering is still a concern. By including the effects of gas solution in the reservoir oil and vaporization of lighter hydrocarbons, engineers can model gasinjection reservoirs as water-injection reservoirs. Although many conformance problems are exclusive to a production well or an injection well, such a clear delineation does not always exist. Therefore, engineers must accurately determine the source of the problem before they can design the proper treatment for each well.

Chapter 1

• barrier breakdown • debris, scale, and bacteria • completion into or near water or gas

Casing Leaks An unexpected increase in water or gas production could be the result of a casing leak. Production logs, such as temperature, fluid density, Hydro, and flowmeter (spinner), can help, individually or in combination, locate where various fluids are entering the wellbore. Thermal multigate decay (TMD) and pulsed spectral gamma test (PSGT) logs can also be used. These tools detect water entry and waterflow into casing. Casing evaluation logs are used to find holes, splits, and deformities that could allow unwanted fluid entry. The logs also detect corrosion conditions that could eventu-

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CONFORMANCE TECHNOLOGY

ally cause leaks. Downhole video can also show engineers the condition of the wellbore and where various fluids enter the wellbore. Engineers can also compare water analyses between the produced water and those of nearby formations to locate the source of the leak.

migration during the initial phases of cement hydration has been thoroughly researched and several control methods have been developed. These methods include systems that exhibit controlled fluid loss, modified SGS development, and compressible systems.

Channels Behind Casing Channels can develop behind the casing throughout the life of the well, but such channels are most likely to occur immediately after the well is completed or after the well is stimulated. Unexpected water production at these times strongly indicates that a channel may exist. Channels in the casing-formation annulus result from poor cement/ casing bonds or cement/formation bonds. Fluid influx can only be prevented if proper displacement techniques are used. The factors affecting displacement efficiency are listed below.

Gas influx can also occur after the cement has set. This type of long-term gas migration is thought to occur because of poor displacement or the debonding of the pipe/cement/formation sheath. In the case of poor displacement, gas flow dehydrates the drilling fluid that the cement bypasses and results in a highly permeable flow path for gas migration. Drilling/production/ workover operations can break the cement/casing bond or cause the cement sheath to fail, resulting in a path for fluid migration. The use of good displacement practices and expansive cements should help solve such “longterm” gas migration problems.

Condition of the Drilling Fluid—Maximum circulatable hole should be achieved, and the mobility of the drilling fluid should be increased through the control of filtercake buildup. In vertical applications, these practices will result in low gel strength and viscosity. In deviated wellbores, the drilling fluid should be conditioned to prevent the dynamic settling of solids to the low side of the wellbore.

Once a well has been cemented, Halliburton can use diagnostic sonic tools (cement bond and pulse echo tools) to determine the effectiveness of the cement job. The logs these tools generate must be interpreted, and this interpretation is historically used as the basis for remedial work, such as squeezing off water and gas. Data from these sonic tools provide information about cement-to-pipe bonding and the quality of the cement-annulus seal.

Pipe Movement—Rotating or reciprocating the casing provides a mechanical means of controlling gel strength buildup. Pipe movement can eliminate a solids-settled channel.

Temperature logs that exhibit deviation from the geothermal gradient when the well is shut in indicate fluid migration behind the pipe. A zone with an abnormally high temperature indicates that fluid is migrating upward. Abnormally low temperatures indicate that fluid is migrating downward. TMD and PSGT logs can detect and quantify water flow in a channel behind the casing. When the well is shut in, borehole audio tracer surveys (BATS) help indicate possible fluid movement behind the pipe.

Pipe Centralization—Centralizers can be used to improve pipe standoff and to equalize the forces in the annulus. The result is uniform fluid flow around the casing. In deviated wellbores, a standoff of at least 70% is preferred. Displacement Fluid Velocity—Fluids should be displaced from the annulus at the highest rate possible while wellbore control is still maintained. Gas influx or fluid migration through the unset cement column occurs because the slurry cannot maintain overbalance pressure while the cement is in a gelled phase, which allows gas percolation to form a gas channel. Once a cement slurry is in place, it begins to develop static gel strength (SGS). Gel strength development inhibits the slurry from transmitting hydrostatic pressure, and when combined with hydration/fluid-loss volume reductions, the result is gas migration. Gas

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Conformance Problems

Barrier Breakdown Even if natural barriers, such as dense shale layers, separate the different fluid zones and a good cement job exists, the shales can heave and fracture near the wellbore. As a result of production, the pressure differential across these shales allows fluid to migrate through the wellbore (Figure 1.2, Page 1-5). More often, this type of failure is associated with stimulation attempts. Fractures can break through the shale layer, or acids can dissolve channels through it. Temperature, TMD, and PSGT logs can be used to detect fluid migration caused by barrier breakdown.

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Chapter 1

Oil

Oil

Shale Barrier Water

Water

Figure 1.2—Communication through a barrier

Figure 1.3—Coning

Debris, Scale, and Bacteria

Reservoir-Related Problems

Debris, scale, or bacteria deposited on the perforations or in the region around the wellbore of an injector can restrict flow through perforations, decreasing injectivity and possibly diverting fluid into unwanted regions. The presence of debris, scale, or bacteria may also indicate that permeability streaks or crossflow exist.

Reservoir-related problems include

Comparing the water analysis results of injection and reservoir fluids is an excellent means of determining the possibility of scale problems. All fluids injected into the well should be evaluated for the possibility of introducing bacteria to the formation face. In addition to water analysis results, scale problems can be detected with downhole video.

Completion Into or Near Water or Gas Completion into the unwanted fluid allows the fluid to be produced immediately. Even if perforations are above the original water-oil contact or below the gas-oil contact, proximity to either of these interfaces allows production of the unwanted fluid, through coning or cresting, to occur much more easily and quickly. Engineers should re-examine core data, the driller’s daily report, and openhole logs to determine the cutoff point of moveable water. Data from resistivity and porosity logs, for example, can be combined to determine the location of water and pay zones.

Chapter 1

• coning and cresting • channeling through higher permeability • fingering • fracturing out of zone • fracture communication between injector and producer • isolation between injector and producer

Coning and Cresting Fluid coning in vertical wells and fluid cresting in horizontal wells both result from reduced pressure near the well completion. This reduced pressure draws water or gas from an adjacent, connected zone toward the completion (Figure 1.3). Eventually, the water or gas can break through into the perforated section, replacing all or part of the hydrocarbon production. When breakthrough occurs, the problem tends to get worse because higher cuts of the unwanted fluid are produced. Although reduced production rates can curtail the problem, they cannot cure it. Fluid density, Hydro, PSGT, and TMD logs can help engineers determine the point of water entry into the wellbore. The PSGT and TMD logs can also indicate the present location of the water-oil contact before breakthrough. In addition to these logs, engineers can run additional well tests to detect bottomwater encroachment.

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CONFORMANCE TECHNOLOGY

Channeling Through Higher Permeability High-permeability streaks can allow the fluid that is driving hydrocarbon production to break through prematurely, bypassing potential production by leaving lowerpermeability zones unswept (Figure 1.4). As the driving fluid sweeps the higher-permeability intervals, permeability to subsequent flow of the fluid becomes even higher, which results in increasing water-oil or gas-oil ratios throughout the life of the project. Tracer surveys, interference and pulse testing, reservoir simulations of the field, reservoir descriptions, and reservoir monitoring are used for channel detection. Tracer surveys and interference and pulse tests verify communication between wells and help engineers determine the flow capacity of the channel. Reservoir description and monitoring verify the location of fluids in the various formations. The data available through reservoir description (Chapter 2) allow engineers to produce more accurate models of the formations and then simulate fluid movement through the reservoir. Permeability variations between zones can be revealed by core test results or pressure transient test results of individual zones.

Higher Permeability

Low Permeability

Figure 1.4—High-permeability streaks

Producer Oil

Fingering Unfavorable mobility ratios (>1) allow the more mobile displacing fluid (from either primary or enhanced recovery operations) to finger through and bypass large amounts of oil. Once breakthrough occurs, very little additional oil will be produced as the drive fluid continues to flow directly from the source to the production well (Figure 1.5). Reservoir- and drive-fluid mobilities derived from fluid and core data are probably the most important factors for determining whether fingering is a potential problem. Engineers can use reservoir simulations or available information on ideal systems to determine if sweep efficiencies are within range expected if fingering did not exist.

Fracturing Out of Zone An improperly designed or poorly performed stimulation treatment can allow a hydraulic fracture to enter a water or gas zone. If the stimulation is performed on a produc-

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Injection Water

Injector Figure 1.5—Fingering

tion well, an out-of-zone fracture can allow early breakthrough of water or gas. If the fracturing treatment is performed on an injection well, a fracture that connects the flooded interval to an aquifer or other permeable zone can divert the injected fluid to the aquifer, providing very little benefit in sweeping the oil zone. Engineers can use temperature logs, tracer surveys, and detailed reviews of the fracturing treatment to identify this problem. Microfrac treatments and long-spaced sonic logs, usually performed before the fracturing treatment, help verify the existence of vertical stress contrasts that might indicate a potential for uncontained fracture height growth.

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Chapter 1

Fracture Communication Between Injector and Producer

Open Fracture

Natural fracture systems can provide a direct connection between injection and production wells, allowing injected fluid to move through these higher-permeability channels, bypassing hydrocarbons within the rock matrix (Figure 1.6). Even if natural fractures intersecting two wells are not directly connected, fluid can preferentially flow through one fracture until it is in close proximity to another fracture or wellbore, crossing through and sweeping only a small portion of the matrix. Natural fractures serving as flow channels can be confirmed by chloride level comparisons and tracer surveys. Reservoir description should locate the discontinuities, and reservoir monitoring should detect the movement of fluids through the fracture system. A combined analysis of pressure buildup or drawdown data and interference data allows engineers to estimate the properties for both the matrix and the natural fracture system. Poorly oriented hydraulic fractures can also provide channels that allow injected fluids to bypass much of the hydrocarbon production. Although created fractures rarely interconnect two wells, a hydraulic fracture still provides a channel of higher conductivity that allows much reservoir fluid to be bypassed. Preferred fracture orientation and the possibility of enhanced recovery operations should be considered during the reservoir initial development.

Injection Well Production Well

Figure 1.6—Injected fluid moving through a high-permeability channel, bypassing hydrocarbons in the rock matrix

Conclusions With a basic knowledge of reservoir behavior and the primary causes of conformance problems, a reservoir description team can examine various wellbore and reservoir parameters to pinpoint any conformance problems that might exist in a given area. Chapter 2 presents detailed information regarding well testing, reservoir descriptions, and reservoir monitoring.

Bibliography Aguilera, R. et al.: Horizontal Wells, Gulf Publishing Co., Houston, TX (1991). Arps, J.J. et al.: “A Statistical Study of Recovery Efficiency,” API Bulletin D-14.

Various technologies, such as microfrac analysis and anelastic strain recovery, allow engineers to determine the expected direction of fracture growth. If engineers know the lengths and directions of any hydraulic fractures, they can use reservoir simulations to model flow through the system and determine the expected sweep efficiency.

Arthur, M.G.: author’s reply to discussion of “Fingering and Coning of Water and Gas in Homogeneous Oil Sand,” Trans., AIME, (1944) 45:200-01.

Isolation Between Injector and Producer

Beterge, M.B. and Ertekin, T.: “Development and Testing of a Static/Dynamic Local Grid-Refinement Technique,” JPT (April 1992) 487.

If oil or gas production does not respond to injection, the problem could be a lack of communication between the injector and producer. A natural barrier, such as a sealing fault, can separate the wells, or they can be perforated in different zones. Interference and pulse tests help determine if interwell communication exists. Reservoir description reveals the presence of major heterogeneities, such as faults.

Chapter 1

Bateman, R.M.: “Building a Reservoir Description Team–A Case Study,” The Log Analyst, (1993) 67-73; 34, 4.

Bournazel, C. and Jeanson, B.: “Fast Water-Coning Evaluation Method,” paper SPE 3628 presented at the 1971 SPE Annual Fall Meeting, New Orleans, Oct. 3-6. Bournazel, C.L. and Sonier, F.: “Physical Models for the Study of Oil Drainage with Cone Formation,” ARTFP 3rd Meeting, Pau, France, Technip Editions, 1969.

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Byrne, W.B. and Morse, R.A.: “Waterconing May Not Be Harmful–1,” OGJ (Sept. 3, 1973) 66-70.

Joshi, S.D.: Horizontal Well Technology, PennWell Publishing Company, Tulsa, OK, 1991.

Chaperon, I.: “Theoretical Study of Coning Toward Horizontal and Vertical Wells in Anisotropic Formations: Subcritical and Critical Rates,” paper SPE 15377 presented at the 1986 SPE Annual Technical Conference and Exhibition, New Orleans, Oct. 5-8.

Kabir, C.S.: “Predicting Gas Well Performance: Coning Water in Bottom-Water-Drive Reservoirs,” paper SPE 12068 presented at the 1983 SPE Annual Technical Conference and Exhibition, San Francisco, Oct. 5-8.

Chapplelear, J.E. and Hirasaki, G.J.: “A Model of OilWater Coning for Two-Dimensional, Areal Reservoir Simulation,” SPEJ (April 1976) 65-72. Coats, K.H.: “An Analysis for Simulating Reservoir Performance Under Pressure Maintenance by Gas and/or Water Injection,” SPEJ (Dec. 1968) 331-40. Collins, D.A., Ngheim, L.X., and Grabenstrotter, J.E.: “An Efficient Approach to Adaptive-Implicit Compositional Simulation with an Equation-of-State,” paper SPE 15133 presented at the 1986 California Regional Meeting of SPE, Oakland, CA, April 2-4.

Karp, J.C., Lowe, D.K., and Marusov, N.: “Horizontal Barriers for Controlling Water Coning,” JPT (July 1962) 783-90. Lake, L.W.: Enhanced Oil Recovery, Prentice Hall, Englewood Cliffs, NJ (1989) 223. Meyer, H.I. and Garder, A.O.: “Mechanics of Two Immiscible Fluids in Porous Media,” Journal of Applied Physics, 25, No. 11, 1400. Mungan, N.: “A Theoretical and Experimental Coning Study,” SPEJ (June, 1975) 247-54. Muskat, M.: The Flow of Homogeneous Fluids Through Porous Media, IHRDC, Boston (1982) 454-476.

Cottin, R.H. and Ombret, R.L.: “Application of a Multiphase Coning Model to Optimize Completion and Production of Thin Oil Columns Lying Between Gas Cap and Water Zone,” paper SPE 4632 presented at the 1973 SPE Annual Fall Meeting, Las Vegas, Sept. 30-Oct. 3.

Papatzacos, P., Gustafson, S.A., and Skaeveland, S.M.: “Critical Time for Cone Breakthrough in Horizontal Wells,” presented at the 1988 Seminar on Recovery from Thin Oil Zones, Norwegian Petroleum Director ate, Stavanger, Norway, April 21-22.

Dahl, J.A. et al.: “Current Water-Control Treatment Designs,” paper SPE 25029 presented at the 1992 SPE European Petroleum Conference, Cannes, France, Nov. 16-18.

Papatzacos, P. et al.: “Cone Breakthrough Time for Horizontal Wells,” paper SPE 19822 presented at the 1989 SPE Annual Technical Conference and Exhibition, San Antonio, TX, Oct. 8-11.

Graig, F.F.: The Reservoir Engineering Aspects of Waterflooding, Monograph Series, SPE, Richardson, TX (1980) 3.

Reed, R.N. and Wheatley, M.J.: “Oil and Water Production in a Reservoir With Significant Capillary Transition Zone,” paper SPE 12066 presented at the 1983 SPE Annual Technical Conference and Exhibition, San Francisco, Oct. 5-9.

Giger, F.M.: “Analytic 2-D Models of Water Cresting Before Breakthrough for Horizontal Wells,” SPE Reservoir Engineering (Nov. 1989) 409-16. Giger, F.M.: “Horizontal Wells Production Techniques in Heterogeneous Reservoirs,” paper SPE 13710 presented at the 1985 SPE Middle East Oil Technical Conference, Bahrain, March 11-14. Høyland, L.A., Papatzacos, P., and Skjaeveland, S. M.: “Critical Rate for Water Coning: Correlation and Analytical Solution,” SPE Reservoir Engineering (Nov. 1989) 495-502.

Slider, H.C.: Practical Petroleum Reservoir Engineering Methods, Petroleum Publishing Company, Tulsa (1976) 353-364. Sobocinski, D.P. and Cornelius, A.J.: “A Correlation for Predicting Water Coning Time,” JPT (May 1965) 594-600. Weber, K.J.: “How Heterogeneity Affects Oil Recovery,” Reservoir Characterization, Academic Press, Orlando, FL, 487-544.

Joshi S.D.: “Augmentation of Well Productivity Using Slant and Horizontal Wells,” JPT (June 1988) 729-39.

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Chapter 1

Weber, K.J.: “Reservoir Modeling for Simulation Purposes,” Development Geology Reference Manual (ed.), American Association of Petroleum Geologists, Tulsa, OK (1992) 531-535. Wheatley M.J.: “An Approximate Theory of Oil/Water Coning,” paper SPE 14210 presented at the 1985 SPE Annual Technical Conference and Exhibition, Las Vegas, Sept. 22-25. Yang, W. and Wattenbarger, R.A.: “Water Coning Calculations for Vertical and Horizontal Wells,” paper SPE 22931 presented at the 1991 SPE Annual Technical Conference and Exhibition, Dallas, Oct. 6-9. Zhao, L.: Progress Report No. 16, Texas A&M University Reservoir Modeling Consortium (1993).

Chapter 1

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Chapter 2 To understand the source or potential source of a problem, conformance control design teams must thoroughly investigate all aspects of well and reservoir parameters, including geological, petrophysical, well completion, and production/injection log data. All of this information may not be available, and some of the available information may not sufficiently identify the source of the problem; therefore, additional tests may have to be performed. By fully understanding the different mechanisms that contribute to a conformance problem, engineers can better evaluate the information available, identify additional tests, and perhaps better determine possible problems. This chapter describes well testing, reservoir description and monitoring methods, and specifies how a design team can use the data collected to identify conformance problems and plan treatments.

Well Testing Well tests provide information regarding pertinent reservoir properties, such as horizontal and vertical permeability. They can also reveal the presence of heterogeneities and verify interwell communication. This section discusses the general effects of reservoir nonidealities on pressure-transient testing and how well testing can be used to quantify these nonidealities. In addition, the application of multiple-well tests to conformance technology is discussed.

Chapter 2

Effect of Reservoir Nonidealities Reservoir nonidealities, such as barriers, permeability anisotropy, layered systems, and natural fractures, play important roles in well conformance. Researchers have examined the effects of each nonideality on pressure-transient behavior, and have developed methods and tests to determine their existence or magnitude. Such tests, however, should be supported by additional geologic, seismic, fluidflow, and performance data. Engineers should not infer heterogeneous reservoir properties based solely on transient testing.

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Faults and Barriers Barriers, such as sealing faults, can prevent communication between injection and production wells. If faults are located near an injector, they could cause rapid pressure changes early in the well life that could be mistaken for indications of other injector-related problems. On an appropriate semilog plot, a linear barrier, such as a sealing fault, appears as a second straight-line portion of double slope in drawdown, two-rate pressure buildup, injectivity, and pressure falloff testing. Log analysts must be careful to ensure that wellbore storage effects are not causing the two apparent semilog straight lines. The use of the intersection time of the two straight-line segments allows analysts to determine the distance from the well to the

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fault. The method for this determination depends, of course, on the type of well test performed. Multiple faults are not as easily analyzed as a single fault because their relative angles and distances from the well affect transient test-pressure behavior.

Permeability Anisotropy The degree to which a reservoir’s permeability is anisotropic affects coning or cresting behavior near the well and will factor into the degree of crossflow between adjacent permeable layers. Typically, vertical permeability is less than horizontal permeability in petroleum reservoirs. Because the response curve of an anisotropic reservoir is the same as an isotropic reservoir, anisotropy cannot be recognized from a single-well test; the permeability determined from one test is considered an average permeability. However, multiple-well transient tests are available that allow engineers to recognize and quantify anisotropic reservoir properties. Well tests are also available for determining vertical permeability.

Well Tests for Vertical Permeability Methods for estimating vertical permeability include vertical interference testing, vertical pulse testing, and the use of a formation tester.

Vertical Interference and Pulse Tests To perform vertical interference and pulse tests, operators must complete the well so that part of the completion can be used for production or injection and another part for observation. A favorable method is to separate the active (injection or production) perforations from the observation perforations with a packer. Theoretically, either set of perforations can serve as the active or observation perforations, but operators generally prefer to use the upper set for the active perforations. In general, operational considerations for these types of tests are more demanding than other tests because operators must (1) limit or eliminate wellbore storage effects, which can mask the pressure response, and (2) eliminate any communication between the two sets of perforations, except through the matrix permeability. In addition to the increased operational difficulty, the analysis of vertical pulse tests is more complex than that of horizontal tests because of the influence of upper and lower formation boundaries on the test. Vertical interference tests are also possible, but they can only be properly analyzed with specialized software.

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Formation Testers Formation testers measure pressures at individual points within a wellbore as fluid samples are taken. As fluids are withdrawn from the formation, a drawdown permeability is calculated from the pressures measured. Spherical buildup permeability is calculated from pressures measured while the formation relaxes to an undisturbed state. Through mathematical relationships, horizontal and vertical permeabilities are calculated from these two values.

Layered Reservoirs The pressure transient behavior of a layered system with crossflow is the same as the behavior of a homogeneous system. Therefore, normal pressure-transient testing will not reveal the layered nature of the reservoir. In these systems, the effective permeability-thickness product will be the total of the permeability-thickness products of the individual layers. Likewise, the effective porositycompressibility-thickness product will be the total of the porosity-compressibility-thickness products of the individual layers. For layered reservoirs separated by barriers that prevent crossflow, early-time drawdown or buildup behaviors cannot be distinguished from those of a single-layer system. However, at later times, once boundary effects occur, the presence of the boundary will be sensed at different times in each layer if the layers have different properties. The resulting behaviors can be analyzed through the use of special techniques. By isolating and testing each layer in a layered reservoir with a straddle packer, analysts can estimate the permeabilities, skin factors, and average pressures of all layers.

Natural Fractures Natural fracture systems, among the most common of heterogeneities, can create flowpaths that allow injected water or drivewater to bypass hydrocarbons within the formation matrix. If the natural fractures occur predominantly in a single direction, the reservoir behaves as a system with anisotropic permeability, and well-testing methods developed for anisotropic behavior can be applied. Natural fractures can also occur in an interconnected system that exhibits two distinct porosity types: (1) the fine, low-permeability pores of the matrix and (2) the higher-permeability system of fractures, fissures, and vugs.

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Chapter 2

The existence of this dual-porosity system manifests itself in pressure-transient testing behavior. For buildup and drawdown tests, techniques are available for determining the total permeability-thickness product for the system, as well as skin factor and average reservoir pressure. A ratio of the porosity-compressibility product of the fracture system to that of the total system is also available. A combined analysis of pressure drawdown or buildup data and interference data allows engineers to estimate the properties of both the matrix and the fracture system.

Multiple-Well Testing As implied by the name, multiple-well transient tests involve more than one well. They require at least one active (producing or injecting) well and at least one pressure-observation well. For practical rather than theoretical reasons, the observation well is shut in for pressure measurement. In addition to providing information on interwell communication, multiple-well tests allow engineers to investigate a larger portion of the reservoir. The investigation area includes the region between the wells and a radius of influence that depends on the reservoir properties and the testing time. Although multiple-well tests are designed to provide information on the effective reservoir properties, they can also indicate whether communication exists between two or more wells. In a multiple-well test, the flow rate of the active well is varied, while the bottomhole pressure response at the observation wells is measured. A lack of response at the observation well indicates little or no communication. This condition suggests that either the active and observation wells are completed in different zones or that a boundary, such as a sealing fault, could exist between the wells. If a response occurs at the observation well, it can usually help engineers determine such parameters as permeability and the porosity-compressibility product. In addition, methods have been developed for estimating anisotropic reservoir characteristics from interference testing. Because multiple-well tests measure properties over a region of influence, the variation in fluid properties (for example, mobility) that exists with fluid-fluid contacts can cause the results to be unreliable or meaningless when they are applied to conformance control. The two major types of multiple-well tests are the interference test and the pulse test. Of the two tests, the pulse test requires less time, but it is more difficult to analyze.

Chapter 2

Interference Tests During an interference test, operators modify the longterm rate, usually by shutting in the active well. Techniques as simple as type-curve matching and semilog plots are applied to the pressure responses measured at the observation wells. In addition, permeability anisotropy can be determined from interference tests that involve multiple observation wells and more complex analysis techniques. If natural fractures exist, they may substantially affect observation well behavior in interference tests. Because early-time behavior is most greatly affected, type-curve methods may not provide correct results in these instances, but semilog methods should still apply.

Pulse Tests During a pulse test, a number of short-duration rate pulses are used at the active well. These production or injection pulses are made at the same rate and duration, and the pulses are separated by shut-in periods of the same duration. The pressure responses measured at the observation well can be small, sometimes less than 0.01 psi, requiring special pressure-measuring equipment. When used on naturally fractured reservoirs, pulse tests can provide erroneous results.

Reservoir Description Historically, engineers have assessed the condition of unwanted fluid production on a well-by-well basis without the benefit of reservoir understanding. While many conformance problems can be traced to mechanical (near-wellbore) problems, a significant number of conformance problems are the result of reservoir-related phenomena. By understanding a reservoir’s characteristics, engineers can more easily identify, control, and sometimes predict a conformance problem. To understand reservoir behavior, engineers must have a description of the static and dynamic properties of a reservoir. Although reservoir information from a problem well may provide valuable information that engineers can use to create a treatment for that well, truly effective reservoir understanding generally results from a multiplewell or field-scale reservoir description. Reservoir description is the quantitative assessment of both static and dynamic subsurface properties, both spatial and temporal. Reservoir descriptions can be

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Static Reservoir Properties

Geophysics

Structural Configuration

Geology

Petrophysics

Engineering

Stratigraphic Framework

h Volumetric Estimate of Fluids in Place

Geologic Model

φ

Reservoir Simulator

Dynamic Reservoir Properties

Optimization of Field Operations

Economic Analysis

Production Forecasts

k Figure 2.2—Integrated approach to reservoir description

P Sw Q φ = porosity h = thickness k = permeability P = pressure Q = rate Sw = water saturation

Figure 2.1—Static and dynamic reservoir properties (modified after Bateman, 1993)

performed at various scales, ranging from a broad basin analysis to an individual reservoir unit analysis. Static properties do not usually change with time and include the size, shape, position, and storage capacity of the flow units. Dynamic properties vary with time and include the initial, current, and future distribution of fluids in the flow units (Figure 2.1). Ideally, a reservoir description should result in a conceptual 3D model that describes the spatial distribution of fluid and rock properties within the gross thickness and areal extent of the reservoir. However, a more limited or problem-specific reservoir description, such as a study of natural fractures, may provide the

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reservoir engineer with the information necessary to identify or treat a conformance problem such as channeling through natural fractures. Any reservoir description should be based on an integrated dataset (geology, geophysics, petrophysics, engineering) prepared by a multidisciplinary team (Figure 2.2). A field-scale reservoir description allows team members to quickly classify the primary production mechanism, identify large-scale trends, and incorporate reservoir heterogeneity when planning secondary or improved oil recovery.

Reservoir Heterogeneity and Conformance Various heterogeneities control the distribution and movement of fluids in a field and reservoir. These heterogeneities include faults, stratigraphic surfaces, flow-unit boundaries, and fractures (Figure 2.3, Page 2-5). Because of macroscopic and microscopic features, porosity and permeability are also heterogeneously distributed throughout a reservoir and field. Table 2.1 (Page 2-6) shows the impact of various types of reservoir heterogeneity on fluid distribution and movement.

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Chapter 2

1. Faults: Sealing fault Semisealing fault Nonsealing fault

Oil

2. Boundaries between genetic units

3. Permeability zonation within genetic units

4. Flow baffles within genetic units

5. Sedimentary structures Lamination Cross-bedding Bioturbation 6. Microscopic heterogeneity Textural types Pore types Cements Clays 7. Fractures Open Partially cemented Cemented Healed

Figure 2.3—Types of reservoir heterogeneity (modified after Weber, 1992)

Chapter 2

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Table 2.1—Types of Reservoir Heterogeneity Reservoir Heterogeneity Type

Reservoir Continuity

Horizontal Sweep Efficiency

Vertical Sweep Efficiency

ROS in Swept Zones

Rock/Fluid Interactions

O X X

O O O

— O O

— — —

— — —

O

O

O

—

—

—

X

O

—

—

Baffles within genetic units

—

X

X

X

—

Lamination, crossbedding

—

X

—

X

—

Microscopic heterogeneity

—

—

—

O

X

Textural types Mineralogy Tight fracturing Open fracturing X = Major influence

— — — —

— — X O O = Minor influence

— — — —

Sealing fault Semisealing fault Nonsealing fault Boundaries as genetic units Permeability zonation within genetic units

Figures 2.4 and 2.5 (Page 2-7) illustrate the effects that reservoir and field-scale heterogeneity have on fluid distribution and movement on waterfloods and oil production. Accurate descriptions and a thorough understanding of field and reservoir heterogeneity allow design teams to predict, manage, and even control the movement of reservoir-related fluids (oil and water) and gas. A reservoir’s static properties do not generally change during the life of a field. Therefore, engineers can delineate the structural features (faults and folds) and determine stratigraphic surfaces and geometries by interpreting 2D or 3D seismic data. Wireline logs provide detailed views of near-wellbore formation thickness, dip, natural and induced fractures, and petrophysical properties such as porosity, lithology, and fluid saturations. Studies of cores and cuttings provide details on sedimentary structures, rock texture/ fabric, mineralogy, pore types and networks, and other microscopic heterogeneities. By integrating these datasets, a design team can construct a stratigraphic framework and develop structural, depositional, and diagenetic models. The team can then use these models to construct a 3D geologic model that represents the distribution of the various types of reservoir heterogeneity throughout the field.

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O — O O — = No influence

O O — —

A well-defined geologic model provides the information necessary for the next phases of field/reservoir development. This model must be dynamic, must be updated as new data is acquired, and must evolve with field development. Effective assessment of a reservoir’s dynamic properties is essential before and during the development phase. To derive fluid types, properties, and distribution, team members can examine petrophysical, well-test, and production data and use advanced reservoir simulators based on the geologic model. Simulation is a vital part of the reservoir management decision-making process because it yields production forecasts for a variety of production alternatives and economic scenarios. In mature fields, where production rates have declined and formation pressures have fallen, the team may be required to evaluate existing secondary recovery activity and model possible secondary recovery options. Strategies for pressure maintenance, infill drilling, workover, and conformance problems can be improved if the results of a reservoir simulation are available. Existing geological, geophysical, petrophysical, and engineering data may often seem sparse in comparison with reservoir size and complexity, and acquiring new

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Chapter 2

data is frequently costly. Table 2.2 (Page 2-8) shows the value of various data for identifying and quantifying different types of reservoir heterogeneity. Finally, the spatial and temporal relationships that exist in a reservoir are difficult to perceive. Reservoir engineers have found 3D displays to be powerful tools for interpreting faulting and fluid regimes that may remain hidden or be obscured in traditional 2D displays, such as maps and cross sections.

Producer

Injector

Solutions for Reservoir-Related Conformance Problems A reservoir description solution can be developed for each of the following reservoir-related nonconformance phenomena identified in Chapter 1:

K/

K/ Φ K/ = 7 Φ K/ = 3 Φ =5

• coning and cresting • high-permeability channeling

Φ = K/ 2 Φ Φ= =2 5

• fingering

K/

• induced fractures • natural fractures • permeability barriers

Figure 2.4—Effect of reservoir heterogeneity on a waterflood front [Movement of the water front is irregular from areal, vertical, and intrareservoir (intralayer or intrazone) perspectives.]

Cumulative Water Injection Cumulative Oil Production

Figure 2.5—Cumulative oil production and cumulative water injection across a field [Distribution of both oil and water volumes is generally heterogeneous; however, at least two subtle trends in both the oil and water volumes may be interpreted (dashed lines).]

Chapter 2

Coning and Cresting As mentioned in Chapter 1, whenever a well is producing from an oil zone overlaying a water layer (aquifer), the near-wellbore pressure gradients may deform the horizontal oil-water contact into a cone or crest. The height or vertical reach of the cone or crest above the oil-water contact depends on the pressure gradient around the wellbore. The tendency for water or gas to cone is inversely related to the density difference between existing oil and gas or water and directly proportional to the viscosity and the pressure drawdown near the wellbore. The density difference between gas and oil is higher than the density difference between gas and water, but gas has a lower viscosity than water. However, formation permeability and thickness generally dictate the extent of coning that occurs because higher-permeability rock has higher flow rates and requires less drawdown. In practice, most wells are perforated closer to the oil-water contact than the gasoil contact; therefore, water coning is a common conformance issue.

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Table 2.2 (1 of 2)—Value of Data for the Identification and Qualification of Heterogeneity Reservoir Heterogeneity Type Sealing fault Semisealing fault Nonsealing fault Boundaries as genetic units Permeability zonation within genetic units Baffles within genetic units Lamination, crossbedding Microscopic heterogeneity Textural types Mineralogy Tight fracturing Open fracturing

Production Logs — — —

Standard Well Logging O O O

Special Well Logging X — X

ROS Well Logging X — —

Cores X X X

SWS Cuttings — — —

Outcrop or Analog Reservoir X X X

X

O

O

X

O

X

O

X

O

X

O

O

X

O

X

O

X

—

O

—

O

—

O

—

—

O

—

O

—

—

—

—

—

—

—

— X — X

— X X X

— — — O X = Major value

— — — X

— X — — O = Minor value

— X — —

— O O O — = No value

Table 2.2 (2 of 2)—Value of Data for the Identification and Qualification of Heterogeneity Reservoir Heterogeneity Type Sealing fault Semisealing fault Nonsealing fault Boundaries as genetic units Permeability zonation within genetic units Baffles within genetic units Lamination, crossbedding Microscopic heterogeneity Textural types Mineralogy Tight fracturing Open fracturing

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Detailed Seismic O O O

Horizontal Reservoir Pressure Distribution O O X

Vertical Reservoir Pressure Distribution X X X

Production Tests X X —

Pulse Tests O X —

Tracer Tests X X —

Production History O X —

X

O

O

X

X

X

X

—

—

X

X

X

—

—

—

—

X

—

X

—

X

—

—

—

—

—

—

—

—

—

—

—

—

—

—

— — — X

— — O O

— — — X X = Major value

— — — O

— — — X O = Minor value

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— — O O

— — — O — = No value

Chapter 2

Before team members can treat a coning problem, they must characterize fluids and reservoir-fluid interactions. To determine the coning or cresting tendencies of different parts of the reservoir, engineers must measure the density, gravity, and viscosity of the hydrocarbon fluids and establish the relative permeability of the reservoir rocks. For example, homogeneous reservoirs with active drives are more prone to coning. To understand the distribution of variations in reservoir thickness and permeability, the team must model the reservoir’s static properties. In this way, they can evaluate the coning tendencies of different parts of the field and/or reservoir. By understanding the reservoir and/or field static and dynamic properties, the team can anticipate potential coning problems. To set production limits that should preclude coning problems in oil or gas reservoirs, team members can calculate a critical production rate based on available reservoir parameters. A reservoir description that includes the distribution and magnitude of permeability heterogeneities and variations in reservoir thickness allows such calculations to be refined to more accurately represent the actual fluid dynamics of the reservoir.

High-Permeability Channeling Reservoirs containing fractures or high-permeability streaks may suffer from early water breakthrough and poor sweep efficiency. As fluids are produced from a reservoir, zones of higher permeability and correspondingly higher flow rates create channels for the preferential movement of fluids. In the case of water, this condition can result in premature communication between a reservoir and an aquifer or premature communication between an injector and a producer. In either case, sweep efficiency is diminished. To eliminate or inhibit channeling, engineers may recommend placing gels in the high-permeability zones at the injection wells. These gels plug the high-permeability zones and force the injected water to sweep the oilsaturated, low-permeability zones. For such gel placements to be successful, engineers must understand the lateral and vertical distribution of the permeability zones to identify interwell flow regimes. To reduce or prevent the effects of high-permeability channeling, engineers can map the lateral and vertical distribution of permeability during reservoir description. By knowing the distribution of high-permeability zones (potential channels) across the field or reservoir, the operations engineer can more easily avoid or control channeling-related nonconformance.

Chapter 2

Fingering Viscous fingering is significant in a waterflood environment, especially when high oil-water viscosity ratios exist. Under these conditions, discrete streamers or “fingers” of displacing water may move through the reservoir or field. When high oil-water viscosity ratios exist, instabilities occur at the oil-water interface because of the driving fluid’s higher mobility. The mobility ratio compares the driving fluid (water or gas) mobility to the driven fluid (oil) mobility. Mobility is defined as the ratio of a fluid’s effective permeability to its viscosity (keff/µ). Ideally, the mobility ratio should be less than 1; otherwise, fingering could result. In a field of several types of reservoirs, the hydrocarbons trapped in each reservoir may not be the same. In some cases, oil gravities may vary substantially from one reservoir to another, even in the same part of the field. Therefore, the mobility of some hydrocarbons relative to water, for instance, may be different in different parts of a field. In addition, static reservoir properties and heterogeneities may dictate the preferential flow of oil, gas, or water, depending on the placement and number of these fluids. During reservoir description, engineers can estimate the fractional flow of fluid phases based on laboratory tests on core samples to determine relative permeabilities and capillary pressures of the wetting phase. During these tests, the variation and distribution of fluid types and fluid properties are characterized and modeled, as well as the static reservoir properties. By integrating the static and dynamic properties into a reservoir model, engineers can predict and plan for zones and scenarios in which fingering is likely to occur.

Induced Fractures Injection above the formation parting pressure inadvertently creates stresses in the reservoir zone that exceed the tolerance of the reservoir rock. These stresses can induce fractures that can modify expected fluid flow patterns. If the induced fractures do not extend beyond the reservoir pay zone, the effect is generally positive (similar to hydraulic fracture stimulation). However, if the induced fractures extend into a gas or water zone, they become high-permeability conduits that allow communication (channeling) between the reservoir and these zones, resulting in diminished sweep efficiency and oil recovery. In-situ reservoir stresses and rock strength control the initiation, opening, and propagation direction of the induced fractures. By understanding the in-situ stress

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field and the mechanical strength of the rock at reservoir conditions, engineers can accurately determine formation parting pressure and the probable intensity, spacing, length, and orientation of any induced fractures. With this information, the design team can plan or modify injection activities to minimize or prevent nonconformance problems.

Natural Fractures Natural fractures are common components of many reservoirs and can provide significant flow paths for fluid movement. Natural fractures can connect oil and water zones and define flow patterns or trends for subsurface fluids. Fractures can also provide a significant portion of reservoir quality by contributing permeability, porosity, or both. When planning production and injection activities, engineers must consider the influence and effects that the fracture system has on hydrocarbon and water distribution and movement. To understand natural fractures, engineers must determine fracture geometry, orientation, intensity, and distribution in 3D space. The reservoir properties of the fracture system (fluid flow interaction or crossflow related to the fracture system, and the fracture system’s contribution to total reservoir quality) must be qualitatively or quantitatively determined. Rocks that have a multistage history of deformation may contain several sets of fractures, each with different characteristics and effects on reservoir performance.

Permeability Barriers The assumption that no horizontal or vertical permeability barriers exist in a typical reservoir is generally wrong. Intrareservoir heterogeneities, such as depositional boundaries (nonconformities), facies changes, diagenetic effects, sedimentary structures, and irregular pore networks can all produce permeability barriers. These barriers disrupt predicted fluid flow, resulting in diminished sweep efficiency and nonconformance problems. For example, horizontal permeability barriers may halt or redirect waterflood fronts, while vertical permeability barriers directly affect water coning and could, in some cases, promote a more uniform flood front or prevent gravity segregation. Production tests and production/injection profiles often show the influence and effects of permeability barriers. Field maps of production and injection data (histories) also often reflect the influence of reservoir permeability barriers (“dead zones”). However, in most cases, a

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detailed geologic study is required before permeability barriers can be identified, quantified, and mapped. If the design team chooses to inject fluid to stabilize or repressure a reservoir, they must carefully consider the distribution and geometry of the permeability barriers in the interwell space; otherwise, the production plan will likely contain inefficient production and injection designs.

Development Planning In addition to identifying and providing solutions to reservoir-related conformance problems, reservoir description can provide valuable information for field development and production planning. Specifically, reservoir description can significantly enhance the quality and accuracy of performance predictions for the following: •

waterflooding

•

infill drilling

•

horizontal/highly deviated wells

•

improved/enhanced oil-recovery schemes

•

stimulation applications

Field Development During reservoir description, team members characterize and model the fluid types, fluid properties, and field-scale heterogeneities. This information can then be applied to well-pattern planning. For example, reservoir conditions quantified by the reservoir description model can be used to simulate the results of various injection schemes based on a variety of common patterns for injection and producing wells. In addition, special features of the reservoir and/or field, such as natural fracture distribution and orientation and permeability trends, can be included in the evaluation of optimal well patterns. By identifying, understanding, and mapping both the permeability barriers and reservoir continuity, designers can determine effective well spacing and assess sweep efficiency based on their understanding of the static and dynamic properties of the reservoir provided in the reservoir description. If the reservoir is not well understood, fluid movements may occur outside modeled predictions and unexpected heterogeneity may occur in production and injection volumes across the field. Poor reservoir understanding will fail to uncover reservoir heterogeneities that can significantly impact the fluid distribution and movement

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in the field or reservoir, limit options for field development, and negatively impact the sweep efficiency and ultimate oil recovery.

engineers can identify, design, and accurately place the proper conformance treatment to optimize the production of reservoir fluids.

Production Planning

Reservoir monitoring does not replace reservoir description or reservoir simulation. Instead, it integrates both technologies to allow engineers to more accurately describe a reservoir and predict its future performance. In other words, the purpose of reservoir monitoring is not merely to obtain a better reservoir description by integrating more focused surface reflection seismic data with well-log, well-test, and well-performance information. Instead, it results in an overall integrated reservoirmonitoring process that combines this description with fluid-front measurement and simulation.

When wells are completed too near the fluid contacts, in the transition zones, or out of zone, expensive conformance problems may result early in the life of the well. For example, an early high gas-oil ratio (GOR) may result in the loss of reservoir pressure, or high water cuts could force premature revisions of the lift equipment. Both problems could have been avoided with better reservoir understanding. In addition to identifying and mapping fluid contacts, engineers can use reservoir description to determine reservoir thickness and distribution, which allows them to delineate zones for completion (and stimulation). By understanding in-situ reservoir stresses, pressures, and rock fabric and strength, engineers can help eliminate wellbore and near-wellbore damage. When a truly effective reservoir description exists, the design team can better understand reservoir behavior and develop more effective development strategies. Ideally, reservoir descriptions should be updated throughout the life of the field, from the exploration phase through abandonment. The underlying objective of reservoir description is effective reservoir management, which can increase production, maximize economic value, and minimize capital investments and operating expenses.

Reservoir Monitoring Reservoir monitoring integrates reservoir description and reservoir simulation with multiple-reflection seismic surveys. Reservoir monitoring allows engineers to track the movement of fluid saturations in a reservoir and predict how the fluids will move in the future.

If fluid movement in a producing hydrocarbon reservoir is accurately monitored, improved recovery may result. For example, reservoir monitoring may lead to better reservoir management, better placement of infill wells, and breakthrough deferral. Reservoir monitoring may also result in lower costs as a result of fewer wells being drilled and reduced water and gas handling. As long as formation thicknesses are sufficient for seismic detection, reservoir monitoring is applicable onshore and offshore to depths of more than 10,000 ft for both sandstones and carbonates. The success of reservoir monitoring is based on two fundamental principles: the seismic principle and the simulation principle. The fundamental seismic principle is that a change in fluid saturations within a reservoir will change the reservoir’s seismic response. The fundamental simulation principle is that the additional data points in space and time provided by a direct measurement of fluid saturation within a reservoir add substantially to the data set used for history-matching; therefore, the data substantially improve the accuracy of the results.

The Reservoir-Monitoring Process

Engineers can achieve better well conformance (1) by observing the detailed 3D horizontal and vertical movement of oil-water, oil-gas, gas-water, and thermal interfaces, and (2) by being able to predict the breakthrough of injected fluids or the coning of reservoir fluids under the current scenario or alternate scenarios. With this information, they can delay or prevent breakthrough.

Figure 2.6 (Page 2-12) shows the steps in a reservoirmonitoring study from seismic data acquisition through final integration. Each step focuses on the reservoir and integrates with the other steps to allow reservoir monitoring teams to obtain the most accurate solution possible.

If breakthrough has already occurred, and a 3D seismic baseline survey is available, engineers may be able to determine whether lateral heterogeneity, vertical heterogeneity, or coning was the cause. By identifying the cause of breakthrough and observing fluid movement patterns,

In this first step, members of the monitoring team design a seismic data-acquisition program to greatly enhance their ability to monitor fluid-contact movement. Their primary focus is on maximized resolution and repeatability.

Chapter 2

Seismic Data Acquisition

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recalibration of log traces, log analysis, and generation of the final database and displays.

Seismic Data Acquisition Seismic Processing Seismic Data Interpretation

Well Log Analysis

Geological Model

Well Test Analysis

Seismic Model Building Seismic Verification Simulation Model Building Simulation Verification Final Integration and Verification Reservoir Fluid Saturation Distribution

Figure 2.6—Reservoir monitoring process flowchart

Seismic Processing During the seismic processing phase, team members perform normalizations, both between successive surveys and well logs. These surveys consist of information regarding positioning, amplitudes, two-way times, and wavelets. The normalizations are based on the known invariance of subsurface geology over calendar time. Least-squared-error cross-equalization filters as well as temporal and spatial shifting filters are used.

Seismic Data Interpretation During the interpretation stage, team members use conventional seismic data to begin developing a detailed reservoir description.

Well Log Analysis During this phase, a standard field development or reservoir exploitation log analysis should be performed. This study includes data preparation, data editing, depth shifting, environmental correction, normalization or

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The log analysis should include complex lithology determination and a log model of rock facies in addition to the standard results such as porosity, saturation, and estimates of permeability. During this analysis, logging analysts should edit and correct sonic and density logs for synthetic seismograph generation and plot the corrected logs in two-way time for display on seismic sections. The lithologic results must be tied to the seismic signature of each well.

Well Test Analysis During this phase, team members should analyze well tests as they would for a normal reservoir description study. Specifically, members should determine permeability and barrier locations to situate geologic changes within the reservoir.

Geologic Model A geologic model that best exemplifies the initial conclusions regarding deposition environment and structural modification can then be constructed. This model allows engineers to integrate all seismic, well log analysis, production engineering, and geologic information. The resulting reservoir description would normally be used in reservoir simulation projects. During the simulation portion of the project, engineers would modify the description as necessary to match actual reservoir performance, based on measured pressure and production data at each well as the matching criteria.

Seismic Verification The initial seismic model honors both the structure contained in the seismic data and the high vertical resolution from the wells. However, it need not tie exactly to the seismic amplitudes at each trace nor to the observed values of the optimal seismic indicators derived from the seismic interpretation. Engineers use these seismic amplitudes and indicators to update the model so that its fine structure not only ties together at the wells, but also ensures that the model predicts the seismic attributes at each trace location. Fluid movements in the reservoir are not expected to change structural characteristics, but the different fluids in that structure will change its seismic response. As a result, the detailed structural model derived from the base survey also applies to the monitor surveys.

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Simulation Model-Building

The result is a match of all of the production and monitoring information and a final reservoir description as expressed by the data in the reservoir simulator.

After completing the previously described phases, team members develop a complete, detailed reservoir description, which includes the integration of all seismic data, well log data, and pressure-transient test results with a geologic model. The combination of these data forms the reservoir model that the team uses to simulate fluid flow throughout the reservoir.

Reservoir Fluid Saturation Distribution The resulting reservoir simulation is as accurate and detailed as possible from available data. Engineers can use the simulation to generate saturation maps describing the current distribution of fluids or to predict future reservoir response to various production and development scenarios.

During this phase, engineers verify the simulation by history-matching all the time-dependent data through the changes in the reservoir description within geologic bounds. This step is similar to the normal historymatching process except, in addition to production and pressure information at well points, the information to be matched includes saturation profiles obtained from the surface-reflection seismic portion of the reservoir monitoring process. Therefore, a great deal more data are available for the reservoir simulation verification process, making the results of the process more detailed than the results for a standard history match.

N

Example Figure 2.7 is a single-layer map of a reservoir. The increases in gas saturation from the first time interval to the second time interval are in the highlighted area that was swept by gas during the interval. The white areas on the map indicate areas where displacement and gas saturation were unchanged. The simulation does not include seismic time-lapse data.

Sg Difference, OSEBERG 3

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Figure 2.7—Gas-saturation difference map showing gas-displaced area estimated by simulation (Courtesy Norsk Hydro, Bergen, Norway)

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Conclusions

Figure 2.8 is a seismic amplitude difference map for the same reservoir, showing the difference in seismic data values from surveys taken 16 months apart. Because seismic reflections from formation interfaces should not change, the map shows the difference in gas saturations between the two points. However, since conditions cannot be exactly duplicated from one survey to the next, noise, in the form of colored areas, also appears on the map. The area considered to show actual gas movement is the magenta and red band east of Well 20. (Note the resemblance to the band in Figure 2.7, Page 2-13.) This band shows how the gas front has moved in the time interval between surveys.

Through the use of well testing, reservoir descriptions, and reservoir monitoring, engineers can more effectively plan and implement a successful conformance control treatment. Chapter 3 provides specific information regarding the methods and equipment available for reservoir evaluation and problem identification.

Bibliography Archer, S.H. and Martinez, R.D.: “A Comparison of Petrophysical Equations for Extrapolation of Lithology Beyond Well Locations Using Seismic Data,” presented at the 53rd Meeting of the European Association of Exploration Geophysicists, Florence, May 1991.

Because they are relatively small compared to the reflections at formation interfaces, the seismic reflections at changes in fluid saturations cannot be readily seen from a single seismic survey. However, since difference maps subtract the features of the reservoir that do not change, engineers can use these maps to locate a fluid front and determine how it is moving through a reservoir. Although this particular example is for a single horizontal slice, vertical fluid positions and movement can also be determined from these maps.

Archer, S.H., King, G.A., and Uden, R.C.: “An Integrated Approach to Reservoir Characterization Using Seismic and Well Data,” paper F03 presented at the 1993 Meeting of the European Association of Exploration Geophysicists, Stavanger, Norway, June 7-11.

1989-1991 Difference 12-40 Hz 2356 100

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Figure 2.8—Gas saturation difference map showing actual gas-front position (Courtesy Norsk Hydro, Bergen, Norway)

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Archer, S.H., King, G.A., Seymour, R.H., and Uden, R.C.: “Seismic Reservoir Monitoring - The Potential,” First Break (Sept. 1993) 11 No. 9, 391-97. Breitenbach, E.A.: “President Breitenbach Defines Challenges for SPE, Industry,” JPT (Oct. 1993) 918. Clark, V.A.: “The Effect of Oil Under In-situ Conditions on the Seismic Properties of Rocks,” Geophysics (July 1992) 57 No. 7, 894-901. Cornish, B.E. and King, G.A.: “Combined Interactive Analysis and Stochastic Inversion for High-Resolution Reservoir Modelling,” presented at the 50th Meeting of the European Association of Exploration Geophysicists, The Hague, June 1988. Domenico, S.N.: “Effect of Water Saturation on Seismic Reflectivity of Sand Reservoirs Encased in Shale,” Geophysics (Dec. 1974) 39 No. 6, 759-69. Dunlop, K.N.B., King, G.A., and Breitenbach, E.A.: “Author’s Reply to Discussion of Monitoring Oil/ Water Fronts by Direct Measurement,” JPT (Dec. 1991) 1525. Dunlop, K.N.B., King, G.A., and Breitenbach, E.A.: “Monitoring of Oil/Water Fronts by Direct Measurement,” JPT (May 1991) 596. Dussan, E.B. and Sharma, Y.: “Analysis of the Pressure Response of a Single-Probe Formation Tester,” SPEFE (June 1992) 151.

Johnstad, S.E., Uden, R.C., and Dunlop, K.N.B.: “Seismic Reservoir Monitoring Over the Oseberg Field,” First Break (May 1993) 11 No. 5, 177-85. King, G.A.: “The Application of Seismic Methods for Reservoir Description and Monitoring,” presented at the 1988 SEG/CPS Production Geophysics Meeting, Daqing, Sept. Maritvold, R.: “Frigg Field Reservoir Management,” North Sea Oil and Gas Reservoirs II, Norwegian Institute of Technology, Graham and Trotman (1990) 155-63. Martinez, R.D. et al.: “An Integrated Approach for Reservoir Description Using Seismic, Borehole, and Geologic Data,” paper SPE 19581 presented at the 1989 SPE Annual Technical Conference and Exhibition, San Antonio, Oct. 8-11. Martinez, R.D. et al.: “Complex Reservoir Characterization by Multiparameter Constrained Inversion,” presented at the 1988 SEG/EAEG Research Workshop on Reservoir Geophysics, Dallas, Aug. Revoy, M.: “Frigg Field Production History and Seismic Response,” presented at the Offshore North Sea Conference, Stavanger (1984). Seymour, R.H. and Archer, J. S.: “Some Requirements from Seismic Methods for Use in Reservoir Simulation Models,” North Sea Oil and Gas Reservoirs II, Norwegian Institute of Technology, Graham and Trotman (1990) 139-46.

Earlougher, R.C. Jr.: Advances in Well Test Analysis, Society of Petroleum Engineers of AIME (1977) New York, 105-122. Earlougher, R.C. Jr.: Advances in Well Test Analysis, Societyof Petroleum Engineers of AIME (1977) New York, 123-146. Greaves, R.J., Beydoun, W.B., and Spies, B.R.: “New Dimensions in Geophysics for Reservoir Monitoring,” SPE Formation Evaluation (June 1991) 141-50. Hao Zhi-xing and Shen Lian-di: “Mechanism of Transit Time Increase and Its Interpretation After Water Injection Into Reservoir M in the Lao Jun Miao Oil Field,” SPE Formation Evaluation (June 1988) 471-79. Johnstad, S.E., Seymour, R.H., and Dunlop, K.N.B.: “The Feasibility of Monitoring Fluid Movements During Production from a Norwegian Oilfield Using

Chapter 2

Repeated Seismic Surveys,” presented at the 52nd Meeting of the European Association of Exploration Geophysicists, Copenhagen (May 1990).

Seymour, R.H. et al.: “The Potential Contribution of Surface Seismic Surveys to Monitoring Offshore Oilfields,” presented at the 1989 51st Meeting of the European Association of Exploration Geophysicists, Berlin, May. Shell: “Science & Technology,” Brochure, SIPM Group Public Affairs, ref. PAC/223, Shell Centre London (Dec. 1990). Wayland, J.R. and Lee, D.: “Seismic Mapping of EOR Processes,” Geophysics: The Leading Edge (Dec. 1986) 36-40.

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Chapter 3 Many technologies can help engineers determine the source of a conformance problem, foresee a potential conformance problem, or evaluate a conformance treatment. This chapter describes three of these technologies: tracer surveys, logging services, and downhole video services.

Fluorescent Dyes as Waterflood Tracers Acknowledgment Halliburton Energy Services thanks The Tertiary Oil Recovery Project (TORP) for granting permission to publish the material presented in this section.

Summary In cases where very rapid communication (about 5 days) is thought to exist between an injector and a producer, fluorescent dyes are considered excellent tracer materials. These dyes are adsorbed to some extent on typical reservoir rocks, but even trace amounts can be detected visually in the produced water without elaborate chemical analysis. Detection of water flow communication between wells can confirm the presence of channels and help size and plan corrective treatments. The usual placement method is to inject a concentrated “slug” of the tracer while the normal waterflood is maintained. Producers offset to the injection well are monitored for the presence of tracer. Fluorescent dyes are easily detected by the naked eye

Chapter 3

at 1 ppm concentration, equivalent to 1 lb/2,850 bbl of water. A “black light” is used to illuminate the water samples for detection of 50 parts per billion of dye. The extreme sensitivity of this detection method allows the use of dyes, provided residence time in the reservoir is not too long and despite high adsorption on rock surfaces.

Testing Methods and Equipment

The two most readily available fluorescent tracers are sodium fluorescein, also known as uranine, which is yellow-green, and Rhodamine B, which is red fluorescence. Uranine is available from Halliburton (Part No. 70.15632). Pylan Products Co., Inc., 1001 Stewart Avenue, Garden City, NY 11530, (516) 2221750 supplies both dyes. Several other sources exist, and most laboratory chemical supply houses have these dyes. The amount of dye to use in a particular situation depends primarily on how much the tracer will be diluted. A pound of dye in an injection well that takes 200 to 500 BWPD is a suggested starting point. This amount provides sufficient dye for some dilution and adsorption while still allowing the dye to be detected at the end of a channel. These dyes are readily water-soluble, and placement is simple. The dye can be dissolved in water, 1 lb/5 gal, and placed into an injection well by any convenient method. If the well will go on vacuum, the dye solution can be dumped in. It can also be added through a lubricator or injected with the waterflood pump. If pumping the

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CONFORMANCE TECHNOLOGY

tracer is necessary, using a tracer volume of a few barrels of water to give the pump truck enough fluid to prime the pump would be simpler. (Everything the truck pumps for a day or two may be dyed after pumping these materials.) After placement of the dye, return the well to normal injection to displace the tracer. Monitor offset producers fairly often over the next several days for the presence of the dye. The tracer typically “spreads out” in the formation and continues to show up for some time after initial breakthrough. The initial appearance is the piece of data that allows observation to estimate the shortest path between the injector and offset producers. If more quantitative calculations are required, such as mass balances, use other nonadsorbing tracers. Several are available that require only simple lab (or field) chemical testing. A good reference on these is listed below. Terry, R. E., et al.: Manual for Tracer Test Design and Evaluation, published by Tertiary Oil Recovery Project, 4008 Learned Hill, University of Kansas, Lawrence, KS 66045. Co-Directors: Don W. Green and G. Paul Willhite. The majority of the manual published by TORP follows.

Manual for Tracer Test Design and Evaluation Abstract The purpose of this information is twofold: (1) to provide background information on a technique that utilizes chemical tracers to describe fluid flow in reservoirs and (2) to provide information that will assist an operator in the design, implementation, and analysis of a tracer study.

Background Information As the need for implementation of enhanced oil recovery processes increases, the need for better reservoir and fluid-flow description also increases. Enhanced oil recovery processes often use expensive chemicals, such as polymers, surfactants, and cosurfactants. A knowledge of the path those chemicals will traverse in the reservoir is necessary to make wise and efficient use of them. Well logs and core permeability data provide some information about the region near the wellbore. A knowledge of previous waterflooding history can add useful information about interwell communication. Also, pressure transient tests, which can be rather expensive, can supply information about fluid flow between wells.

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Another source of information of reservoir behavior is to trace injected water with a chemical and observe when and where that chemical is produced. Several tracer tests have been reported in the literature (Page 1-5) that provide design and analysis techniques. A well-planned and executed tracer test can provide information in some, if not all, of the following areas. Directional Flow Trends When a chemical tracer is injected into an injection well and the surrounding producing wells are monitored, different arrival times for the tracer could indicate preferred flow paths or directional flow trends. These preferred flow paths would be from the injector to the specific producers that receive the most tracer at the earliest time. Adjustment of injection and withdrawal rates could alter these directional flow trends, giving an improved sweep efficiency. Identification of Rapid Interwell Communication If a channel or high-permeability streak exists between an injector and a producing well, a tracer experiences a very early breakthrough. This early breakthrough identifies problem injection wells that could require a treatment to alter permeability. Volumetric Sweep Through a knowledge of injection and production rates, pattern layout, and the pore volume in the reservoir, breakthrough of tracers often yields an estimate for the volumetric sweep efficiency. Very small injected volumes of floodwater to breakthrough indicate the existence of a channel or high-permeability streak and give an estimate for the volume of that zone. Larger injected volumes to breakthrough indicate a more uniform permeability distribution, and again, a volume of the swept zone could be estimated. Delineation of Flow Barriers If a fault or some other barrier to fluid flow is thought to exist near a producing well, tracers can be injected into injection wells surrounding the suspect producing well. The failure to observe one or more tracers in the producing well could be the result of a flow barrier. Two other areas where the use of tracers provide useful information are (1) evaluation of sweep improvement techniques and (2) evaluation of relative flow of two different fluids, such as brine and polymer. The former requires that a tracer study be conducted before and after the application of a sweep improvement process. The

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latter requires the injection of a different tracer in each fluid of interest. If the measured breakthrough times are different for the tracers, then the fluids could be assumed to have contacted different portions of the reservoir and thus have different flow characteristics. Greenkorn described the ideal tracer as “one that would follow the fluid of interest exactly as the fluid front.” But the ideal is impractical to attain because adsorptiondesorption effects cause the tracer to lag behind the front. These effects, plus diffusion-dispersion effects, cause the tracer front to spread out more than the fluid front. Carpenter et al. have set forth the following requirements for a tracer to be satisfactory in measuring the movement of flood water in secondary recovery operations. 1.

A tracer should be quantitatively determined in less than 10 ppm concentration. 2. It should be either absent or present only at low concentrations in the displaced and injected waters. 3. It must not react with the injected or displaced waters to form a precipitate. 4. It must not be adsorbed by the porous medium. 5. It must be cheap and readily available. There are four general types of tracers for use in aqueous systems: radioisotopes, fluorescent dyes, water-soluble salts, and water-soluble alcohols. The radioisotopes provide an advantage because they are easily detectable in small concentrations and have insignificant adsorption losses in the reservoir. Tritium as tritiated water is one of the most widely used tracers in the field. However, a firm licensed by the Nuclear Regulatory Commission is required to handle and inject all radioisotope materials. Frequently, when radioactive materials are used, it is necessary to work with state agencies as well. The fluorescent dyes can also be detected in very small concentrations, but they have the disadvantage of being highly adsorbed on reservoir rock. The dyes should only be used in cases where there is thought to be a very rapid (5 days or less) communication between an injector and a producer. When radioactive tracers are prohibited because of a lack of a licensed firm to do the handling, water-soluble salts and alcohols are the tracers most frequently used. A few of the common water-soluble salts and alcohols are listed below. Preferred Water Tracer Materials Ammonium Thiocyanate (NH4SCN) Chapter 3

Ammonium Nitrate (NH4NO3) Sodium or Potassium Bromide (NaBr or KBr) Sodium or potassium Iodide (NaI or KI) Sodium Chloride (NaCl) 2-Propanol (IPA) Methanol (MeOH) Ethanol (EtOH) Analytical techniques to measure the concentrations of each of the tracers mentioned are described in the Chemical Analysis of Data section. Unfortunately, not all of the analysis techniques can be performed with ease in the field. This requires using a supportive laboratory for some of the chemical analyses. Care should be taken to determine the background levels in field waters of any ions that might interfere with the analysis of those ions that are considered tracers. High levels could inhibit the measurement of tracer concentrations in produced samples. Compatibility tests should also be made on the proposed tracers with the injected brines. Adsorption of ions onto the reservoir rock surface could be detrimental to using a particular water-soluble salt. The water-soluble alcohols, with the possible exception of 2-propanol, are susceptible to biodegradation and therefore should be used with bactericides where the bactericides are usually in concentrations of about 50 ppm. Produced samples should also be treated with the bactericide to prevent alcohol degradation before the samples are analyzed. 2-Propanol does have a limited solubility in some crude oils, which could cause retention of the alcohol in the reservoir. All of these factors should be considered before selecting a tracer.

Information Necessary to Plan a Tracer Test Before a tracer test can be designed, a pilot or pattern area needs to be defined. Once a pilot area is chosen and well pattern and isopach maps are collected, all available reservoir data are analyzed to determine reservoir permeability, pore volume, water saturation, and formation thickness. These data, combined with production data, including injection and withdrawal rate information, are needed to calculate the required amounts of tracers and to model tracer breakthrough. Information pertaining to the effectiveness of a waterflood that may have been conducted in the pilot area is also useful in the design and analysis of a tracer test. The importance of keeping good records of all production and injection data and workover information for each

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well in the pilot area cannot be overemphasized. These records need to be kept for each well in the pilot area. It is not enough to know the production rate for the entire field or pattern area. A test on each production well once or twice a month would be sufficient to identify the individual well rates. The individual well production and injection rates are necessary to make material balance calculations and also, as mentioned above, to provide input data for the mathematical treatment of the data. The material balance calculation is useful in determining expected breakthrough times and places.

For example, consider the injection well in Figure 3.1 and the corresponding reservoir data.

Another major consideration in designing a tracer test is the information obtained from the analysis of field brines and supply waters used in injection wells. Background levels should be determined for all chemicals being considered as tracers. Often, a chemical analysis has been conducted on a water sample. This analysis usually provides concentrations of Na+ and Cl- ions, bivalent ions, such as Ba2+, Ca2+, and SO42-, and the amount of total dissolved solids, density, viscosity, and turbidity of the water sample. A synthetic brine can be made using the compositions determined from the water analysis. Synthetic brines are usually easier to work with than actual field brines, and as a result, tracer analysis techniques are typically developed in the synthetic brine. However, before a specific tracer is finally chosen, it is necessary to determine the background level and test the analysis procedure for the tracer in the actual field brine and/or supply water. If a tracer is not compatible with the field brine or the field brine contains ions that interfere with the tracer analysis test, that tracer should not be used. A knowledge of which, if any, chemicals are being used as treating agents is also useful in the design of a tracer test. Oxygen scavengers or bactericides are frequently used to keep corrosion to a minimum. If bactericides are used, the water-soluble alcohols become prime candidates for use as tracers.

Calculation of Tracer Amounts The amount of a tracer that should be used for a given application can be calculated by several different methods. This section isolates one of those methods. If the pore volume associated with a given injection well can be determined, the amount of tracer can be calculated by assuming the tracer will dilute the entire pore volume.

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DN001136

Before any tracers are injected, the reservoir must be “pressured up.” This requires that the reservoir be on waterflood long enough to fill any void space, therefore minimizing potential loss of tracer material.

Figure 3.1—Pattern Layout for Tracer Amount Calculation.

Average reservoir thickness, h = 20 ft Average reservoir porosity, φ = 25% Average water saturation, Sw = 55% Density of tracer solution, 350 lb/bbl The areal extent of the reservoir associated with this injection well will be given by: Area = d2 The distance between producing wells (d) can be calculated from: 2 (2002) = d2 d = 283 ft The pore volume associated with this injection well is: Pore Volume = (Area) (h) (φ) PV = (80,000) (20) (0.25) PV = 400,000 ft3 or 71,238 bbl The water pore volume can be obtained by multiplying by the water saturation. (PV) Sw = 71,238 (0.55) = 39,181 bbl

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If the density of the tracer solution is multiplied by this volume, the result is the mass (in pounds) of the tracer solution that would occupy the entire water-pore volume associated with the injection well.

m = 0.001247 (Area) (h) (φ) (Sw) Eq. 3.4:

Mass of tracer occupying entire water pore volume, mpv.

m = 54.3 (Area) (h) (φ) (Sw)

mpv: 39,181 (Density) = 39,181 (350) = 13.71 x 106 lb If the required concentration is 10 ppm of tracer in the effluent, the amount of tracer (m) that needs to be injected will be:

Injection and Sampling

Eq. 3.3:

Tracers are injected into the reservoir as rapidly as possible. The alcohols and other liquid tracers should be diluted at least 50% with the injection water before injection. The solid tracers, usually obtainable in 50- to 100-lb bags, need to be mixed with the injection water. Care should be taken to stay well below the solubility of the tracers in the brine water. Table 3.1 lists solubility data for several common tracers in distilled water.

m = (mass) (concentration in effluent) m = (13.71 x 106) (10/106) m = 137 lb Frequently a safety factor is used in engineering calculations. The magnitude of the safety factor is in the range of 2 to 5 but can be higher, depending on the operator. A safety factor of 2 means that 274 lb of tracer would be required. Summing up the calculations and combining them into one equation gives the following expression for m.

The solubility of the tracers in actual field brines is less than those listed in Table 3.1. Once a concentration is determined, it should always be tested in the actual field brine. This test gives the operator an indication of how much mixing time will be required to dissolve the tracer and confirms that it will be soluble. The third column in Table 3.1 gives recommended concentrations. These recommended concentrations can be used as starting points for specific applications.

Eq. 3.1: m = 0.356 (Area) (h) (φ) (Sw) (Density) (Desired Concentration) The constant contains a safety factor of 2 and a conversion factor, 5.615 ft3/bbl, to convert the pore volume in ft3 to barrels.

Figure 3.2 (Page 3-6) is a schematic representation of an injection system. The system consists of a pumping unit, mixing tank, and lubricator. The mixing tank should have a capacity of about 10 bbl. The lubricator should have a capacity of about 2 bbl. The solution of water-soluble salts can be prepared easily in the mixing tank using the pump to recirculate the water. While the water is circulated, the tracer is added to the system. The circulation action is usually enough agitation to solubilize the tracer.

If the area is known in acres, the equation becomes: Eq. 3.2: m = 15,516 (Area) (h) (φ) (Sw) (Density) (Required Concentration) Assuming a desired breakthrough concentration of 10 ppm and a density of 350 lb/bbl, Eqs. 3.1 and 3.2 become:

Table 3.1—Solubilities and Recommended Injection Concentrations

Tracer Ammonium Thiocyanate Ammonium Nitrate

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Solubility in Distilled Water (lb/bbl) 420

Recomm ended Injection Concentration (lb/bbl) 200

1,280

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556

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446

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Sodium Chloride

125

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Alcohols

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Figure 3.2—Typical injection system.

Table 3.2—Sampling Frequency in Terms of Expected Breakthrough Breakthrough Sampling Interval 1 day 1 to 2 hours 2 to 3 hours 2 days 4 to 8 hours 3 days 4 to 7 days 8 to 16 hours 1 to 2 weeks once a day 2 to 4 weeks every other day 1 or more months once a week

Sampling the produced water in the surrounding producing wells is a very important part of the tracer program. Samples need to be taken often enough that the initial breakthrough of tracers is not missed. On the other hand, the more often samples are taken, the more analytical work needs to be done, which adds expense to the program. A rule of thumb for sampling frequency in terms of expected breakthrough is presented in Table 3.2. Any information the operator has on the field, i.e., response to waterflood, etc., should be used to help determine a sampling frequency.

Chemical Analysis of Data A variety of chemicals have been used to follow the flow of water through porous media. An ideal tracer is a material that is easy to detect, does not interact with the rock or the oil, is inexpensive, and free of environmental hazards. All these characteristics cannot be found in a single substance. However, several chemicals have been identified that meet part of the criteria and have been successfully used to monitor flow of water in oil reservoirs. Only two classes of chemicals are considered in this (TORP) manual: alcohols and salts.

For tracing water flow, only water-soluble alcohols, such as methanol (methyl alcohol), ethanol (ethyl alcohol), 1propanol (n-propyl alcohol), and 2-propanol (isopropyl alcohol) are useful. Analysis of any of these alcohols requires equipment not normally found in the oil field. The easiest and most rapid method of analysis for watersoluble alcohols is by gas chromatography. Operating the equipment can be performed by field personnel. However, setup, maintenance, and interpretation of unusual results requires trained personnel. Since analysis of alcohols by gas chromatograph does not lend itself to onsite analysis, no details of analytical procedure are included in this version of the (TORP) manual. For completeness, the advantages and disadvantages of alcohol tracers are listed below. Advantages 1.

Alcohols listed above are compatible with injection waters. 2. Four tracers can be detected and determined in one analysis. 3. Analysis procedure lends itself to automation in the laboratory. 4. Alcohols are relatively inexpensive. Disadvantages 1. 2. 3. 4. 5.

Alcohols are susceptible to biological degradation. Propanol has some solubility in oil. Analysis does not lend itself to rapid onsite determination by field personnel. Alcohols are flammable and can be dangerous. Alcohols are sometimes found in welltreating fluids.

Salts Various inorganic salts have been used to trace the flow of water. A salt is comprised of two parts: the cation and an anion, which provides two distinct entities when dissolved in water. For example, sodium chloride dissolves in water to give sodium cations and chloride anions. Each ion is a tracer. Chloride anion can be determined easily, but the sodium cation is determined with difficulty. Using chloride anion as a tracer does not depend on the sodium cation. Thus, potassium or ammonium chloride could be substituted for sodium chloride, if chloride is the tracer.

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Three salts have been used as tracers, ammonium nitrate, sodium bromide, and ammonium thiocyanate. Each of these tracers is discussed separately. The discussion includes a description of an analytical method of determination. Nitrate Nitrate is determined colorimetrically by the reduction of nitrate by cadmium metal in acid solution in the presence of gentisic acid to give a colored material. The proper proportion of reagents is conveniently combined in a commercial product by Hach Chemical Company of Loveland, Colorado. The analysis procedure follows. Procedure Place 25 mL (2 tablespoons) of water sample in a small bottle. It is convenient to use a two-ounce bottle and fill it one-half full of the sample. 2. Add contents of NitraVer V reagent pillow to bottle. 3. Shake bottle for 1 minute. 4. Let stand for 5 minutes. 5. Compare the intensity of amber color to set of standard solutions or to a color wheel, or measure the intensity of the color in a spectrophotometer at 500 nm. For field work, the color cube of a color comparator wheel available from Hach Chemical works well. Detection and estimation of amount of nitrate can be performed by non-experienced personnel. Advantages

2. 3. 4.

2. 3. 4. 5.

Ferric iron in the water can cause high results. Large amounts of chloride cause low results. Barium in the water causes turbidity that can cause color comparison difficulty. Colored substances in the water can look like the amber color developed during the reaction. Ground waters can contain nitrate from runoff from adjacent fields. Using nitrate as a tracer has met with mixed success in the field.

Chapter 3

Reagent Solutions Ferric chloride a. Weigh out 10 g FeCl3 • 6H2O and place in oneliter flask. Measure out 15 mL concentrated HCl and add to flask. (Caution: HCl fumes are irritating to eyes and nose.) Add distilled water to make 1 L of acid ferric chloride reagent, or b. Weigh out 1.5 oz of FeCl3 • 6H2O and place in 1-gal glass or plastic container. Measure 1.5 fluid oz (3 tablespoons) of concentrated hydrochloric acid and add to a 1-gal container. Add distilled water to make 1 gal of acid ferric chloride solution. Note: Concentrated HCl is 12 normal. If six normal HCl is available, double the amount stated. The six normal acid is less irritating to handle than the concentrated acid. Procedure

Ammonium nitrate is readily available from fertilizer suppliers and venders. It is inexpensive. Analysis can be performed in the field by non-skilled personnel. It is a minimal biohazard.

Disadvantages 1.

The presence of thiocyanate in water can be detected by ferric thiocyanate complex, which colors the water red. The intensity of the red color indicates the amount of thiocyanate present. Certain materials in the water can interfere with the formation of the ferric thiocyanate complex. The salt in 20,000 ppm brine decreases the intensity of the red coloration by about one-half. Copper, zinc, and lead form an insoluble precipitate with thiocyanate. As a result, the thiocyanate is no longer available for forming the red ferric thiocyanate complex.

1.

1.

1.

Thiocyanate

1a. Take 100-mL of sample water and add 10 mL of ferric chloride solution. A red color develops immediately if thiocyanate is present, or 1b. Take one cup, 8 oz, of sample water and add one tablespoon of ferric chloride solution. A red color should develop immediately on mixing if thiocyanate is present. 2. Compare intensity of color with that of standard samples or measure color intensity in spectrophotometer at 450 nm. Standard Solutions Solution 1 1.

2.

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Weigh out 1.3 g of ammonium thiocyanate and dissolve in 1 L of water. This gives 1,000 ppm NH4SCN solution. Take 100 mL of NH4SCN solution and dilute to 1 L. This gives a 100-ppm NH4SCN solution.

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3.

Take 10 mL of 100-ppm solution and dilute to 1 L. This gives a 10-ppm NH4SCN solution, or Solution 2

Weigh out 2 oz of ammonium thiocyanate (NH4SCN) and dissolve in 1 gal of water. This gives a 11,430ppm NH4SCN solution. 2. Take 8 oz of NH4SCN solution and dilute to 1 gal. This gives a 700-ppm NH4SCN solution. 3. Take 8 oz of 700-ppm solution and dilute to 1 gal. This gives a 45-ppm NH4SCN solution. If necessary, prepare other concentrations of NH4SCN by dilution. Since 20,000-ppm brine causes a decrease in color intensity, it is convenient to use produced water to make the NH4SCN solution. Advantages

b.

1.

Thiocyanate can be detected in the field by field personnel. Disadvantages

Procedure 1. 2. 3. 4. 5.

1.

1.

Copper, lead, and zinc in the produced water interfere with the formation of red ferric thiocyanate. 2. High brine concentration reduces sensitivity of the test. 3. Bromide is determined colorimetrically by the oxidation of bromide to bromine in acid solution by potassium bromate. The intensity of the reddish brown color of bromine in water can be used to estimate the amount of bromide. As an alternative, the bromine can be extracted into chloroform or carbon tetrachloride. This is helpful if the water sample is yellowish in color. Reagent Solutions 1.

2.

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In a well-ventilated area, measure out 3 oz of concentrated hydrochloric acid in a plastic or glass measuring cup and pour into quart glass or plastic container. Measure out 2 1/2 oz of concentrated phosphoric acid and add it to a quart container. Add distilled water to make one quart of acid buffer solution.

Take 100 mL of water sample. Add 50 mL of acid buffer solution. Add 10 mL of potassium bromate solution. Shake or mix solutions together A reddish-brown color is indicative of bromine. Optional - Add 25 mL of carbon tetrachloride or chloroform and shake. Reddish-brown color indicates bromine is present.

Alternate 1. 2.

Take 4 oz, 1/2 cup, of water sample. Add 2 oz of acid buffer solution.

3.

Add 1/2 ounce, 1 tablespoon, of potassium bromate solution. 4. Mix or shake the sample. A reddish-brown color to water is indicative of bromine. 5. Optional - Add one ounce of carbon tetrachloride or chloroform and shake. Reddish-brown color indicates bromine is present. 6. Measure the color intensity in a spectrophotometer at 390 nm. Advantages

Potassium bromate

1. Bromide can be detected in the field by field personnel. Disadvantages

a.

1.

Weigh 1 g of KBrO3 and dissolve in 1 L of distilled water, or b. Weigh 1/2 ounce of KBrO3 and dissolve in one quart of distilled water. Take 2 oz and dilute to 1 quart with distilled water. Acid buffer solution a. In a well-ventilated area, measure out 85 mL of concentrated hydrochloric acid (HC1) and pour into 1-L flask. Measure out 70 mL of concentrated phosphoric acid (H3PO4) and add to liter flask. Add distilled water to make 1 L of acid buffer solution, or

Testing Methods and Equipment

2. 3.

Many brine waters contain approximately 100 ppm bromide. Quantitative determination of bromide does not lend itself to measurement in the field. Presence of iodide can interfere with bromide results.

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Logging Methods

confirms that the propped intervals did not communicate with one another. Therefore, the TracerScan log confirmed the fracture height modeling and fracture design, and analysts deemed the operation a success.

FracPressure Analysis Engineers can combine full-wave sonic measurements with bulk-density log data to predict fracture height as a function of the differential pressure between downhole treatment pressure and fracture closure pressure. The log shown in Figure 3.3 (Page 3-10) shows a FracPressure analysis. Engineers predicted fracture height before the treatment to ensure that the job design limited fracture growth and avoided the water table. Track 1 contains the gamma ray and stress profiles. Fracture pressure is the amount of pressure equal to the least principal stress; this pressure is computed from the rock properties measured by sonic and density logs. This stress profile identifies barriers to fracture growth and stress contrasts between producing zones. Track 2 of Figure 3.3 shows the calculated static fracture extension. The fracture extension pressure is the pressure necessary for the fracture to extend vertically. The pressure blocks indicate the extent of the fracture with the length of their right-most edge. Track 3 shows formation lithology as determined from an openhole log analysis.

TracerScan Analysis To determine the effectiveness of hydraulic fracture treatments, engineers may choose to inject radioactive tracers during the frac job. These tests can be run in two ways: a different isotope can be used in each of several zones or a fluid stage or a sand stage can be simultaneously tagged with different isotopes and evaluated with a spectral gamma ray log. Figure 3.4 (Page 3-11) shows a TracerScan analysis of a spectral gamma ray log run after materials used in a hydraulic fracture job were tagged with two isotopes. The foam pad was tagged with scandium-46, and the proppant was tagged with iridium-192. The gamma ray concentrations on the log indicated that each of the three intervals remained isolated. The scandium relative-distance curves indicate that the fracture in each zone extended beyond the perforated intervals, particularly in the upper zone, where the fractures propagated more than 50 ft above the perforations. However, the iridium relative-distance curve

Chapter 3

Logging Services Many logging services are available for detecting and predicting potential conformance problems. The following primary logging systems are available: • Openhole logs • Cement evaluation logs • Casing evaluation logs • Pulsed neutron logs • Production logs Table 3.3 (Page 3-12) provides a general overview of how each of the logging types can be used for conformance control.

Openhole Logs Openhole logs allow analysts to determine the possible causes or contributors to unwanted water or gas production. Caliper logs reveal severe borehole washout areas that can contribute to poor cement bonding. Gamma ray and SP logs can help delineate shale beds from possible water- or hydrocarbon-producing reservoirs. When they are combined, resistivity and porosity logs (sonic, density, and neutron) can help analysts determine water and pay zones. These zones can later be compared to cased-hole logs, allowing analysts to monitor changing water levels of coning in producing reservoirs. Figure 3.5 (Page 3-13) is an example of a typical openhole logging suite. Figure 3.6 (Page 3-14) is a computer-processed interpretation that provides information on the potential of the various reservoirs. Most openhole logging tools have an outside diameter (OD) of 3 5/8 in. and are rated to 400°F and 20,000 psi. Hostile-environment (small borehole-diameter and hightemperature or high-pressure) tools are also available for more difficult applications.

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Figure 3.3—FracPressure analysis log.

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HN01224

Figure 3.4—TracerScan analysis.

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Table 3.3—Areas of Application for Well Logs Problems Acid job went to water Bottomwater coning

Openhole Logs

Cement Evaluation Logs

Casing Evaluation Logs

Production Logs

X

X

X X

Bottomwater shutoff

X

Casing leaks Channel behind casing

Pulsed Neutron Logs

X X

X

X

X

Channel from injector Early water breakthrough Frac job went to water

X

High-permeability streak

X

X

X

No shale barrier

X

X

X

X

X

X

Plugging well Injection out of zone Lost circulation

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Figure 3.5—Typical openhole logging suite.

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Figure 3.6—Computer-processed interpretation of openhole log.

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Nuclear Magnetic Resonance

•

Intensive research and development has led to successful downhole porosity measurements employing pulsed Nuclear Magnetic Resonance (NMR) technology. NMR hardware, as well as interpretation methods, have been improved significantly. Currently, log analysts can use powerful NMR interpretation methods for estimating bound and free fluids, and for direct hydrocarbon-typing, including gas detection. NMR technology can help analysts determine petrophysical parameters that cannot be obtained from traditional logging methods. The MRIL tools can provide the following information: • • •

A lithology-independent porosity Formation permeability Free and bound water volumes and saturations (Sw-Swirr) • Hydrocarbon detection • Hydrocarbon typing • Grain-size sorting and identification of reservoir heterogenities • Linkage to clay type Unlike the neutron/density combination, which is sensitive to hydrogen bound in the formation and in fluids, NMR measurements are sensitive only to hydrogen in fluids. Thus, NMR measures the amount of bound and free fluid in a tool-dependent rock volume (the “sensitive volume”). Combining the advantages of NMR with new interpretation software allows conformance evaluation, design, and placement improvements. This process, called StiMRIL, is a total analysis of the reservoir, consisting of production data, reservoir history, and other analytical tools to achieve a high degree of reservoir and fluid knowledge. Figure 3.7 (Page 3-16) is a StiMRIL flow presentation. Within the depth track on the left side of the log are pay flags and the numbers assigned to the selected zones, as determined by the zoning process. The red lines across all the tracks delineate the zones that were chosen based on NMR permeability (MPERM). The tracks contain the following information: • •

Track 3 presents the variable density image of the T2 distribution generated from echo trains acquired with long polarization time. • Track 4 contains the NMR analysis, which includes effective porosity, bound water, movable water, and hydrocarbons. • Track 5 presents permeability calculated from NMR measurements. • Track 6 provides five different flow calculations to help operators determine the economic potential of each zone. The inflow analysis is based on classic reservoir engineering principles and includes a variety of inputs such as estimates of fracture halflength, skin, flowing sandface pressure drop, etc. Track 6 also displays two normalized curves that help operators interpret zones of interest: permeability feet (NKH) and porosity feet (NPORH). Both are normalized from 0 to 1 over the entire well. These curves provide a comparison of porosity and permeability in each zone and can be used in pipe-setting economics. Visual analysis of the log based on the pay flags and on the NMR analysis reveals that Zones 4, 6, and 8 could be candidates for completion and possible stimulation. These three sands seem to exhibit comparable properties based on the log display. Without StiMRIL information, all three zones would likely be completed and fractured together with standard production-enhancement procedures. An inflow profile for each zone is calculated based on reservoir pressure information and NMR permeability. The family of flow potentials presented is based on ideal infinite fracture conductivity half-lengths. For highpermeability reservoirs and matrix acidizing, the inflow analysis is based on a family of skin values rather than fracture half-length. This idealized inflow analysis is the first step in profit optimization. Combining flow information with treatment costs (consisting of both initial stimulation and possible conformance) is the first step in determining economics.

Track 1 contains gamma ray, caliper, bit size, temperature, and T2 bin information. Track 2 presents the clay-bound-water T2 variabledensity image.

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Figure 3.7—StiMRIL presentation showing flow estimates and zoning based on permeability.

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Cement Evaluation Logs The primary reason for cementing casing into a wellbore is to achieve hydraulic isolation between formations. Often, unwanted fluids can flow into the casing because of improper cementing procedures, bad borehole conditions, well age, or workover operations. Cement bond logs (CBLs) help analysts determine the current condition of the cement annulus and diagnose potential fluid-flow paths. Cement evaluation logs are produced by conventional CBL tools or ultrasonic bonding tools. Most of these tools have a 3 5/8-in. OD and are rated for at least 350°F and 20,000 psi. A few of the tools are available in 1 11/16-in. diameters for through-tubing applications.

Conventional Bond-Logging Tools Conventional bond-logging tools have a single acoustic transmitter and two receivers. The receivers are typically spaced approximately 3 ft and 5 ft from the transmitter. The acoustic signals generated during each transmitter pulse travel to the receivers along various paths through the borehole fluid, casing, cement, and formation. The logging system records the waveforms and determines travel times and amplitudes of signals reaching the receivers. The first signal that arrives at the near receiver generally corresponds to the first acoustic signal that traveled from the transmitter, through the borehole fluid, the casing, through the borehole fluid again, and back to the receiver. This signal is often called the pipe arrival. The associated transmitter-to-receiver travel time is recorded on the log as the travel-time curve. In free pipe, the travel-time curve can be used to indicate tool centralization. In a particular size of unbonded casing containing a particular fluid, the travel time should be constant, except when collars are encountered. A varying travel time may indicate that the tool is not centered in the casing; therefore, the signal amplitude measurements may not be accurate. If a sufficient bond exists between the pipe, cement, and formation, formation signals appear in the wave train. These signals traveled through a portion of the formation (and through cement, casing, and borehole fluid) before returning to the receiver. In slow formations, such as sandstones, the acoustic wave travels more slowly through the formation than through the casing. As a result, the first formation signal, or formation arrival, arrives at the receiver after the pipe arrival.

Chapter 3

In fast formations, such as low-porosity limestones and dolomites, the acoustic wave travels more quickly through the formation than through casing. As a result, the formation arrival can occur before pipe arrival. If such circumstances exist, variations in the travel-time curve can correspond to variations in the formation and do not necessarily indicate whether the tool is centered in the borehole. The far receiver indicates the amplitude of the pipe signal. This signal is displayed on the log as the pipe amplitude curve. This receiver records the entire acoustic waveform. Analysts can qualitatively analyze waveform displays to determine if the following conditions exist: • Free pipe • No cement bond to formation • Partial cement bond to formation • Good cement bond to formation Figure 3.8 (Page 3-18) shows conventional bond-log responses to some of those conditions, and the general waveform appearance is illustrated for each of the conditions shown. Free pipe is not firmly bonded to the cement sheath in Figure 3.8a. It vibrates freely with little signal attenuation. Both the pipe amplitude curve and the X-Z display show high-amplitude pipe signals in a free-pipe zone. The alternating dark and light streaks on the X-Z display appear as straight traces. Casing collars appear as “w” patterns. When cement is bonded to the pipe but not the formation, the pipe cannot vibrate freely, and poor acoustic coupling occurs between the cement and the formation. The signal cannot travel effectively from the transmitter, through the formation, and back to the receiver. As a result, the log records low-amplitude pipe and formation signals, which appear on the X-Z display as a lack of well-defined traces. A partial bonding of cement and pipe can result from channels in the cement or from a microannulus between the pipe and cement (Figure 3.8b). This condition is indicated on the X-Z display by pipe and collar signals that are accompanied by strong formation signals. Additionally, the pipe amplitude curve is high. If a microannulus is suspected, the logger can increase the wellhead pressure and relog across the zone of interest. If the X-Z display on the relogged interval indicates a good bond, a microannulus exists. If a good bond does not exist, the cement may contain a channel.

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Figure 3.8—Example log showing (a) free pipe, (b) partially bonded, and (c) fully bonded.

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A strong, identifiable formation signal with no pipe signal suggests effective zone isolation and a good bond between both the cement and the pipe and the cement and the formation (Figure 3.8c). Under these conditions, the pipe amplitude curve should be low. Normal CBL interpretation assumes that changes in pipesignal amplitude are caused by changes in bonding only, but other factors can cause variations in pipe-signal amplitude. If they are not recognized, bonding conditions could be misinterpreted. These factors include changes in the following: • Pipe diameter, weight, and thickness • Borehole fluid density • Cement thickness and compressive strength • Transmitter signal strength • Receiver sensitivity Several of these factors can be eliminated. For example, the depths where pipe-size changes exist are usually known. For cement-sheath thicknesses greater than 3/4 in., changes in cement thickness have little effect on signal attenuation.

Ultrasonic Bond-Logging Tools Conventional bond-logging tools are generally omnidirectional. The acoustic signals that their transmitters generate travel away from the tool in all directions, and their receivers are sensitive to acoustic waves arriving from all directions. At a particular instant, the signal amplitude at a receiver is the result of all the acoustic signals arriving at the receiver. As a result, the bond quality determined from these tools is a circumferential average of the bonding around the casing. These two cases are difficult to distinguish because circumferentially averaged amplitude and attenuation can be the same for high-strength cement containing a channel and for evenly distributed low-strength cement. For annular cement to attenuate the signal, a good shear mechanical bond must exist between the cement and the casing outer wall. If a gap exists, such as a microannulus between cement and casing, the log can indicate poor bonding even if the gap is so thin that it prevents fluids from flowing. Ultrasonic tools provide the most beneficial data when evaluating cement placement and bonding. Instead of a separate source and receiver, the ultrasonic source and receiver are packaged together as a transducer. Early

Chapter 3

ultrasonic tools consisted of eight ultrasonic transducers in a helical array. The new generation of these tools consists of one rotating transducer. The ultrasonic scanning or imaging acoustic tool uses a single rotating ultrasonic transducer to produce high-resolution, circumferential data. The Circumferential Acoustic Scanning Tool (CAST-V) acquires data for both cement evaluation and casing evaluation in the same run or pass. The rotating transducer can provide 36 to 200 measurements per depth sample, depending upon the service company. Depth-sample rates range from 2 to 12 samples per foot, again depending upon the service company. Not only can channels in cement be detected, but the orientations of the channels can be determined and the proper squeeze or remedial action can be performed. Because of the high horizontal sample rate, the data are normally presented in a color-coded image instead of a single curve. The color coding is based on the impedances of gas, water, and cement. To overcome the limitations of conventional bond logging tools, Halliburton originally developed the ultrasonic Pulse Echo Tool (PET) and the newer CAST-V. PETs contain eight ultrasonic transducers equally spaced in a helical pattern around the main tool body. For ultrasonic tools, each transducer generates an acoustic wave that travels toward the casing, perpendicular to the casing wall. Most of the energy arriving at the inner wall reflects back and forth within the casing, allowing casing thickness to be more easily determined. Some energy is transferred outside the casing at each reflection, so the amplitude of the reflected wave is reduced at each reflection. For a casing of a specified size and weight containing a specified fluid, the rate at which the amplitude decreases depends on the acoustic impedance of the annular material. The fixed 8-transducer PET and the rotating CAST-V measure borehole fluid velocity with an additional transducer. The distance from each transducer to the casing wall can be determined from combining this information with the two-way travel time from the transducers to the casing inner wall. This will be discussed with more detail in the casing inspection section. The acoustic impedance of a material is the product of its density and acoustic compressional velocity. The train of reflected waves returning to the transducer provides information about the annular material, which allows analysts to distinguish cement, liquid, and gas in the annular space.

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The output frequency of the ultrasonic tool ranges from approximately 300 to 600 kHz. However, in the region of a gas-filled microannulus (or in cement containing gas bubbles), the ultrasonic bond log may indicate free pipe. The preferred cement evaluation program combines the CBL and the CAST-V tools. As illustrated in Figure 3.9, the combined data from both logs provides a more complete and reliable evaluation. The tracks provide the following information: Track 1 provides correlation data, average impedance, and tool centralization information.

•

Track 2 provides information from both the CBL (amplitude curves) and CAST-V (FCBI) about the cement to pipe bond. High-amplitude readings indicate free pipe while low amplitude readings indicate good bonding. The FCBI curve is generated from the impedance map and is a method to show the percent of cement to casing bond. Track 3 consists of the CBL waveform, which indicates both the cement-to-pipe bond and cement-to-formation bond. In fact the CBL tool is the only tool available to help determine the cement-to-formation bond.

DN001119

•

•

Figure 3.9—Standard CAST-V/CBL presentation showing a channel.

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•

Track 4 presents the standard impedance image from the CAST-V, which is corrected to the low side of the hole. This information will help determine if the cement problem is correctable or not due to pipe position in the wellbore. The channel on the impedance image indicates less than perfect zonal isolation. Depending upon the reservoir, the cement may not provide the necessary zonal isolation to prevent unwanted fluid production. Figure 3.10 examines the same zone of Figure 3.9. The tracks provide the following information:

•

Track 1 provides correlation data, average impedance, and tool centralization information.

Track 2 consists of the standard impedance image from the CAST-V. Tracks 3 through 11 are the segmented curves from the impedance map. The impedance map is broken into nine segments, and five equally spaced curves from each segment are plotted. Because the map is oriented to the low side of the hole, Segment E will always be on the low side, while Segments A and I will be on the high side. This curve segmentation allows the actual impedance from each curve to be shown and provides a measure of the activity level of the data. The channel is clearly identified on both the impedance map and the segmented curves. The impedance of the material in the channel is about 1.7, which indicates water.

DN001120

•

•

Figure 3.10—Segmented presentation with the impedance map showing the activity level and impedance values.

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This activity level, called the statistical variation process (SVP), allows analysts to discern solid crystalline structures, such as cements, from fluids. Solid-free liquids have a consistent or steady activity level on logs while solids, when mixed with either fluid or gas, have an irregular activity level. Cement, with a mixture of solids, liquids, or gases, should exhibit a high degree of variability in the impedance measurement. A consistent phase, such as water, gas, or drilling mud, will exhibit less variation in the computed impedance. After tool position is taken into account, analysis of the vertical rate of impedance change can easily determine whether foamed cement or liquid is present.

•

•

•

SVP processing assumes that cements are not consistent, but it does not use the impedance values directly in determining if the material is solid or liquid. Combining the SVP processing methods with the original impedance data provides an easier method for determining the pipe-tocement bond. Because liquids should have both low impedance and low activity level, this information can help determine if the annular material is solid or liquid. This new image combines the original impedance data with the variance data to create a new image called cement. Adapting this technique to the CBL waveform data highlighted information not currently being used in the evaluation of cement bonding. The essential portions of this interpretation are collar response and the waveform amplitudes and behavior in free, bonded, partially bonded, and microannulus situations. Subtle changes in the CBL waveform can be seen by the naked eye. Such changes would be lost when presented in the conventional MSG display. Applying the SVP processing to the entire acoustical waveform and determining the variance between vertical sample points makes these subtle changes recognizable. Normally the variance processing results are added to the standard CBL waveform, highlighting both the high-amplitude portion of the CBL waveform and the differences.

• •

This entire process is known as Advanced Cement Evaluation (ACE). ACE can expand cement evaluation for any service company and tools, including segmented bond logs and other ultrasonic tools, stationary or rotational.

• • •

Figure 3.11 (Page 3-23) illustrates a complete new analysis of both the CBL and ultrasonic data over the same well as Figures 3.8 to 3.10. The tracks provide the following information: •

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Track 2 provides information from both the CBL (amplitude curves) and CAST-V (ZP BI, CEMENT BI) about the cement-to-pipe bond. ZP BI is the normal bond index from the impedance map without any further processing. CEMENT BI is the bond index from the cement image. These curves should track the amplitude curve from the CBL because both measurements are an indication of cement-to-pipe bond. Track 3 consists of the CBL waveform, which indicates both the cement-to-pipe bond and cement-to-formation bond. In Track 4, the CBL variance shows the difference between vertical samples of the acoustic wave form. The initial vertical distance between the two sides of the wedge is about five feet, the same as the distance between the CBL source and receiver. As the pipe-to-cement bond increases, the ends of this wedge narrow and approach five feet. As the quality of the cement bond increases, the collar response disappears almost entirely. The colors change as the bond increases from the top to the bottom of the log. Track 5 presents the standard impedance image. Track 6 consists of the cement image, which is determined from the impedance and variance calculation. The channel is still present and probably will not allow zonal isolation over the interval.

Casing Evaluation Logs Many water-entry problems are caused by poor mechanical integrity of the casing. Holes caused by corrosion or wear and splits caused by flaws, excessive pressure, or formation deformation can allow unwanted reservoir fluids to enter the casing. Halliburton uses the following mechanical, electromagnetic, and ultrasonic logging tools to inspect casing:

•

Multi-Arm Caliper tool Casing Inspection tool (CIT) Pipe Inspection tool (PIT) using Flux Leakage/ Eddy Current (FL/EC) Circumferential Acoustic Scanning tool (CAST)

•

Pulse Echo tool (PET)

Track 1 provides correlation data, average impedance, and tool centralization information.

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DN001121

Figure 3.11—New analysis of both the CBL and ultrasonic data over the same well as Figures 3.8 to 3.10.

Mechanical Logging Devices Mechanical devices use independent, spring-loaded feeler arms or fingers to measure the internal radius of the casing. The number of arms can vary from 15 to 80, depending on casing size and tool type. Mechanical calipers only provide information about internal casing condition. Their major deficiency is that they inspect only a small circumferential fraction of the casing. The size of this fraction depends on the number of feeler arms, the width of the arms, and the casing size and weight. For example, a tool with 40 arms inspecting a 7-in., 35-lb/ft casing (6.004-in. ID) would cover only 17.0% of the wall

Chapter 3

(using a feeler width of 0.08 in.). In a 5.5-in., 17-lb/ft casing, the fractional wall coverage is approximately 21.0%. As a result, locating small holes or splits with a mechanical caliper requires multiple passes with the tool. The logs produced by most mechanical calipers present minimum diameter (MINID), maximum diameter (MAXID), and remaining wall thickness (REMWAL) curves, as shown in Figure 3.12 (Page 3-24). To compute the remaining wall thickness, analysts subtract the measured internal radius of the casing from the casing nominal outside radius.

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0

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Figure 3.12—Multi-Arm Caliper log for casing inspection.

Electromagnetic Phase-Shift Devices Electromagnetic phase-shift devices measure the attenuation and phase shift of a transmitted electromagnetic signal to determine circumferential averages of casing thickness and diameter. Casing Inspection Tool The Casing Inspection Tool (CIT) is an electromagnetic phase-shift device. The CIT casing-thickness measurement is made by the transmitter and the near receiver on a one-transmitter, two-receiver coil array. A 30-Hz pulsed electromagnetic field from the transmitter induces eddy currents in the casing. The eddy currents generate an electromagnetic field that is sensed by the near receiver. Analysts can determine the casing thickness by examining the phase shift between the transmitter and near-receiver signals. On the standard raw-data CIT the resulting curve is designated as the thickness index. The measurement has a vertical resolution of approximately 18 in. Because this measurement is omnidirectional and has a somewhat coarse resolution, it cannot clearly detect small anomalies. A second phase-shift is measured between the near and far receivers. This measurement detects casing anomalies over a short length of the casing. It has a vertical resolution of about 2.5 in., and the associated curve on the CIT log is designated as the differential index. On this curve, a large deflection to the right followed by a large deflection to the left indicates an increase in metal. A large

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deflection to the left followed by a large deflection to the right indicates a decrease in metal. The CIT also measures casing ID, but with a coil array that consists of one transmitter and one receiver. The transmitter coil is driven by a continuous 30-kHz source. The resulting electromagnetic field induces eddy currents on the inside surface of the casing. The eddy currents, in turn, generate an electromagnetic field that the receiver coil detects. The phase shift between the transmitted and received signals is a function of the casing’s ID. This measurement is presented on the log as the caliper index curve. One limitation of the CIT is that it cannot clearly distinguish perforations because perforation diameters are significantly smaller than the measurement’s vertical resolution. If perforation diameters are small and shot densities are low, the volume of metal over a perforated section of casing is not much different from the volume of metal over an unperforated section. Therefore, the differential readings are small, and perforations are difficult to identify. The CIT can, however, distinguish intervals perforated at high shot densities. The Multifrequency Electromagnetic Tool The Multifrequency Electromagnetic Tool (METG) is used to gauge casing thickness for detection of defective or damaged casing. This multi-frequency electromagnetic tool measures the casing’s magnetic properties, casing ID, and phase shift to accurately compute the casing thickness.

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The METG detects oilwell casing flaws, such as corrosion, casing wear, mill defects, burst pipe, erosion, and crushing. A noncontact, nondestructive, electromagnetic remote eddy current technique is used for determining areas of metal loss, such as large-scale corrosion, holes larger than 2 in., and vertical casing splits. The METG is currently the only method for detecting casing flaws on the outer strings of multiple-string casings.

Figure 3.13 compares the result from the METG with that of the CAST-V. The following information is provided:

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Track 1 consists of the gamma, eccentricity, and ovality.

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Track 2 consists of two calibrated ID (CIDL, CIDS) curves from the METG and average ID from the CAST-V.

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Electrical caliper measurements are commonly used to determine the inner diameter of the innermost casing in the string. These measurements help determine whether damage to the casing is on the inside or outside of the pipe, and its electrical properties. This caliper measurement is not affected by nonmagnetic mineral-scale buildup.

Typically, the METG tools are designed to be run in combination with other casing-inspection tools. With through-wiring, other tools, such as PIT or CAST-V, can be run in combination with the METG. This combination can provide qualitative information concerning casing integrity.

Figure 3.13—METG results compared to the CAST-V in the pipe-inspection mode.

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•

Track 3 consists of the ID from CASE and shows some internal wear.

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Track 4 compares two thickness curves (TH1L, TH2L) with the average thickness from the CAST-V.

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Track 5 shows the thickness image from the CAST-V.

Track 6 provides thickness information from the two receivers of the METG at two frequencies. Pipe Inspection Tool The PIT is a FL/EC type of tool. FL/EC devices are widely accepted for evaluating metal loss. The PIT provides 360° wall coverage with high vertical resolution by using an array of pad-mounted coils. FL/EC tools identify flaws in casing or tubular goods and then discriminate between flaws on the external or internal surface of the pipe.

•

Flux Leakage. The flux leakage (FL) measurement is made by an induction coil near the pipe surface that is positioned between the north and south poles of a DC electromagnet. Current through the electromagnet causes lines of magnetic flux in the pipe wall. Normally, this flux is contained within the walls of the casing, but when holes, pitting, or other defects exist in the wall of the pipe, perturbations in the flux lines cause some flux to spill out of the confines of the wall. When the inductive sensor is passed over these perturbations, a voltage is generated in the coil. The FL coil responds to holes and inner and outer wall defects.

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Eddy Current. An eddy current (EC) excitation coil is driven by an AC source. The sensor is designed so that in clean pipe, any signal induced into one receiver coil is canceled by an equal signal in the other receiver coil. Several factors control the depth that the current travels into the pipe wall, although current frequency is the primary factor. Normally, the depth of penetration is very shallow. When the PIT tool passes a defect on the inner wall, the receiver coils become imbalanced, first in one direction, then the other. In this manner, a characteristic signature is produced for the defect on the inner wall, but no response occurs for flaws on the outer wall or internal flaws beyond the skin depth of penetration of the excitation current. By comparing the response of the FL and EC signals, analysts can determine whether the defect is on the outer wall only, the inner wall only, or is a through-hole defect. FL curves can reveal holes with diameters as small as 0.1 in. The EC measurements detect defects

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with diameters as small as 0.125 in. To help analysts visualize the pipe condition, FL/EC logs provide plots of the raw FL/EC curves from each pad as well as detailed 360° maps of the flux leakage and eddy current. The PIT tool and associated software allow identification of casing damage. Once a defect is located, the type, size, and percent of penetration are shown in Figure 3.14 (Page 3-27). The PIT processing algorithm allows the standard joint counter and grading programs to be used. The tracks provide the following information:

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Track 1 provides the gamma, tension, and hall effect, which indicates casing damage and/or quality control.

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Track 2 provides the processed eddy curves that are plotted on the same scale range with a different offset.

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Track 3 provides the processed flux curves that are plotted on the same scale range with a different offset.

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Tracks 4 and 5 indicate whether the defects are on the inside or outside of the casing. The extent to which the defects penetrate the casing (as a fraction of casing thickness) determines the grade as shown. Casing grade is determined by defect penetration (again, as a fraction of casing thickness).

•

Track 6, the rightmost track on the log, flags casing defects and identifies each defect as either isolated or circumferential. The log example shown in Figure 3.14 is from a well without cement allowing pipe recovery. The pipe was retrieved and examined showing a hole at 93 meters. The pipe was photographed as shown in Figure 3.15a (Page 3-27). The high sampling rate and full pipe coverage of the PIT allows accurate 3D images to be generated as shown in Figure 3.15b. The two images have an excellent match showing the casing damage. The hole was determined to be approximately 1/8 of an inch across.

Ultrasonic Casing Tools Two types of ultrasonic tools are commonly used for casing inspection: (1) the Circumferential Acoustic Scanning Tool (CAST) and (2) the Pulse Echo Tool (PET). Circumferential Acoustic Scanning Tool The CAST has a rotating ultrasonic transducer that can accurately measure casing ID, casing thickness, casing ovality, and tool centralization. When the transducer is pulsed or fired in the “transmit” mode, a narrow acoustic beam propagates through borehole fluids toward the

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Figure 3.14—Casing damage on the outside at 93 meters.

Figure 3.15—Video capture of the pipe in Figure 3.11 with 3D image of the casing damage using PIT data.

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borehole wall. This beam reflects off the borehole wall and travels back through the borehole fluids to the transducer. The transducer then acts as a receiver to record the travel time and amplitude of the reflected signal. The travel time (or time of flight) is the elapsed time between the transducer’s firing and the instant when the highest amount of reflected energy arrives back at the transducer. Amplitude is a measure of that peak amount of returning ultrasonic energy.

Because the resonant frequency of casing decreases as casing thickness increases, transducer frequency must be selected according to casing thickness. Further waveform processing provides information about the material in the annular space between the casing and the wellbore wall. This annular space is normally filled with cement, drilling mud, water, gas, and other substances. The ultrasonic tools determine the impedance value of these materials and indicate the amount of pipe-to-cement bonding.

The CAST-V operates in either image mode or cased-hole mode. In image mode, the tool acquires data from the interior diameter of the pipe or formation. In cased-hole mode, data is acquired from the casing ID, the casing thickness, and the annular space between the casing OD and surrounding formation. Both the amplitude and travel-time data from both modes may be used to help determine the conditions of the casing or riser. The navigational package is required to provide geometry of the casing or hole. This will allow casing wear to be monitored accurately.

Waveform processing achieves cement evaluation and casing inspection at the same time, without requiring additional passes. Thus, high telemetry data rates, intense processing capabilities, and selective transducer frequencies are required. Before deciding to log with a CAST, engineers must consider the wellbore fluid and the casing wall condition. If the wellbore fluid contains large quantities of solids, the solids attenuate and disperse the transmitted and reflected signals. If the casing wall contains scale, paraffin, or other disruptive materials, the reflected signal can be significantly attenuated and scattered, and the data will be useless.

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Image Mode. In image mode, the scanner evaluates only the “inner” surface of the target (the formation bounding the wellbore or the inner wall of the casing). The high vertical resolution (60 samples per ft), and extensive azimuthal sampling (200 shots or radial measurements per sample depth) provide the necessary information needed for 2D and 3D images. The travel time and amplitude of the acoustic waveform can provide both visual and digital data to indicate casing integrity or problems. These images are useful for evaluating casing integrity by revealing distortion, wear, holes, parting, and other anomalies on the inner wall of the casing.

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Cased-Hole Mode. The ultrasonic scanner also operates in cased-hole mode for a thorough casing assessment including wall thickness or pipe-tocement evaluation. The cased-hole mode determines both the internal radii of the casing and the casing thickness. Casing thickness combined with the ID measurements can be used to indicate defects on the exterior of the casing. The normal tool operation will provide a vertical resolution of four samples per ft, and azimuthal sampling of 100 shots per sample depth. This data can be recorded at 12 samples per ft, but the logging speed needs to be reduced. The amplitude and travel times are also recorded to provide image-interpretation capabilities. The acoustic waveform is processed in cased-hole mode. Casing thickness is calculated by a Fast-Fourier transformation of the frequency content of the waveform itself.

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Another major consideration in CAST logging is the distance from the transducer head to the casing’s inner wall. If the transducer head is too close to the wall, a near-field phenomenon causes the data to be difficult to interpret. Under these conditions, the acoustic wave is unable to travel a sufficient distance from the transducer to produce a wave front that is planar when it impacts the casing wall. This planar condition is necessary for good data. If the distance is too great, the acoustic amplitude of the received signal is greatly reduced. Therefore, the proper transducer head size must be used to ensure optimal standoff distance. After the data is acquired in either mode to accurately evaluate the internal casing wear, tool position and eccentering need to be accounted for. Spiral or patterns similar to a barbershop pole are indications of eccentricity problems, not necessarily casing wear. Special processing, provided both real time and post acquisition, allows the travel time image to be corrected for the tool eccentering. After the raw data is corrected, several different programs will allow complete interpretation of the data to completely evaluate the casing damage. Figures 3.16 to 3.18 (Pages 3-29 through 3-30) provide detailed information about packer damage on 7-in., 26-lb/ft casing. These figures range from the raw data to 3D images. Figure 3.16 shows where the packer was set and did not release properly (B). The metal was peeled up when the packer

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Figure 3.16—Raw data from the image mode, allowing easy visualization of the casing damage.

Figure 3.17—Computed results showing casing radius for the packer damage.

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Figure 3.18—Raw data along with three-dimensional image show casing damage.

was pulled. The amplitude and both the travel time images in Figure 3.16 show the channels of the packer pins. They also show that peeled metal is still in the casing immediately above the damage (C).

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Track 3 is the amplitude of the first arrival in the image mode. This will show the greatest detail concerning any casing damage; Howeve,r the data cannot be used in any further quantitative evaluation.

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Track 1 provides tool and casing eccentricity and ovality data

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Track 2 provides information about the travel time of the fluid in the casing along with wellbore deviation

Track 4 is the uncorrected travel time for tool eccentricity. This travel time will be used along with the fluid travel time to determine the casing radius.

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Track 5 is the corrected travel time for tool eccentricity. The post-processing software will correct the data for slight eccentricity errors.

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The computed results of Figure 3.17 show the amount of metal removed to be approximately equal to the metal remaining above the damage. The indicated damage at (D) is circumferential and seems to have been caused by the packer compressing against the casing wall. The segmented presentation in Figure 3.17 provides a detailed analysis of the casing damage. The maximum depth of the two grooved pits is about 0.125 in. deep (Segments B, G, and H). In the nondamaged area, the average, minimum and maximum radius curves all indicate the known casing radius.

different times, the casing is oval. If all eight transit times are different, the tool is eccentered.

Figure 3.18 uses a standard imaging package to display the calculated pipe radius in a 3D view. While these images correlate well with both the calculated and raw data, it is difficult to measure actual casing damage with these 3D images. 3D images allow excellent visualization of casing damage and corrosion; However, these images do not provide the necessary, minute detail required for monitoring.

Pulsed Neutron Logs

Pulse Echo Tool Although it is primarily a cement evaluation tool, the Pulse Echo Tool (PET) can also determine casing ID and thickness. The PET has a helical array of eight transducers, each acting as both a transmitter and a receiver, evaluating the adjacent segment of casing. The transducers emit a short pressure pulse with a center frequency close to the resonant frequency of the casing (approximately 400 kHz). When the pulse arrives at the casing, it generates both a large reflected wave and casing resonance waves, all of which are sensed by the transducer, which measures time of flight (t) of the reflected waves and the frequency of the resonance waves. A ninth transducer and a reference reflective surface are mounted in a tool cavity that is exposed to the borehole fluid. To determine the borehole’s acoustic interval transit time (Dtf), analysts must first measure the acoustic signal’s time of flight from the transducer to the reflective surface and back before determining the known distance from the transducer to the reflective surface. The casing ID is derived from t and Dtf, while casing thickness is calculated from resonant-wave frequency.

Figure 3.19 (Page 3-32) is a PET casing profile plot with casing ovality, eccentricity, average thickness, and other standard curves plotted in Track 1. In Track 4, the nominal thickness of the casing is displayed as the distance between two adjacent vertical gridlines. The actual thickness that each transducer measures is plotted as a solid black trace inset between the nominal-thickness grid lines. Each transducer curve is plotted next to its opposing transducer.

Two types of pulsed neutron logs are available: (1) pulsed neutron capture (PNC) logs, which are usually run in areas with high-salinity formation waters, and (2) pulsed neutron spectrometry (PNS) logs, which are usually run in waters in which the salinity is low or unknown. These cased-hole logs can sometimes be used in openhole applications. When these logs are combined with either openhole or earlier pulsed neutron logs, changes in water level or coning can be evaluated. Pulsed neutron tools can detect and quantify water flowing past the tool during logging. When water moves past the generator, oxygen is activated by the high-energy neutrons and forms a radioactive isotope of nitrogen. This isotope is unstable and decays with a 7.35-second halflife. As water flows past the logging tool, the tool’s detectors register the gamma rays emitted during the decay. This technique detects (1) channels outside the casing, (2) leaking tubulars, and (3) water production, particularly in highly deviated wells. Thermal Multigate Decay Logs The Thermal Multigate Decay (TMD) log is Halliburton’s PNC log. The TMD is a dual-detector tool that can help detect water flow by identifying increased background count rates on the quality log. To quantify flow rates, the logging service makes several passes with the tool over the flowing interval. Analysts can then determine flow rates by noting the depth changes where the activation appears on the background curves. TMD tools have a 1 11/16-in. OD and are rated for at least 300°F and 15,000 psi.

To determine casing ovality and tool eccentralization, analysts compare the interval transit times of each transducer. If diagonally opposing pairs of transducers have the same transit time and adjacent pairs have

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Figure 3.19—Ultrasonic pulse echo log used for casing inspection.

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Pulsed Spectral Gamma Logs The Pulsed Spectral Gamma (PSG) log is a PNS logging device. The single-detector PSG tool detects water by measuring the activated oxygen in a spectral window placed around the main oxygen peak in the capture gamma ray spectrum. Because of its single-detector design, only qualitative interpretation is available. If water is flowing past the tool, the log registers an increase in the count rate of the oxygen-activation curve. PSG tools usually have a 3 3/8-in. OD and are rated for at least 300°F and 15,000 psi.

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The example TMD log in Figures 3.20 and 3.21 (Pages 3-33 and 3-34) is from a well involved in a loginject-log project that determines the residual oil saturation in a reservoir before a waterflood. The log was run during the early injections of brine. The LS-BKG curve increases significantly on the quality log above the packer at X490 ft. This background increase (together with an absence of high natural gamma activity) indicates water flowing upward in the casing-tubing annulus because of a leak in the packer assembly. The increased LS-BKG response from X640 ft to X625 ft indicates a channel outside the casing. The count rates are much lower and more variable for channels than for flow inside the casing because of the smaller, more variable volume.

Figure 3.20—TMD log showing water movement from packer leak and a channel outside pipe.

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Figure 3.21—PSG log showing oil/water contact and leaking squeezed perforations.

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The example PSG log in Figure 3.22 (Page 3-36) is from a well that analysts logged to monitor reservoir depletion by comparing open- and cased-hole saturation interpretations. The oxygen-activation curves (OAI) from the field log were placed on the computing center analysis in Track 1 to aid in the interpretation. The activation increases at each of the two bottom sets of perforations, X400 to X408 ft and X352 to X356 ft. The activation returns to near-zero at the top perforations at X326 to X332 ft. These activation increases indicate water flowing upward past the logging tool and entering the upper set of perforations because of reservoir pressure differentials.

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Provide porosity information within the completion interval

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Evaluate gravel-packs and lithology with silicon activation

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Detect water flow inside or outside the pipe

Because the RMT Elite can accurately evaluate the timelapse performance of hydrocarbon producing reservoirs without requiring tubing to be pulled from the well, operators can do the following:

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Increase production more cost effectively

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Avoid production problems through enhanced diagnostics

Reservoir Monitoring Tool

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Make faster decisions on workovers and completions

New developments in tool electronics detectors have allowed a new through-tubing reservoir monitoring tool (RMT) to assist in the monitoring and management of the production of hydrocarbon reserves. Halliburton’s RMT Elite is a unique through-tubing pulsed neutron logging tool that consists of carbon/oxygen (C/O) system and has two to three times higher measurement resolution than other systems. Its high-density Bismuth Germanium Oxide (BGO) detectors let the RMT Elite achieve resolutions previously available only with larger diameter C/O systems. The tool length is 27.2 feet long with an outer diameter of only 2 1/8 in.

The RMT Elite can also affect the economics of the well intervention and associated costs by reducing or eliminating the following:

The presence of flowing water under shut-in conditions helps explain the overly pessimistic oil-depletion calculations over this interval. The inelastic gamma ray measurements from the PSG log used to calculate oil saturation have a very shallow depth of investigation and were heavily influenced by the flowing water.

The advanced modular design provides a highly versatile system that has multiple operating modes and capabilities, allowing operators to make simultaneous C/O, Sigma, and water flow measurements. Because the system is modular, it can be combined with a complete string of production logging tool sensors for detailed production analysis. RMT Elite allows logging speeds two to five times faster than any competing system. This combination of speed and precision allows the RMT Elite to perform the following functions:

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Accurately determine oil and gas saturations in high salinity or fresh water formations

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Identify bypassed reserves

Tap into bypassed hydrocarbon reserves Optimize, manage, and produce reservoirs more efficiently

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The cost of killing the well

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Potential production losses due to formation damage from well-kill fluids

The cost of pulling tubing out of the well Operational cost and lost production revenue from additional workovers

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The cost of recompleting the well by re-running tubing Figure 3.23 (Page 3-37) is an example of the RMT Elite in a steam flood environment. This example not only shows the remaining oil saturation, and the injected steam saturation, but also indicates where water is moving behind the casing. Remember that conformance is not only the study of unwanted water production but can also include the production of gas or steam:

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The depth track recorded at the far left side of the log displays water flow measured by the RMT Elite outside the casing.

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Track 1 is the openhole density neutron porosity. Steam measured in the formation at the time of the log is indicated by the gray shading between the curves.

Pinpoint formation fluid contacts Identify lithologies and mineralogies

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Monitor changing conditions and fluid movement

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Figure 3.22—PSG log showing water crossflow between reservoirs.

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Figure 3.23—RMT Elite in a steam flood environment showing fluid saturations, bypassed reserves, and fluid movement behind casing.

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•

•

Track 2 displays the inelastic and capture ratios measured from the RMT Elite. The red shading indicates the current location of steam in the reservoir. This example indicates that the steam chest has changed when compared to the original formation contacts. Track 3 displays the Carbon Oxygen and the Calcium Silicon ratio curves. The green shading between the two curves indicates hydrocarbons in the formation. Also displayed in the track are the natural gamma ray measurement and the simultaneous recorded formation sigma.

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Track 4 of the example displays the computed oil saturation (shaded in green) and the gas saturation (shaded in red). These saturations were computed using a combination of C/O and formation Sigma. Spectral Flow (SPFL) The Spectral Flow tool is designed to measure simultaneous up and down water flows. This tool was intended for use with additional production logging tools to accurately determine water entry and movement. The SPFL is a high-energy PNS tool that activates the oxygen in water for a short time, allowing the oxygen to emit gamma rays of specific energy. These gamma rays are sensed and measured by detectors in the tools, and the resulting measurements are used to determine water-flow velocities inside, as well as outside, casing. The SPFL tool uses two spectral gamma ray detectors and a pulsed neutron generator with a special timing sequence designed to emphasize activation measurements. These spectral measurements enhance velocity estimates by allowing gamma rays from oxygen activation to be distinguished from those arising from iron activation, silicon activation, and natural activity. Furthermore, spectral measurements permit analysis of Compton scattering to indicate whether water is flowing inside or outside the casing. The detectors are located far enough from the source that oxygen decay in stationary water, mud, formation or cement is not observed. Oxygen activation measurements clearly identify where the water is moving and at what velocity. This allows the Spectra FlowSM Service to accurately detect and quantify downhole water flow to enhance the planning and improvement of conformance and water management. Updating previous reliable tools and interpretation software allows the SPFL service to achieve the following:

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Accurately identify the water entry points and channels for timely planning of effective remedial action.

Testing Methods and Equipment

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Evaluate downhole flow patterns

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Reduce water disposal costs

Create quality injection profiles that can lead to improved conformance measures

Precise water velocity measurements using spectral data are provided with continuous logs and stationary impulse step-down tests:

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Use of a count-rate ratio from the two spectral gamma detectors, which provides a continuous log but requires well calibrated detectors.

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Use of an impulse/shutdown sequence, which is performed while the tool is stationary and is calibration independent. Logging techniques have been developed that use a combination of continuous and stationary logging measurements. This procedure allows water velocity greater than 3 ft/min to be detected and, depending on the flow volume and location, accurate quantitative velocities as low as 5 ft/min can be measured. For velocities over 50 ft/min, improved accuracy is obtained by using the more distant natural gamma ray detector. The example well for this SPFL was producing almost 2,000 BWPD and 770 BOPD. The results of the stationary impulse tests with the tool in inverted configuration indicated downward water flow in a channel outside the casing. Measurements made with the natural gamma ray detector at the top of the tool showed simultaneous upward water flow inside the casing. Variations in the water-flow velocity from test to test suggest that the cross-sectional area of the channel is not constant. The left side of Figure 3.24 (Page 3-39) shows the plots of the SPFL continuous logs run with the SPFL tool in normal mode; the right part of this figure shows the plots of the continuous logs run with the SPFL tool in inverted mode. The normal-mode logs measured two water-flow entry points at 9,806 ft and 9,720 ft as indicated by the OAI measurements. The CRAT measurements in Track 1of the log indicate the water flow inside the wellbore. The OAI and CRAT measurements obtained in inverted mode indicated water channeling behind pipe starting at 9,642 ft, with most entering the wellbore from perforations at 9,722 ft. The inverted-mode logs also weakly indicate a second channel beginning at 9,736 ft and continuing to the lower set of perforations. The arrows on the CBL-GR plot the combined water-flow measured by the SPFL tool.

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Figure 3.24—SPFL in normal and inverted mode.

In addition to measurements made by the new watervelocity tool, a full set of production logs was recorded on this well. The PL computed analysis is shown in Figure 3.25 (Page 3-40). The analysis indicated that most of the water was being produced by the lower perforations at a rate of 1,880 BWPD and 420 BOPD. The upper perforations showed that fluid was being produced out of the top 8 ft. This zone was only producing 75 BWPD and 350 BOPD.

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Track 7 of the log in Figure 3.22, labeled Velocity, plots the velocity calculated from the PL spinner and the continuous velocity measured by SPFL tool in normal mode. The velocity from the new tool is lower than the velocity from the spinner, which indicates that the oil was flowing faster than the water. As the flow stabilized around 9,760 ft, the two velocities were nearly equal. The velocities differed again with oil entry from the upper set of perforations and stabilized with an equal rate at 9,712 ft.

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Figure 3.25—SPFL with PL analysis.

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In summary for this example, the logs indicated three sources of water. The lower perforations were producing water from the zone and as well as a small amount from a channel in the cement. The upper perforations were producing water from a higher channel.

Production Logging Tools The normal production logging string consists of the following five tools:

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fluid-density tool hydro tool

The fluid-density tool consists of a collimated gamma source and a collimated gamma detector mounted at opposite ends of a sample chamber. The gamma rays emitted by the source are absorbed at a rate proportional to the density of the fluids passing through the sample chamber. The detector counts the gamma rays that are not absorbed. The fluid density is inversely proportional to the number of gamma rays reaching the detector. This tool allows users to determine the density of wellbore fluid, locate zones where fluids are entering the well, locate tubing or casing leaks, determine the depth of contact between different fluids, and determine fluid holdups. Hydro Logs

spinner tool pressure tool temperature tool

Two new tools have been developed by Halliburton and its suppliers to improve the calculation of holdup. Holdup tools normally consist of the fluid density and hydro tools, which are center-sample devices. These centersample devices are adequate when the fluids are well mixed and are flowing in a steady state. Unfortunately, this environment is not usually encountered in horizontal or deviated wells. The Gas Holdup Tool (GHT) and Capacitance Array Tool (CAT) are part of the new generation of fullbore holdup tools. The GHT measures gas holdup in all types of environments, including deviated and horizontal wells. The CAT tool can actually measure all three holdups (gas, oil, and water simultaneously). These new tools are discussed in detail.

The hydro tool is sensitive to the dielectric constant of fluid mixtures in the wellbore, which enables it to detect water and hydrocarbons. The sensor section of the hydro tool consists of two concentric plates. The annular area is designed to minimize effects of fluid flow and its characteristics. As fluids with differing dielectric constants pass through the annular area, the probe capacitance changes, subsequently changing the output frequency of the tool’s oscillator circuit. The response is sensitive to the presence and amount of water in the flowstream because of the considerable difference between the dielectric constants of water (80) and hydrocarbons (2 to 4). The tool allows users to determine hydrocarbon-water ratios, fluid holdups, and fluid entry. Gas Holdup Tool (GHT)

Fluid-Density Logs

The gas holdup tool is a 1 11/16-in. OD production logging tool that measures the volumetric fraction of gas in any cased or screened wellbore. The fullbore measurement is based on the combined effects of back scattering and photoelectric absorption. The GHT employs a low-energy cobalt-57 source and a scintillation detector to measure the gas fraction in the annulus between the tool and the casing. Gamma rays are radiated through the low-energy (titanium) housing, and are backscattered from the fluid in the annulus, then counted by the scintillation detector. The low energy source ensures that the gamma rays are effectively attenuated through photoelectric absorption by the casing, which prevents gamma rays that escape the casing from reentering the cased wellbore and influencing the measurement.

The fluid-density tool continuously measures wellbore fluid densities. Changes in density can indicate either contact of two different fluids or fluid entry into a well. In the latter case, the tool can locate perforations or verify leaks in the casing or tubing.

Because count rates are not directly related to only the density of the fluid, the GHT may not be used as a fluid density tool. In many instances, the GHT may obviate the need for the center-sample radioactive fluid-density tool, because the GHT obtains gas holdup directly.

These 1 11/16-in. tools are rated for 350°F and 15,000 psi. Either individually or in combination with each other, these tools can indicate the presence of water or gas influx. Fluid-density and hydro devices indicate the type and amount of fluid present in the wellbore. Flowmeters indicate both the rate and direction of flow. Temperature and pressure tools provide valuable reservoir parameters for additional analysis. All these measurements can be combined in Halliburton’s production logging analysis (PLA) program, which provides a complete analysis of fluid flow. This analysis consists of both fluid identification and flow rate for the well.

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The conventional center-sample radioactive fluid-density tool employs a cesium-137 source and a Geiger-Mueller counter to measure the attenuation of the gamma rays in the volume between the source and the detector, a measurement that may not be representative of the entire well cross-section. This limitation could lead to measurement inaccuracies, particularly in deviated and horizontal wells, where stratified flows are common. The GHT has a gas holdup accuracy of 3% and a resolution of 1% in two-phase flow, given the pressure and temperature as an input. It has a vertical resolution of approximately 1 ½ in. Another feature of the GHT is its insensitivity to the wellflow regime. The tool makes an accurate gas holdup measurement, regardless of how the gas is mixed with wellbore fluids. For a given fractional volume of gas, approximately the same fraction is measured whether the gas bubbles are floating on top of the liquid phase or are more uniformly mixed. This characteristic makes mixing fluids unnecessary and provides a more accurate measurement independent of the well conditions. This insensitivity to well flow patterns is especially important because exploitation of a reservoir requires recognition of the gas and its entry points. Two holdup devices are required to obtain the information necessary for three-phase flow calculations. The fluid density tool is normally used in conjunction with the capacitance tool to calculate holdups for each phase. The example logs in Figures 3.26 (Page 3-43) and 3.27 (Page 3-44) will show that capacitance tools are inaccurate during high water holdup, which causes shortcircuiting between the measurement plates. The new technique capitalizes on the capability of the gas holdup tool to determine the gas holdup, independent of fluid density. Once the gas holdup is determined, a gas-free fluid density can be calculated, leading to determination of the water and oil holdups. This technique, using GHT and fluid-density sensors only, has been successfully used on several wells throughout the world, providing calculated surface production rates that agree with actual production rates. Below XX900, the raw data log (Figure 3.26, Page 3-43) shows that the hydro (capacitance) tool is short-circuited, and offers only a straight-lined reading. The FDEN shows

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a small degree of activity, while the GHT shows more activity than the other tools. Very little gas production is seen below XX850. Above XX850, the logs show gas and fluid entry in both the raw data log (Figure 3.26) and the computed log (Figure 3.27). The computed analysis log shows that a consistent bubble flow regime is present, composed of oil and water. The temperature deflection at XX840 shows a heating anomaly, indicative of fluid entry, as confirmed by increased spinner rates. The raw data shows that the well has not been stabilized, as indicated at approximately XX840. Here, the curves from each of the three tools (FDEN, HYDRO, and GHTCO) diverge between different passes, showing a different depth for the fluidentry zone with each logging pass. GHT-computed analysis uses PVT correlations to accurately calculate volumes of free gas and solution gas for the total gas flow-rate analysis. The Gas Flow Rates track displays free gas in solid red, while using pink bubbles to show solution gas. Computer analysis emphasizes the difference in interpretation of data gained by center-sample tools versus the fullbore GHT. Gas entry is indicated on the raw data log from XX788 to XX795 by a slight temperature decrease accompanied by increased spinner rate. With typical center-sample tools (fluid density and hydro), the major oil/gas entry point at depth X788 to X795 could easily be misdiagnosed as a major gas/water entry point. The Fluid Density/Hydro analysis indicates an increasing water and gas flow rate at X788, as indicated on the computer analysis (Figure 3.27, Page 3-44) by an increase in the QLIQN curve, which shows the water production rate. However, the Fluid Flow Rates track, which uses GHT and Fluid Density readings, shows a consistent QLIQ (water production rate curve), thereby indicating no water entry. Instead, it actually indicates increased oil production. This example highlights some of the problems faced in conformance work. Conformance treatments may be deemed a failure due to continued fluid production. In reality the problem could be misdiagnosing of the conformance problem and an incorrect solution being applied to the reservoir or well.

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Figure 3.26—PL raw data with GHT. Zones 1,3,5, indicate that the hydro is inactive, due to the high water holdup. Zone 9 shows that all three sensors are now working properly.

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Figure 3.27—Interpretation of the raw data of Figure 3.26. The interpretation on the left uses the GHT/fluid density, and the one on the right uses the hydro/fluid density combination. The hydro/fluid density combo indicates water entry from Zone 8 while the GHT/fluid density combination indicates that the water is entering from Zone 6.

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Capacitance Array Tool and FloImager Applications The Capacitance Array Tool (CAT™) greatly enhances the ability to gather reliable holdup data (gas, oil and water) in highly deviated and horizontal wells. This application is extremely useful in highly deviated and horizontal wells with multiphase flow. Applications for detecting three-phase fluid entry can be performed at any angle. Combined with the FloImager and FloImager3D software packages, this service provides the highest resolution three-phase fluid entry detection and flow image at a broad range of well angles. This is the latest advancement in the production monitoring capabilities that Halliburton provides. Using data from the CAT, FloImager identifies fluid entry and fluid distribution in a borehole cross-section and reliably calculates water holdup in horizontal, highly deviated, and undulated wells. FloImager uses data from the CAT, which consists of an array of 12 micro-capacitance sensors that are radially distributed in the wellbore to accurately measure fluid holdup. Because this holdup measurement is fullbore, tool position does not affect the readings in horizontal wells as compared to a center-sample device. The arms are retracted going downhole, then extended when logging up, and the process is repeated as often as necessary. Readings are taken with the tool stationary at any depth or with continuous up-logs. It can be run in combination with Reservoir Monitoring tools and other conventional production logging sensors. FloImager improves interpretation of the flow patterns in all wells due to the increased number of sensors at the same depth. Since the relative position of the CAT is known at all times, the images and logs are corrected to the high side of the hole, allowing accurate holdups to be determined.

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FloImager can obtain fluid-phase distribution maps from 12 sensors in a cross section and enable quality and speedy decision making. A multitude of applications exist for the FloImager and FloImager3D. In addition to measuring fluid holdup, the FloImager can be used to detect water entry and its orientation relative to high side of pipe at any well deviation. FloImager can successfully show three-phase fluid segregation since each fluid has its own log response. FloImager provides an accurate visualization of the undulating horizontal wellbore when TVD data is combined with the CAT data. Combining the calculated fluid holdup with additional PL sensors allow an accurate and complete three-phase analysis. Figure 3.28 (Page 3-46) is an example log of the CAT data and FloImager software. This well is a horizontal well that produces approximately 30 Mscf/day gas, 300 STB/day oil and 12 bbl/day water.

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Track 1 provides correlation data gamma ray (GR), pressure (P), temperature (T), spinner rate (SR), cable speed (CS), and relative bearing (RB).

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Track 2 is the horizontal image generated in FloImager. This image is corrected for relative bearing so that the high side of the hole is on the left and right while the low side is in the middle. The white curve shows the low side or center of the image. The spectrum grades from blue (water), to green (oil) to gas (red), so naturally the lighter phases should be on the upper side of the wellbore.

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Track 3 is holdup data from the three tools run in this well. The fluid density and hydro are center-sample devices while the ACAPN is the average of the 12 sensors from the CAT. Notice how tool position affects the readings especially around X418-X430 and X454-X468.

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Track 4 is the vertical image generated from the FloImager software. Because relative bearing is recorded, determining each sensor position relative to the vertical plane is possible. The image from left to right is going from low side to high side of the hole. The yellow curve is the calculated water holdup while the black curve is the calculated gas holdup. Again, the white line shows the vertical center of the image.

CAT and the FloImager software offer the following benefits:

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FloImager provides more value because it reduces client operating expenses by increasing confidence in well problem diagnostics.

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Excellent wellbore coverage with array of 12 sensors allows superior data and improved flow characterization.

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FloImager provides continuous holdup curves, fluid distribution mapping, and a view of the fluid distribution in cross-section.

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FloImager can obtain reliable holdup measurements and high resolution fluid entry detection, location and orientation in deviated and horizontal wells

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Figure 3.28—FloImager presentation of an horizontal well. This shows the ability of the CAT tool to locate entry points of the wellbore fluids.

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•

Track 5 is the calculated holdup from the FloImager software. This holdup is determined by the vertical position of each sensor and is not just a straight average of the sensor response. FloImager3D allows the user to view, rotate, and manipulate the CAT data to understand the flow patterns and character of the well. FloImager3D allows complete a complete picture or profile of the downhole holdup pattern. FloImager3D allows the user to view, rotate, and manipulate the CAT data to understand the flow patterns and character of the well. Since the sensors are normalized in FloImager, the same color pallet can be used for each sensor providing a precise image. FloImager3D provides a superior technique to both calculating and displaying multiphase holdup.

Flowmeter Logs Continuous, fullbore, and basket flowmeter tools accurately measure velocity and direction of flow in the wellbore. The continuous flowmeter consists of an impeller mounted on sapphire jewels and surrounded by a cage that is mounted on the bottom of the logging tool. The sapphire jewel mountings of the impeller minimize friction, allowing the tool to make accurate low-velocity measurements. The impeller turns at a rate proportional to the speed of the borehole fluid in the center of the pipe. The fullbore flowmeter consists of multibladed spinners that extend in casing to encompass the entire wellbore. This tool is designed for specific casing sizes and must be chosen accordingly. The design allows for fluid-velocity measurement across the entire wellbore and is efficient in both deviated and low-velocity wells. The basket flowmeter is a stationary measurement tool that funnels the wellbore fluids to a small spinner. This tool is designed for deviated wells and segregated flow. The maximum flow rate for this tool is approximately 2,000 B/D.

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Because the CAT records both sensor data and relative bearing, the resultant logs can be corrected to the high side of the hole, allowing accurate visualization of the fluid segregation. However, because this segregation depends upon total fluid flow, each sensor has the capability to measure phase holdups of gas, oil, and water. Both FloImager3D and FloImager have several options to calculate total holdup of the wellbore, allowing the user to determine the best possible solution to this complicated issue. The final holdup then can be used in the PLA programs to help determine both the downhole and surface flow rates for each phase. Although the 3D imaging

capabilities of FloImager are difficult to show in a two dimensional figure, one of the outputs is the cross-sectional display shown in Figure 3.29. This correlates to the depths A425 and B523 shown in Figure 3.25.

Figure 3.29—Cross-sectional display showing depth and holdup calculation from the log in Figure 3.28.

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Pressure Logs Pressure tools continuously measure pressure in the borehole. Two types of tools are available: the straingauge pressure tool (SPT) and the quartz pressure tool (QPT). The SPT uses a strain gauge to measure the downhole pressure, and the tool is designed to minimize the effects of temperature. The QPT uses quartz sensors specifically designed for gas and oil wells. The rugged quartz sensors have high-resolution measuring capabilities. A temperature sensor built into the quartz sensor section accurately compensates for temperature effects. Temperature Logs Temperature logging tools continuously measure temperature in the borehole and can detect liquid or gas movement behind pipe. A highly sensitive resistance thermometer in the tool provides reliable temperature measurements. Since the temperature tool detects changes in borehole temperature, it can locate cement tops and gas-entry points. When it is near curing cement, the tool senses the increased temperature caused by the heat of hydration. At gas-entry points, the tool detects reduced temperatures caused by the gas expanding as it enters the wellbore. Depending on the temperature of fluid entering the wellbore, the tool may be capable of indicating whether the fluid is from the adjacent formation or if it has channeled from above or below. A temperature that is cooler than expected may indicate channeling from a cooler formation, which is normally higher in the wellbore. Similarly, a temperature that is warmer than expected can indicate a channel from below the formation. Temperature abnormalities can also indicate possible flow behind casing or tubing. These abnormalities are highlighted when the temperature gradient is compared to the normal temperature gradient that was observed with the well shutin. Increased temperatures indicate flow from below the formation. Reduced temperatures indicate either flow from above the formation or the presence of gas. Examples Well 1 Well 1 was a gas-production well with high water production. This well was logged with fluid-density, temperature, pressure, and spinner tools that provided information for the production logging analysis (PLA) program.

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The fluid-density log indicates the type of fluid present. Figure 3.30 (Page 3-49) consists of the fluid-density log, a wellbore schematic, and temperature, gamma, and collar logs. Below X077 ft, the fluid density read 1.03 g/cm3, indicating that the wellbore fluid was all water. From X073 to X077 ft, the density decreased to 0.73 g/cm3, which indicated gas production. Between the perforation depths of X055 to X060 ft, the fluid density again decreased from 0.73 g/cm3 to 0.62 g/cm3, suggesting additional gas production. Figure 3.31 (Page 3-50) presents the temperature information in the forms of amplified and differential temperature logs. The amplified temperature log is the temperature log presented with a more sensitive scale that allows analysts to identify minute differences. At X100 ft, the amplified temperature log shows a warming anomaly, which indicates that liquids are entering the wellbore. Temperature decreases indicate gas entry caused by the gas expansion. According to the amplified temperature log, gas is entering the wellbore at X090 and X060 ft. The differential temperature is the difference between two temperature measurements at a set interval. The differential temperature log showed differences in the geothermal gradient, providing an excellent indicator of fluid movement. The differential temperature log indicates a normal geothermal gradient below X105 ft. Between X105 and X091 ft, the log becomes negative, which indicates that liquid is entering the wellbore. At the depth of X090 ft, the differential temperature becomes positive, which suggests the cooling temperatures that indicate gas entry. By overlaying the fluid-density and temperature logs, analysts can determine additional information. For example, in Figure 3.32 (Page 3-51) the density log by itself does not indicate fluid movement at X100 ft. The temperature log, however, indicates water production. Multiple sensors provide additional valuable information for analysts to determine downhole performance. Production logging analysis uses the available data to provide the answers shown in Figure 3.33 (Page 3-52). The fluid density is used to calculate holdup, the area of the pipe occupied by the phase. Below the bottom set of perforations, the wellbore is completely filled with water. Above the top set of perforations, the pipe contains 60% water and 40% gas.

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Figure 3.30—Fluid-density log with a wellbore schematic and temperature, gamma, and collar logs.

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Figure 3.31—Temperature information in the forms of amplified and differential temperature logs.

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Figure 3.32—Combination of fluid-density and temperature logs.

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Figure 3.33—Production log anaylsis (PLA).

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The flow rates at surface conditions show water production of 475 STB/D and gas production of 450 Mscf/D. Further analysis of the data indicates that from X094 and X103 ft, more than 250 STB/D of water is being produced. Therefore, a treatment in this zone would eliminate most of the water without significantly reducing gas production. Well 2 Well 2 was a producing well that had a three-phase flow of gas, oil, and water. For proper analysis, operators ran fluid-density and Hydro tools on the well to calculate fluid holdups. They also used a continuous spinner to determine fluid velocity and temperature and pressure tools to calculate reservoir properties. Fluid-density and hydro tools must both be run when three-phase flow occurs below the bubble point. Figure 3.34 (Page 3-54) shows the data from these tools. Below X700 ft, both holdup tools indicate only water in the wellbore. At X697 ft, the decreased fluid density and the increased hydro count rate indicate hydrocarbons entering the wellbore. Since the fluid-density measurement is 0.62 g/cm3, the hydrocarbons are probably primarily gas. A slight decrease in the hydro count above the top set of perforations at X640 ft indicates that either water or oil is entering from those perforations. Figure 3.35 (Page 3-55) presents the raw spinner data and the cable logging speed. Negative cable speeds indicate that the tool is logging up the hole; positive cable speeds indicate that the tool is logging down. Higher spinner count rates should occur when the tool is logged against flow, as shown in Figure 3.35. Analysts examine data from multiple passes of the tool to calculate fluid velocities, which they use to determine flow rates. By studying the raw data, analysts can determine where fluid is entering the wellbore. Below X721 ft, the spinners show very little change, suggesting that no flow exists. Between X718 and X721 ft, and again between X692 and X698 ft, the large changes in spinner response indicate fluid entry. The other regions show very little change in spinner response, indicating neither production nor loss of fluids. Figure 3.36 (Page 3-56) provides the PLA analysis of the logging data. Again, the holdups are calculated from the fluid-density and hydro data. The data show 100% water below the bottom set of perforations and about 45% water, 15% oil, and 40% gas above the perforations. The flow rates indicate the surface production of each

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phase (2,000 STB/D of water, 500 STB/D of oil, and 900 Mscf/D of gas). Zonal analysis of the well indicates that most of the water comes from the bottom perforated interval, with smaller amounts produced uphole. Gas is being produced primarily from the second perforated interval, while oil is produced almost equally from the upper two zones. Therefore, treatments on the lower zone would likely decrease the amount of water production without adversely affecting hydrocarbon rates.

Downhole Video Services Real-time downhole video services allow analysts to (1) identify wellbore problems, (2) plan reservoir and wellbore treatments, (3) monitor well treatments while in progress, and (4) confirm post-treatment of well conditions. The video images permit viewers to determine exactly where reservoir fluids and particulate matter enter the wellbore. The images also reveal fluid turbulence and flow direction to help viewers identify fluid migration through the wellbore and into thief formations. When used with other reservoir analysis tools, downhole video visually confirms analysis models about reservoir behavior. It can also reveal low-volume fluid entry that conventional well-data acquisition methods may not normally detect.

Application in Oilwell Environments A common misconception is that oil entry into a wellbore causes turbulent fluid mixing, resulting in the formation of opaque emulsions. In reality, at low to moderate flow rates, crude oil generally enters into the wellbore as amorphous bubbles of oil that float through standing water to the water/oil interface. This reaction results in a “lava-lamp” effect, where the fluids remain distinct and separate rather than being mixed in an emulsion. The resulting medium has proven to be very adequate for the use of video; in fact, the possibility of the camera flowing up the well is more likely to constrain the use of video than the degree of fluid emulsification. Video services are also effective in low water-cut oil wells. Sometimes a low water-cut oil well is assumed to have a proportionately low percentage of water in the wellbore. If this assumption were true, video service could be performed in an oil well only after the well was shut in and the target viewing interval was displaced with a clear fluid.

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Figure 3.34—Fluid-density and hydro tool data.

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Figure 3.35—Flowmeter with raw spinner data and cable logging speed.

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Figure 3.36—PLA analysis of logging data.

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Actually, the water-oil ratio in the well can be much greater than the water-oil ratio produced because the oil tends to flow to the surface more readily than water. The oil bubbles travel to the top, where they are produced, while the water ascends more slowly. As a result, a high percentage of water may appear to be standing in the wellbore. This water provides an excellent medium for the video system to monitor the flow activity in the well. Video services have been effective in wells producing as little as 7% water cut.

Detection of Fluid and Particulate Entry Oil can bubble into the wellbore gradually without significantly disrupting the well fluids. As a result, oil entry can be difficult or impossible to detect if the perforation interval cannot be visually observed. If the oil gradually enters the wellbore over a significant length of perforated casing, much of the perforated interval actually producing the oil can be mistakenly assumed to be nonproductive. By monitoring the perforated interval with a downhole video camera, viewers can easily determine where oil is entering the wellbore. In Figure 3.37, oil is identified as black bubbles rising through standing water.

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Gas entry into the wellbore is usually more turbulent. Depending on the velocity and condensate content of the gas, gas entry may appear as a spray of bubbles, a smokelike jet or plume, or waves of distortion in otherwise clear fluid. If the turbulence is strong enough, the fluids can become locally stirred so that any bubbles of oil could mix with the water to cause a semitransparent or opaque emulsion. The emulsion will generally be isolated to the turbulent-flow area. Above the turbulence, the fluids tend to separate.

In localized areas of emulsion, operators can detect fluid entry by observing the motion of particulate matter that is suspended in the fluid. Fluid entry is detected as the particulate matter moves sideways or in circular eddies in response to a sideways flow disturbance. Oil entry into an existing emulsion is more difficult to detect if the oil is bubbling in at a low rate. Although the dark oil bubbles themselves are easy to identify, their source can be more difficult to determine. If the well is shut in for a short time, the emulsion should stratify into components, allowing the targeted viewing interval to clear. Alternatively, well fluids can be displaced to shift clear fluids into the targeted viewing interval. Once clear fluids are established in the target viewing area, the well can be allowed to flow, permitting viewers to observe fluid entry before emulsification occurs. The entry of sand and particulate matter into the wellbore is easily recognizable and helps trace the entry and movement of clear fluids, such as water. Similarly, changes in the movement of falling sand and suspended matter near fluid entry points can signal entry of clear fluids into the wellbore. Viewers can further track the motion of clear fluids in the wellbore by monitoring the motion of flexible members, such as a piece of string fastened in front of the camera. In injection wells, operators can use dyes to locate fluid entry points in the producing wells and to better understand the water migration patterns between the injection and producing wells.

Logging Wells are generally shut in for 24 hours before a video log is run so that any opaque fluids can separate into distinct fluid layers. This shut-in increases the probability of water or clear liquid existing in the interval of most interest. If opaque fluid is located in the interval targeted for viewing, the fluid in the wall may have to be partially displaced with filtered water, brine, production gas, or some other clear fluid to provide a clear viewing medium. Frequently, the opaque fluid layer is above the interval of interest. To begin video logging, operators run the downhole video camera on cable or coiled tubing to the lowest point in the well. If necessary, the well can be brought on at this point as the camera ascends. The entry of fluids and solids can be observed as the camera passes perforations or other fluid entry locations.

Figure 3.37—Downhole video camera picture.

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Depth and temperature displays are superimposed on the video monitor during video operations so that the viewer can correlate the observed well features and conditions to the well tally.

Problem Identification and Remedial Treatment Planning Because so many effective conformance control methods are available, engineers must thoroughly understand the exact nature of fluid entry to determine the target treatment area and select the best treatment. Downhole video services reveal wellbore conditions and help viewers pinpoint locations requiring treatment.

In-Progress Monitoring If the treatment medium is relatively clear and the physical operating limits of the camera and cable are not exceeded, video can successfully monitor well and reservoir treatments. For example, operators could use downhole video cameras during a fracturing job to verify the location of the proppant.

Depth The maximum operating depth for the cable-deployed system is 17,000 ft. This depth can be achieved because the 7/32- or 1/4-in. diameter cable permits the camera assemblies to be run against pressure without the need for weight bars. When it is deployed on coiled tubing, the video system maximum depth depends on the coiled-tubing system depth capability. Coiled tubing deployment provides two advantages over cable: (1) it allows operators to use downhole video services in deviated wells, and (2) operators can pump nitrogen through it to bring on the well during video operations. Regardless of depth, the picture quality remains exceptional because the video images are transmitted through a fiber optic member to the surface. The cable assembly also contains electrical conductor wires to power the camera and lights. Chemical Resistance

After a reservoir or wellbore treatment, a video run can confirm that the treatment accomplished the intended result. By using video to confirm treatment conditions, the viewer can learn more about treatment effectiveness.

The cable armor design is similar to electric conductor line because both are resistant to wear and chemicals. Special polishes with surfactant wetting agents are used on the camera lens and light sources to cause oil bubbles to slide off without leaving an opaque film, and chemicalresistant coatings and treatments for the cable are available for special applications.

Operating Limits

Other Applications

Clear Fluid Medium

In addition to conformance control, downhole video can also be used for the following applications:

Post-Treatment Confirmation

Video service requires a relatively clear fluid medium in the viewing area. Most wells, however, have enough standing water or gas to accommodate video. When opaque fluids, such as crude oil and mud, are displaced, the video camera can clearly show the target areas of the well. Coiled tubing can also be used to displace the local target interval without displacing the entire well. Pressure and Temperature

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Inspecting casing, tubing, and downhole equipment Performing corrosion surveys Detecting fractures and their orientation Verifying well treatments and other service operations Locating and identifying fish Performing well-appraisal analysis

The camera, cable system, and all wetted components are designed for operation at 10,000 psi and 225°F. Video logging has been successfully performed at temperatures greater than 250°F, although the picture quality was compromised. All components exposed to well temperatures can withstand temperatures over 250°F without permanent damage.

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Conclusions The examples of logging tools and computer software show how conformance problems can be properly diagnosed. Conformance treatments not properly chosen for the well or reservoir conditions fail. Correct interpretation of the downhole environment can remove errors in the treatment of the conformance problem. In this vein, a composite log called ConformXpert was developed to highlight the entire well from openhole images to casing/cement evaluation to reservoir monitoring. Lack of a cement evaluation log could be significant if a water-bearing zone is nearby, so proper analysis of the entire system could justify acquisition costs. Figure 3.38 (Page 3-60) provides an example of the ConformXpert presentation:

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The depth track shows a pay flag generated from the openhole logs along with a zonal number used in the production logging analysis.

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Track 1 provides an amplitude image from the CAST-V of the openhole section. This will highlight rock textures, fractures, and other reservoir features that could influence conformance applications.

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Track 2 is a standard volumetric analysis of the openhole logs. Rock types and lithologies could also determine the proper conformance treatment applied.

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Track 3 provides comparisons of the initial openhole water saturation and later reservoir monitoring water saturation. If the zones are adequately swept, the best treatment may be abandonment of the zone.

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Track 4 consists of the openhole fluid analysis. This will highlight water vs. producing zones.

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Track 5 consists of the openhole permeability calculations. This will highlight zones or formations that might have a premature water breakthrough either through water flooding or natural water drives.

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Track 6 provides a typical CBL log that shows the condition of the cement sheath. This will allow operators to determine whether zonal isolation is the conformance problem.

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Track 7 consists of the CAST-V cement image providing detail about the cement-to-casing bond. The Tracks 6 and 7 when examined together provide accurate information regarding the zonal isolation of the well.

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Track 8 is the pipe inspection data from the CAST-V. If casing damage is present, the conformance treatment could be simple or complex, depending on the type and cause of the damage.

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Track 9 provides production logging data. This shows the what and where of fluid production. Reservoir conditions can be more accurately determined through the use of tracers, logging tools, and downhole video. Once conditions are known, design teams can use computer programs to identify conformance problems and recommend effective treatments. Chapter 4 provides information regarding Halliburton’s XERO WaterControl Expert System.

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Figure 3.38—ConformXpert log combines all the available well log data into one easy to use image. Missing segments are shown to allow determination of the proper conformance treatment. Further data acquisition could make the correct conformance treatment selection easier and the treatment results could be excellent.

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Chapter 4 Introduction This chapter describes two software packages recommended for conformance solutions—the QuikLook simulator and the XERO water control expert system. The QuikLook simulator can be used to design a conformance treatment, while the XERO system is used to help diagnose problems from a production profile. The QuikLook simulator section of this chapter includes basic background, features, and testing of the simulator. To learn how to run the simulator, refer to the QuikLook software user manual.

QuikLook Simulator The QuikLook simulator is a new tool primarily intended for reservoir fluid management. It is the first simulator designed specifically for conformance applications and for use by practicing engineers. QuikLook is a “black-oil” three-dimensional, three-phase, fourcomponent, non-isothermal reservoir simulator that numerically solves the differential equations for multidimensional fluid and heat flow through a porous medium. The simulator is used to optimize the design of a conformance treatment and to evaluate the efficiency of the conformance solution. Specifically, the simulator can be used to help perform the following tasks: •

Predict the effect of a conformance treatment on reservoir performance

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Forecast results of treatments applied to complex reservoirs and/or complex wells

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Reduce economic operational risk by employing better candidate selection

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Achieve a better understanding of reservoir mechanics

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Reduce cycle time by shortening the decision-making process

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Optimize the design of a conformance treatment to maximize value to customers

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Investigate new placement techniques

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Train engineers in conformance technology

Computer Programs

The QuikLook simulator has a userfriendly graphical user interface (GUI) that allows users to enter data, launch the simulation, monitor the simulation run, and analyze the results. It also provides a convenient way to enter the complex data required for numerical simulation with the help of interactive graphics, consistency checks, supplemental plots, and other simple tools. Several important features make the QuikLook simulator especially valuable for helping solve conformance problems. These features do not usually exist in conventional blackoil simulators. •

In addition to numerically solving the partial differential equations that govern 3-D flow of oil, gas, water, and the conformance fluid, QuikLook also numerically solves the energy balance (heat flow) equation. This feature is critical

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In addition to calculating the flow of oil, gas, and water, QuikLook contains a fourth phase that represents the injection and flow of the conformance fluid. This phase enables the software to track the location of the conformance fluid, leading to significantly better solutions and predictions of reservoir performance than the conventional black-oil simulators. This option also allows the user to modify the placement technique to maximize the return and benefit of the conformance treatment.

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QuikLook simulates the conformance fluid rheology and polymer thickening (gelation) with time and temperature.

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Several Halliburton conformance fluids are built in to QuikLook, eliminating the need to enter the properties of those fluids.

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QuikLook is linked to the WELLCAT wellbore simulator.

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QuikLook is designed to have a user-friendly GUI.

QuikLook capabilities are accessed through its GUI (Figure 4.1), into which all data are entered. The GUI controls the processing of the data by QuikLook and WELLCAT software packages. The QuikLook solver and WELLCAT model are completely integrated to simulate a flow of fluids in the wellbore and the reservoir.

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to conformance applications in two respects: (1) simulating the injection of conformance material into a formation that may have been cooled down by circulation and (2) in calculating and understanding the process of polymer gelation as a function of time and temperature.

Figure 4.1–QuikLook Graphical User Interface

WELLCAT can be turned off so that wellbore calculations cannot be made. When WELLCAT is turned off, the data assumes no change in temperatures, pressures, and compositions of fluids traveling from the surface to the bottom of the hole or vice versa.

Purpose and Philosophy of QuikLook The main purpose of QuikLook is to provide Halliburton Engineers with a software tool designed to investigate the feasibility of applying a Halliburton proprietary conformance treatment to oil or gas wells that exhibit conformance problems. The software simulates the application of conformance treatments for a given situation and provides guidance for choosing among options for conformance fluids and treatment design. The program is designed to enable the user to identify a problem, quickly investigate the effects of various

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remedies, and choose an optimal treatment. The effect investigated here is in terms of reservoir response (rate and total production). QuikLook is designed to help engineers estimate the value of a project as illustrated in Figure 4.2 (Page 4-3). The basic philosophy behind the simulator is to sacrifice some of the accuracy to gain speed in both simulation and turnaround rate. The goal is to achieve at least 85% accuracy but reduce the turnaround rate to four hours or less. However, the user should recognize that some of the features incorporated in QuikLook are truly unique and do not exist in the commercially available simulators. Some of these features include the heat flow, a fourth component, and the linkage with a wellbore simulator. With the addition of these features, it may be argued that the QuikLook results may be more accurate than the results from a conventional simulator.

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Some of these general types of conformance fluids include sub-types that differ by the type of activator used. Chapter 5 of this book provides a detailed discussion of these fluids.

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Figure 4.2—QuikLook conformance solution process

QuikLook Theory QuikLook is a sophisticated numerical simulator. Like all numerical simulators, QuikLook solves a set of differential equations that describe flow of fluids and heat through a wellbore and porous media. These equations are solved by first converting the differential equations into a set of difference equations for each cell in the reservoir. The difference equations would form a set of linear algebraic equations. This set of equations is solved numerically using matrix solution techniques. Descriptions of how the difference equations are formulated and solved are provided in other literature.1,2

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Conformance Fluids Modeled by QuikLook The chemical sealants that are used for conformance are normally designed to be placed at a low viscosity and react in situ to form a more viscous (usually highly crosslinked) gel. In the QuikLook simulator, conformance fluids are assumed to consist of a monomer and an activator that catalyzes the conversion of the monomer to a gelled or partially gelled polymer. The following Halliburton conformance fluids are built into QuikLook:

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H2Zero

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Injectrol

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PermSeal

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PermTrol

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WELLCAT is a Landmark Graphics software package that includes several modules that can model a variety of wellbore applications. Only the WS-PROD module is used in the QuikLook simulator. The WS-PROD module simulates fluid flow and heat transfer in wellbores during completion, production, stimulation, testing, and well-servicing operations. It handles both steady state and transient single and multiphase flow. The WS-PROD module of WELLCAT software is used to calculate pressure and temperature profiles in a wellbore for both flowing and shut-in conditions. The WELLCAT capability in QuikLook is required to help determine the true state of the conformance fluid as it enters the formation at the bottom of the well. In practice, conformance fluid pressure, temperature, and related properties are measured only at the surface during treatment. Conformance fluid properties at bottomhole conditions where fluid goes from the wellbore into the reservoir and/or behind casing should be calculated. These calculations are the main function of WELLCAT software within the QuikLook simulator.

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General Data Requirements The QuikLook simulator requires the following basic engineering data:

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Geological reservoir characteristics (e.g. porosity, permeability and thickness of the producing formation)

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Rock properties such as relative permeability and pore volume compressibility (cr)

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Well drainage radius, current reservoir pressure, oil-water and gas-oil contacts

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Fluid properties for the reservoir fluids (e.g. viscosity, density and compressibility of the reservoir oil, gas and water)

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Historical production and injection data for the well or wells to be treated (e.g. oil production rates, pressures)

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Tubular goods configuration (e.g. casing, tubing, packers) and completion intervals

The simulator has default values for certain fluid and rock property data. In general, these default values will not be appropriate for all situations, so at least approximate values for all of the data should be available. In addition to the data listed for conventional petroleum reservoir simulation, QuikLook requires fluid properties of the conformance fluids.

Validation of the QuikLook Simulator This section attempts to validate the QuikLook simulator by comparing the output of the simulator to output from existing commercial simulators. Two different sets of runs were implemented. In the first set of examples, the basic validity of the simulator was confirmed by compar-

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ing its results to results reported in two SPE comparative simulation studies. In these two studies, the QuikLook simulator was run as a conventional black-oil simulator. In the second set of examples, the validity of QuikLook as a conformance simulator was investigated using a commercially available simulator. Among available simulators, only STARS and QuikLook could simulate the performance of a conformance treatment. The QuikLook simulator has a distinct advantage of considering both the wellbore and temperature effects. However, both simulators have a fourth component to simulate the presence of a conformance fluid. After the validity of the simulator was established, the features specially developed to simulate conformance studies were used in a series of runs.

Example 1—First SPE Comparative study In an article that was published in 1982,3 seven operating, software and consulting companies participated in a study to compare the results of their

three-dimensional black-oil simulators. These companies were Amoco, Exxon, Mobil, Shell, Intercomp Resource Development, Computer Modeling Group (CMG), and Scientific Software Corp. The reservoir geometry was simple: a rectangular reservoir consisting of three layers. Both a producer and a gas injector are in this reservoir. The injection well was located in one corner of the reservoir and completed in the top layer only, while the production well was placed in the opposite corner and perforated in the bottom layer. Table 1 lists the reservoir properties and constraints specified for the study. PVT data and detailed descriptions of the problem can be found in Reference 3. This reference also gives descriptions of the various models used by the participating companies. All simulators were 3-D, three-phase black-oil simulators, and none of the simulators considered heat flow. The 10 × 10 × 3 reservoir grid system used for this first SPE comparative study is shown by the areal view in

Table 4.1–Data and Constraints for Example 1 Initial reservoir pressure (psi) 4,800 Depth (ft) 8,400 Gas injection rate (MMCF/D) 100 Maximum oil production rate (STB/D) 20,000 Minimum oil rate (STB/D) 1,000 Minimum flowing pressure (psi) 1,000 Maximum saturation change during 0.05 Porosity at 14.7-psi base pressure 0.3 Wellbore radius (ft) 0.25 Skin factor 0 Capillary pressure (psi) 0 Reservoir temperature (°F) 200 Gas specific gravity 0.792 Maximum project time (yr) 10 Maximum GOR (SCF/STB) 20,000

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Figure 4.3. Figure 4.4 shows the cross-sectional view of the nearwellbore area of the injector and the producer. The QuikLook simulator was run to simulate the conditions specified in the article3 and results were compared to those reported. First the initialization results (i.e. the calculated fluid in place from the QuikLook simulator) were in excellent agreement with the simulators used in the first SPE comparative study. Results from this simulation run are shown in Figures 4.5 through 4.9.

Figure 4.5 (Page 4-6) presents the oil production predicted by the various simulators. All the simulators initially produce at the maximum allowable rate of 20,000 STB/D. Production rate starts declining at the minimum allowable flowing pressure of 1,000 psi. At this point the simulator switches to a constant flowing pressure, allowing the rate to decline. As Figure 4.5 shows, all simulators reached this point approximately four years from the start of production. They all show decline in productivity with time reaching a rate of about

6,000 STB/D at about 10 years from start of production. Although the QuikLook simulator was not exactly an average of the simulators, its response was excellent. It agreed more with Shell’s simulator. Figure 4.6 (Page 4-7) shows the how the gas-oil ratio (GOR) changed with time. For a little more than three years the GOR was constant and equal to the solubility of gas in oil, indicating that up to that point the reservoir pressure was above bubble point pressure. When the flowing pressure fell below the bubble point pressure, gas began to come out of the solution, building up the gas saturation inside the formation, which in turn led to the building up of formation permeability to gas.

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This effect is seen in the very fast increase in GOR. In the QuikLook simulator, the flowing pressure reached the bubble point pressure at about the same time as for most simulators. In addition, the GOR profile was comparable to the other simulators.

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Figure 4.3–Cartesian grid system for SPE Comparative Project 1

Figure 4.4–Cross-sectional view of the near wellbore area of (a) injector and (b) producer

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Figure 4.5–Oil production ratio vs. time for SPE Comparative Solution 1

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Figure 4.6–GOR vs. time for SPE Comparative Solution 1

Figure 4.7 (Page 4-8) provides the producing pressure vs. time for the various simulators. Although the QuikLook simulator reached a little higher peak at a slightly later time, it generally agreed with the rest of the simulators throughout the life of the project.

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Figure 4.8 (Page 4-8) presents the gas saturation history at the bottom layer where the production well is located. (The simulators are in general agreement.) Figure 4.9 (Page 4-9) shows the pressure profile at the injection well. (The simulators are in general agreement.) However, similar

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to Figure 4.7, the peak pressure reached by the QuikLook simulator is a little higher than the rest. These results could be caused by the differences in how the individual simulators handle the wellbore geometry.

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Figure 4.7–Gridblock 10, 10, 3 pressure vs. time for SPE Comparative Solution 1

Figure 4.8–Gridblock 10, 10, 3 gas saturation vs. time for SPE Comparative Solution 1

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Figure 4.9–Gridblock 1, 1, 1 pressure vs. time for SPE Comparative Solution 1

Example 2—Second SPE Comparative Study

case of the first study, many of these companies no longer exist.

In an article that was published in 1986,4 eleven companies participated in a study to compare the results of their three-dimensional black-oil simulators. These companies were Arco, Chevron, Gulf, Shell, Intercomp Resource Development, Scientific Software Corp, D&S Research and Development, Franlab Consultants, Harwell, McCord Lewis Energy Services, and J. S. Nolen & Associates. LGC’s VIP is based on a simulator developed by J. S. Nolen, while the QuikLook simulator is based on a simulator that was owned by D&S. As in the

The problem submitted to the various companies was essentially a water-coning problem. Figure 4.10 (Page 4-10) shows a cross-section of the 15-layer reservoir. Basic reservoir properties are presented in Table 4.2 (Page 4-10). Detailed reservoir, fluid, and simulation data are listed in Reference 4.

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The problem is obviously artificial in several aspects.4 The planned production rate changes were unlikely to occur in real situations, and the GOR was very high for the specified oil. This makes the problem difficult to solve and possibly a better test for the various simulators.

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The given reservoir dimensions represent a drainage area of approximately 303 acres, or 3,634 ft × 3,634 ft square drainage area. The corresponding drainage area is shown by the Cartesian grid system in Figure 4.11-a (Page 4-10). Half of a vertical cross-section along the gridblocks in which the well is located is presented in Figure 4.11-b (Page 4-10), showing the location of the perforations. As in the first study, the initialization results (i.e. calculated the amount of fluid in place) from the QuikLook simulator agreed with the simulators used in the first SPE comparative study.

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Production Well

Block (1.7) Block (1.8)

rw = 0.25 FT

WOC - 9209FT

2050FT NR = 10

359 FT NZ =15

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DEPTH 9000 FT GOC - 9035

Figure 4.10–Reservoir model for SPE Comparative Solution 2

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Table 4.2–Data and Constraints Initial reservoir pressure (psi) 3,600 Depth (ft) 9,035 Radial extent (ft) 2,050 Number of layers 15 Minimum flowing pressure (psi) 3,000 Wellbore radius (ft) 0.25 Skin factor 0 Capillary pressure (psi) 0

Figure 4.11–Cartesian grid system and cross-sectional view of vertical layers

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margin. For example, after 400 days the various simulators predicted a water cut ranging from 0.335 to 0.36; the QuikLook simulator predicted a water-cut of 0.322. Figure 4.14 (Page 4-12) presents the GOR vs. time for all the simulators.

Results of the QuikLook simulator are consistent with the majority of the simulators. The same observation applies to the bottomhole flowing pressure vs. time profile shown in Figure 4.15 (Page 4-12) and the pressure drawdown vs. time in Figure 4.16 (Page 4-13).

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Figure 4.12 presents oil production rate as a function of time. The QuikLook simulator is not different from the rest of the simulators. Although the predicted the water cut followed the general trend of the various simulators (Figure 4.13) its value was underpredicted by a small

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Figure 4.12–Oil production rate vs. time (SPE Comparative Solution 2)

Figure 4.13–Water cut vs. time (SPE Comparative Solution 2)

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Figure 4.14–GOR vs. time (SPE Comparative Solution 2)

Figure 4.15–Bottomhole pressure vs. time (SPE Comparative Solution 2)

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Figure 4.16–Pressure drawdown vs. time (SPE Comparative Solution 2)

QuikLook as a Conformance Simulator In this section, the capabilities of the QuikLook simulator as a conformance simulator are demonstrated. These capabilities are first matched against STARS, then examples of QuikLook used for simulating channeling and coning problems are illustrated. The examples demonstrate the use of the QuikLook engine, thermal model, and its linkage to WELLCAT for designing and optimizing the size and placement of a conformance treatment so that reservoir performance is maximized. For this comparison, the following three specialized data sets were used. Each data set reflects the application of sealants for controlling the production of unwanted water from both oil and gas reservoirs. 1.

Water channeling between injector/producer in a black-oil reservoir (PermSeal solution)

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2.

Water coning of a single gas producer (H2Zero and PermSeal solutions)

in Figure 4.18-a (Page 4-14). The treatment interval is shown in Figure 4.18-b (Page 4-14).

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Water coning of a single oil producer (PermSeal solution)

This producer was flowed at initial oil rate of 1,000 STB/D simultaneously with water injection in the injector. The injection pressure was maintained at a maximum value of 2,000 psia. Oil, gas, and water production histories are presented in Figure 4.19 (Page 4-15) and are compared with STARS results for the base case using the simulators as black-oil simulators. The comparison is excellent.

Case 1–Water Channeling in an Injector-Producer System (PermSeal Solution) Case 1 is an example of a five-year production and water injection in a 13-layer black-oil reservoir system. Figure 4.17 (Page 4-14) shows the 21 × 21 × 13 ft Cartesian grid system, with the two wells in this reservoir, and a vertical cross-section across the wells illustrating the refined grids in the near-wellbore area. This reservoir has an impermeable layer at the middle of the productive zone (Layer 7), with high-permeability layers at the top of this barrier and low-permeability layers below it. A cross-sectional view of the production and injection intervals is shown

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Additionally, the predicted pressures, both flowing and average pressure, show a very good match between the two simulators. Figure 4.20 (Page 4-15), a plot of average pressure and bottomhole pressure profiles for both QuikLook and STARS simulation runs, shows a very good comparison between QuikLook and STARS results.

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Figure 4.17–Cartesian grid system used for Case 1 and cross-sectional view across the wells

Figure 4.18–Cross-sectional view of (a) producing and injection intervals and (b) treatment interval for Case 1

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Figure 4.19–QuikLook and STARS oil, gas, and water production rates (base case)

Figure 4.20–QuikLook and STARS average reservoir and bottomhole pressures vs. time (Case 1)

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jump in water production from essentially zero to over 400 bbl/D and remaining almost constant thereafter. Meanwhile, the layers with low formation permeability remained unswept, causing the oil rate to remain low. Because the preferred path of the injected water, in this case, is the already swept high-permeability layers, conformance treatment

intervention is necessary to produce oil from the lower-permeability layers. An appropriate treatment in this case is to inject PermSeal into the high-permeability layers. PermSeal will form a barrier that will prevent injected water from getting into the high-permeability layers. Instead, injected water will be diverted into the lower-permeability layers, sweeping these layers.

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As expected, a major portion of the injected water flooded the highly permeable layers located at the top, with water breakthrough in this region occurring about 200 days from the beginning of production. This situation is graphically illustrated in Figure 4.21, which shows very high water saturation in the high-permeability layers. Figure 4.21 also shows the water breakthrough at approximately 200 days as manifested by the

Figure 4.21–2-D QuikLook water saturation profile at water breakthrough

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QuikLook may be also used to graphically illustrate the placement of the treatment in greater detail. Figure 4.23-a (Page 4-18) shows a 2D polymer gel profile in the nearwellbore area of the injection well just after the conformance treatment. The conformance gel profile is uneven across the treatment interval, as shown in the expanded graph in Figure 4.23-b (Page 4-18). Layers 3 and 4, which have lower

permeabilities of approximately 60 md, had a shallow gel penetration. Layers 1 and 2 with permeabilities of 140 md, and Layers 5 and 6 with permeabilities of 100 md, had relatively deeper gel penetration. The post-treatment production rates predicted by both QuikLook and STARS simulators are plotted in Figure 4.24 Page 4-18). The graph shows an excellent agreement between the two simulators.

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For the treatment case, the upper layers in the injector were treated with 100 bbl of PermSeal. The well was then shut in for five days to allow the polymer to set, and later put back on injection. Figure 4.22 shows that this conformance treatment forced the injected water to sweep the bottom layers, thereby modifying the injection profile in this injector.

Figure 4.22–QuikLook water saturation profiles four years after the conformance treatment

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Figure 4.23–QuikLook conformance fluid saturation profiles five days after treatment

Figure 4.24–QuikLook and STARS oil, gas, and water production rates (treatment case)

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The main objective in this example was to reduce water production. Using PermSeal to shut down the upper layers that have already been swept stopped the water from channeling through the reservoir. From that point on, all injected water went into the lower zone. Because of the injection pressure limitation, the injected water rate going into the lower zones was not increased.

Consequently, oil rate was not increased. In this case, a constant oil production rate was achieved with a significantly lower water injection rate and lower water production. The lower cost of water injection and surface processing of produced fluids very favorably impacted the economics of the project.

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QuikLook simulation of reservoir performance with and without the conformance treatment is presented in Figure 4.25. This graph shows the significant impact of the polymer gel treatment for reducing water production from 400 bbl/D to almost zero; oil production rate did not significantly change. In addition, the plot demonstrates the QuikLook simulation capability of profiling modification jobs.

Figure 4.25–QuikLook oil, gas, and water production rates (with and without treatment)

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Case 2–Water Coning of a Single Gas Producer (H2Zero and PermSeal Solutions)

The producing interval (perforations) is placed at the very top of the formation so as to minimize water production, as shown by Figure 4.27-a. The 5-ft injection zone, used for conformance treatment of this well, is shown by the cross-sectional view in Figure 4.27-b. This treatment interval was placed almost 10 ft below the bottom of the perforations–as close as

possible to the lowest perforations while avoiding invasion of conformance fluid into the producing interval during treatment. This well was produced at an initial gas rate of 10 MMcf/D. As shown in Figure 4.28 (Page 4-21), water coning began approximately two months after the start of gas production. The comparison between QuikLook and STARS waterproduction histories is quite good. However, following coning, the

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Case 2 involves a 640-acre dry gas reservoir with a producer located at the center. In this case, the effect of H2Zero and PermSeal conformance treatments on reservoir performance is examined. Figure 4.26-a shows the Cartesian grids used in the simulation of the reservoir system. A cross-

section along the well showing both the areal and vertical grid refinement is presented in Figure 4.26-b.

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Figure 4.26–Cartesian grid system with locally refined grids used for Case 2

Figure 4.27–Cross-sectional view of (a) producing interval and (b) injection interval for Case 2

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QuikLook simulator shows a faster increase in water production, finally reaching the water production limit of 100 bbl/D approximately a year from the start of production. STARS reached that same level about three months later. The difference in results between the two simulators is within the range for simulation discussed in the SPE comparative studies.

Figure 4.28–QuikLook and STARS gas and water production rates vs. time (base case)

To solve the coning problem, approximately 170 bbl of H2Zero was used to treat this gas producer. Figure 4.30 (Page 4-22) presents the gas and water production rates for both the base and treated cases. The polymer was injected into the formation two months after the start of production. This event appears as a discontinuity in the water and gas rates, reflecting the change in condition from production water and gas to injection of polymer and back to injection.

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Figure 4.29–QuikLook and STARS average reservoir and flowing pressures vs. time (Case 2)

On the other hand, the predicted pressure values (both the average and flowing bottomhole pressure) from QuikLook and STARS match very well. This match is illustrated in Figure 4.29.

The graph clearly shows the effect of H 2Zero on gas and water production. The treatment increased both gas rate and gas cumulative production while delaying water production for five years. Although not investigated in this chapter, the simulator can also be used to investigate the timing of the treatment.5 In this reservoir, the ratio of verticalto-horizontal permeability is 0.2. Lower ratios are sometimes seen. The lower the vertical-to-horizontal permeability ratio the less severe the coning problem will become, and the wider the polymer barrier will become for the same injected volume.

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Figure 4.30–QuikLook gas and water production rates vs. time after H2Zero treatment

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The QuikLook simulator may be used to study fluid saturation inside the reservoir, providing an insight into the potential optimization of placement and reservoir performance. Figure 4.31 shows the water saturation distribution inside the reservoir before and after the conformance treatment. In Figure 4.31-a, which shows the fluid saturation after 60 days and just before the conformance treatment was placed, large pressure drawdown in the reservoir caused water coning into the perforated interval. In other words, within two months of reservoir depletion, water from the aquifer reached the perforated interval, resulting in early water production in this well.

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Figure 4.31–QuikLook water saturation profiles (before and after the H2Zero treatment)

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Figures 4.31-b and 4.31-c show water saturation profiles in the reservoir just after the conformance treatment (65 days) and approximately five years after the treatment, respectively. In the water saturation profile in Figure 4.31c the bottomwater appears to move around the gel barrier into the open perforations, indicating that a wider barrier (larger injected volume) would produce even better results.

As mentioned in previous sections, the QuikLook simulator uniquely integrates the temperature and wellbore calculation into the reservoir simulation. The nearwellbore temperature profiles before and after the H2Zero gel treatment are calculated and presented in Figure 4.32. The initial reservoir temperature of 150°F is reflected throughout the reservoir during prejob production period (Figure 4.32-a). The surface temperature was only 80°F. The wellbore simulator WELLCAT calculated a downhole temperature of 130°F during the conformance treatment.

Figure 4.32-b shows the temperature profile immediately after the H2Zero and displacement fluid injections. The cooler injected fluids cause a reduction in reservoir temperature in the locations where they contacted reservoir fluid. The subsequent increase in the temperature of the injected gel during the production period after the treatment is demonstrated by Figure 4.32-c. This figure shows that after the treatment nearly a month passed before the reservoir temperature was restored to original conditions. The reservoir temperature in this case is low enough to allow for the injection of H2Zero without any problem, but this is not always the

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One observation that can readily be made from the H2Zero results in Figure 4.31 is that the treatment was effective within an approximately 28-ft diameter around the wellbore. Although low concentrations of the conformance fluid are present beyond that region, Figure 4.31-a clearly demonstrates that the

effective gel barrier controlling the bottomwater coning is limited to the 28-ft diameter barrier.

Figure 4.32–Temperature profiles before and after H2Zero treatment

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case. In cases where reservoir temperature is fairly high, some cooler fluid may need to be injected or circulated to reduce the reservoir temperature enough to allow for polymer injection without premature gelling. To investigate the effect of other treatments, the same well was also treated with approximately 300 bbl of PermSeal. Later, the well was treated with 960 bbl of PermSeal. Conformance fluid distributions in the nearwellbore area for the H2Zero and the two PermSeal treatments are presented in Figure 4.33.

Another important observation is that the injected PermSeal plugged the formation around the lower part

of the perforated interval (Figure 4.33-c). This action reduced the effectiveness of the treatment, indicating that the conformance treatment design in such a situation should not only include the type and amount of conformance treatment to be injected, but also where this volume should be injected. Gas and water production histories for the two PermSeal treatments are plotted in Figure 4.34 (Page 4-25), along with the base case. The larger treatment (960 bbl) considerably improved reservoir performance; gas production increased significantly as the water production rate decreased.

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As seen in the previous H2Zero results given in Figure 4.31, the treatment

was effective within a 28-ft diameter around the wellbore. In the case of the larger PermSeal jobs, Figure 4.33-b shows an increase in the dimensions of the gel barrier, 32 ft and 60 ft in diameter for the 300- and 960-bbl treatments, respectively. In the latter case, however, the bulk of the additional PermSeal (over the initial 300 bbl) went to expand the barrier thickness as a result of the relatively high vertical to horizontal permeability ratio. A lower permeability ratio would cause the barrier to be thinner and wider.

Figure 4.33–QuikLook conformance fluid profiles

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Figure 4.34–QuikLook gas and water production rates vs. time (with and without PermSeal treatment)

Case 3–Water Coning of a Black-Oil Producer (PermSeal Solution) This last case is similar to Case 2, except that the reservoir fluid is a black-oil system. In this example, the initial reservoir pressure was 1,800 psi. The reservoir was exploited using a single well located at the center of 160-acre drainage area, shown in Figure 4.35-a (Page 4-26). The well is produced under a constraint of 1,000 bbl/D maximum liquid production rate. A vertical crosssection showing the refined grids used in the near-wellbore area is presented in Figure 4.35-b (Page 4-26). Figures 4.36-a and 4.36-b (Page 4-26) show the locations of the producing and treatment intervals, respectively. A summary of the simulation results for the base case (without treatment)

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is shown in Figure 4.37 (Page 4-27). For the base case, fluid predictions by the QuikLook and STARS simulators compare quite well except that QuikLook predicts slightly higher produced water than STARS, which also reflected on the slightly lower oil production rates. Water saturation distribution inside the reservoir is shown in Figure 4.38 (Page 4-27). Additionally, water coning is evident very early in the life of this oil well. Figures 4.38-b and 4.38-c show water saturation profiles just after the conformance treatment (65 days) and roughly five years after the treatment, respectively. As in the previous coning example, the water tends to bypass the gel barrier over time. This phenomenon often calls for a large conformance treatment to ensure an extensive gel barrier. However, as noted in the

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previous case, increasing the size of the conformance treatment could result in an unintended additional restriction near the perforated interval. Similar to the previous example, in reservoirs with high vertical permeability, the potential exists for some of the injected conformance fluid to move up in the formation and invade the original perforations. Three conformance treatment options were considered in this case: 120 bbl, 300 bbl, and 1,000 bbl of PermSeal conformance fluid. The effect of the injected volume was examined, along with the effect of the location of injection. In the first set of treatments the conformance material was injected through perforations in a 5-ft interval located 10 ft below the bottom of the producing interval.

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Figure 4.35–Cartesian grid system with local grid refinement used for Case 3

Figure 4.36–Cross-sectional view of (a) producing interval and (b) injection interval for Case 3

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Fig. 4.37–QuikLook and STARS oil, gas, and water production rates (base case)

Fig. 4.38–QuikLook water saturation profiles (before and after conformance treatment)

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Figure 4.39 shows a typical plot from optimization runs based on job size. The extensions tr1, tr2, and tr3 represent treatment volumes of 120 bbl, 300 bbl, and 1,000 bbl, respectively. All the treatments mitigated the coning problem in this well. The 120-bbl conformance job appears to be the best treatment for this case.

Although the larger treatments result in barriers with larger diameters, the barriers were also larger in height and damaged part of the perforated interval. Therefore, the larger treatments did not perform as well as the smaller treatment. When the treatment was injected 15 ft below the producing perforated interval instead of just 5 ft, the situation significantly changed as shown in Figure 4.41 (Page 4-29). In this figure, the extensions tr4, tr5,

and tr6 correspond to treatment volumes of 120 bbl, 300 bbl, and 1,000 bbl of PermSeal, respectively. Figure 4.42 (Page 4-30) shows conformance fluid distributions in the near-wellbore area for these same three treatments. The graphs illustrate the conclusions. Figure 4.41 shows that increasing the volume of the injected conformance fluid from 120 to 300 bbl improved the performance of the treatment. Increasing the volume to 1,000 bbl still caused the well performance to decline, indicating that for this reservoir injecting that much volume merely 15 ft below the producing perforated interval is not advised. Therefore, an optimized treatment size always exists for every reservoir situation.

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Figure 4.39 also indicates that increasing the size of the conformance treatment results in worse oil and water production during the 5year period. Although these results may initially appear to be illogical, examination of the conformance fluid distribution inside the reservoir helps clarify the results.

Conformance fluid distributions in the near-wellbore area for these three treatments with different treatment volumes are presented in Figure 4.40 (Page 4-29). This figure shows only a limited gel barrier with a diameter of approximately 20 feet for the 120-bbl conformance job.

Figure 4.39–QuikLook oil and water production rates (with and without treatment)

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DN002277 DN002278

Figure 4.40–QuikLook conformance fluid profiles – Case 2

Figure 4.41–QuikLook oil and water production rates (treatment interval is 15 ft below bottom of original perforations)

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Figure 4.42–QuikLook conformance fluid profiles (treatment interval is 15 ft below bottom of original perforations)

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The XERO Program Once data has been collected and analyzed, engineers can use Halliburton’s XERO Water-Control Expert System to verify problem identification and determine possible treatments (Figure 4.43). XERO, a Greek term meaning “no water,” is a Microsoft® Windows™-based system that has two processing phases: the problem identification phase and the treatment design phase. This chapter provides a general overview of the XERO System.

Based on the information the user enters, the system can determine the probability of one or more of the following conformance problems existing in the well: •

Bottomwater

•

Bottomwater coning

•

Casing leaks

•

Channel behind pipe

•

High-permeability streaks

Phase 1: Problem Identification

•

Injection out of zone

During the problem identification phase, the system prompts the user to enter reservoir and well information.

•

Interwell communication

•

Stimulation into water

Figure 4.43—XERO main screen showing Problem Identification and Treatment Design options

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During the problem identification phase, users will be prompted to provide the following information. The Customer Information screen (Figure 4.44) requires the user to provide information about the customer and the well that will be evaluated. After the user provides the available information and presses the GO! button, the first Reservoir Information screen appears.

Figure 4.44—Customer Information screen

The Reservoir Information screens (Figures 4.45 and 4.46, Page 4-33) allow the user to enter as much relevant reservoir information as possible. Much of this information can be omitted if it is not available or if its accuracy is questionable. The minimum data required are the completed interval depth range (Figure 4.45) and the bottomhole static temperature (BHST) (Figure 4.46, Page 4-33). Obviously, however, the more information the user enters, the more accurately XERO can identify potential reservoir problems.

Figure 4.45—Reservoir Information I screen

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Figure 4.46—Reservoir Information II screen

After choosing GO! from the Reservoir Information II screen, the user advances to the Well Information screen (Figure 4.47). This screen again prompts the user to answer a series of questions and to enter available data. The only required information is the average permeability and the hole size.

Figure 4.47—Well Information screen

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If production and permeability data is available, a Production Well Profile screen will next appear (Figure 4.48).

Figure 4.48—Production Well Profile screen

After entering the pertinent data for this screen, the user advances to the Injection Information screen (Figure 4.49). The only required information for this screen is the injection rate.

Figure 4.49—Injection Information screen

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If the user enters a maximum recorded bottomhole injection pressure (BHIP), an Injection Well Profile screen will appear (Figure 4.50)

Figure 4.50—Injection Well Profile screen

After entering the pertinent data, the user advances to the Workover History screen (Figure 4.51). This screen asks several questions regarding past workovers, including previous conformance control treatments. All the treatments listed in Figure 4.51 are Halliburton-specific treatments.

Figure 4.51—Workover History screen

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To enter non-Halliburton treatments, the user would click on the OTHERS button to display the generic water control treatments listed in Figure 4.52.

Figure 4.52—Other Water Control Treatments screen

After choosing a generic water control treatment and advancing to the next screen, the user must enter well performance data (Figure 4.53). The only information required for the Well Performance screen is the current water production rate, which in the case of the example is 650 B/D.

Figure 4.53—Well Performance screen

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After entering all available well performance data, the user advances to the Water Production Data screen (Figure 4.54), which requests water production data for up to 10 years.

Figure 4.54—Water Production Data screen

Based on the information the user enters, the system creates a water production plot (Figure 4.55), and asks the user to select up to two patterns that most closely match the current water production plot.

Figure 4.55—Water Production Plots screen

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After completing this screen, the user advances to a series of recommendation screens, the first of which lists possible problems and their percentages of likelihood (Figure 4.56).

Figure 4.56—Possible Problems screen

By clicking on any of the possible problems listed, the user will receive a list of reasons and unknowns (Figure 4.57). The Reason(s) list contains data that contributed to the identification of the problem. The Unknown(s) list contains data that, if available, would help the system more accurately identify the water problem.

Figure 4.57—List of Reasons and Unknowns

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To learn more about each reason or unknown, the user can click on the item and another window will appear with additional information about that particular reason or unknown (Figure 4.58).

Figure 4.58—Window providing more information about unknowns

Phase 2: Treatment Design During the treatment design phase, the user chooses one or more of the potential water problems that the system identified as likely and enters treatment design information into the system. The system then determines fluid systems that can be used based on current well information and displays a selection list of the treatments. The user can choose from any of the treatments for each water problem from the selection list. Once the system has identified potential problems, the Treatment Design button becomes active on the main screen (Figure 4.59). To begin the fluid selection process, the user must first select at least one of the potential problems and advance to Figure 4.59—XERO main screen showing active Treatment Design button the next screen.

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The Design Information I screen requires the user to enter specific wellbore geometry and previous stimulation information for the well (Figure 4.60).

Figure 4.60—Design Information I screen

Once the user enters this information and selects GO!, the Design Information II screen appears (Figure 4.61). On this screen, the user must input the appropriate operator constraints on the treatment and other pertinent information as shown on the screen. The “tripping out” option on this screen gives the user the option of using cement as part of the treatment design. Depending on well conditions, the user may want to use the program to make two designs: one with cement and one without cement.

Figure 4.61—Design Information II screen

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After the Design Information II screen is completed, the user advances to the Fluid Selection screen (Figure 4.62), which shows the recommended fluid, as well as primary and secondary alternatives. Any of the listed choices could be used for the treatment, but the recommended fluid is the one that best fits the requirements of the candidate well that was evaluated. To select the fluid, the user must place the mouse pointer over the appropriate box and click the left mouse button.

Figure 4.62—Fluid Selection screen

Once a fluid is selected, the system calculates a job schedule, including estimated fluid volumes, a list of the materials required, and recommended placement techniques for the selected fluids (Figure 4.63).

Figure 4.63—Job Design screen

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To see additional information about Halliburton products, the user can choose Product Description from the dropdown menu at the top of the main screen, as shown in Figure 4.64. After the treatment design phase, users can print a report containing all the data the system used to identify the problem and generate possible solutions.

Figure 4.64—Product Description screen for Injectrol Service

Summary and Conclusions This chapter provided three examples and SPE comparative studies that validated QuikLook as an excellent reservoir simulator for predicting the performance of black-oil, volatile, and gas reservoirs. The preprocessor, solver, and post-processor have been improved significantly and are quite stable. As a conformance simulator, the last three cases show that QuikLook predictions compare quite well with STARS results. The software is unique in the industry because of features such as a very user friendly GUI, thermal affect,

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linkage to a wellbore simulation, and accurate representation of polymer injection and setting. The linkage of the simulator to Halliburton conformance fluids makes the simulator an especially easy tool to use. Several interesting features have been considered for future implementation into the simulator to enhance the simulator’s conformance simulation capabilities. These features include:

•

Polymer adsorption model, which will be calibrated carefully with specific field cases from successfully executed jobs

•

Irreversible gelation model

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•

Relative permeability modifier (RPM) simulation

•

Radial grids for efficient coning simulation

Finally, through the use of programs such as XERO, users can identify and verify conformance problems. They can also choose from several means of improving well conditions. Chapter 5 provides specific information about the many treatments and treatment methods available to control conformance problems.

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References 6.

Dawson, Rapier: “Drillpipe Buckling in Inclined Holes,” JPT (Oct. 1984) 1734.

7.

Hammerlindl, D. J.: “Basic Fluid and Pressure Forces on Oilwell Tubulars,” JPT (Jan. 1980) 153-59.

1.

Crishlow, Henry, B.: “Modern Reservoir Engineering: A Simulation Approach,” Prentice Hall, 1977.

2.

Khalid Aziz: “Petroleum Reservoir Simulation,” Chapman & Hall, 1979.

3.

Odeh, Aziz S.: “Comparison of Solutions to a Three-Dimensional Black Oil Reservoir Simulation Problems,” JPT, January, 1981, 13-25

8.

Weinstein, H. G., Chappelear, J. E., and Nolen, J. S.: “Second Comparative Solution Project: A Three-Phase Coning Study,” JPT, March 1986, 345-353.

9.

4.

5.

Soliman, M. Y., Creel, P., Rester, Sigal, R., Everett, D., and Johnson, M. H.: “Integration of Technology Supports Preventive Conformance Reservoir Techniques,” SPE 62553 presented at the 2000 SPE/AAPG Western Regional Meeting held in Long Beach, California, 19–23 June.

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Hammerlindl, D. J.: “Movement, Forces and Stresses Associated with Combination Tubing Strings Sealed in Packers,” JPT (Feb. 1977) 195-208. Hammerlindl, D. J.: “Packer to Tubing Forces for Intermediate Packers,” JPT (March 1980) 515-27.

10. Lubinski, A.: “Helical Buckling of Tubing Sealed in Packers,” JPT (June 1962) 655-670. 11. Lubinski, A.: “Influence of Tension and Compression on Straightness and Buckling of Tubular Goods in Oil Wells,” Proc., 31st Annual Meeting, API, Prod., Vol. 31, Sec. IV (1951), 31-56.

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12. Mitchell, R. F.: “Buckling Behavior of Well Tubing: The Packer Effect,” SPEJ (Oct. 1982) 616-24. 13. Mitchell, R. F.: “Numerical Analysis of Helical Buckling,” paper SPE 14981 presented at the 1986 SPE Deep Drilling and Production Symposium, Amarillo, TX, 6-8 April. 14. Muskat, M. and Wycoff, R. D.: “An Approximate Theory of Water Coning in Oil Production,” Trans., AIME (1935), 114: 114-161. 15. Wu, F. H., Chiu, T. H., Dalrymple, E. D., Dahl, J. A., and Rahimi, A. B.: “Development of an Expert System for Water Control Applications,” paper SPE 27552 presented at the 1994 European Petroleum Computer Conference, Aberdeen, Scotland, 15-17 March.

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Chapter 5 The chemical methods that are currently available for controlling waterflow range from a variety of water-based polymer systems to hydrocarbon-based, ultrafine Portland cement slurries. In injection wells, the success of a treatment is measured by the incremental oil recovered from offset producers. The response time in the producers ranges from immediate to several months, depending on treatment volume, well spacing, and formation properties. Engineers may use other techniques such as fluid-entry surveys and pressure testing to determine the success of the treatment. In production wells, the success of the treatment is generally measured by changes in the well’s water production. After a treated production well has been shut-in for the recommended time, production is slowly resumed. If the treatment was designed to seal a casing leak, pressure testing to the required pressure determines job success or failure. For all other applications, a successful treatment should decrease the amount of produced water. When designing a conformance project, engineers must first carefully consider the purpose of the program. Specifically, they must make certain that the physical and chemical characteristics of the solutions used

Chapter 5

will not contradict with any immediate or future plans for the reservoir. The following questions should be explored:

Treatment Options

What is the treatment expected to do? When success is not explicitly defined, well data must be thoroughly reviewed to determine how production should change after the target zone is treated. For example, zones that were not producing water before the treatment might begin producing water after the treatment. These situations can be predicted by material-mass equations. What bottomhole conditions can the treatment withstand? Bottomhole conditions include temperature, pressure, reservoir-fluid composition, and lithology. For example, design engineers would not recommend injecting an Injectrol® treatment into an interval if they were planning an improved oilrecovery job in that same interval at a later date. Instead, they would choose a material that would not permanently seal the zone, such as PermTrol. Regardless of the treatment planned, engineers should always order laboratory-scale tests to evaluate recommended treatment formulations before the actual treatment is performed.

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PermSeal Service

Water-Based Polymer Systems

PermSeal service reduces or plugs permeability to water and/or CO2 in hydrocarbon wells. After the water-thin gelation system is batch-blended and pumped into the isolated water-bearing permeability, the well is shut in, and the fluid polymerizes into an elastomeric gel. The system uses a temperature-activated initiator to induce a phase change from a liquid to a solid at predictable times. PermSeal can be used in temperatures from 70° to 200°F (21° to 93°C). The PermSeal service provides conformance control without heavy metal crosslinkers such as chrome. It is acid-resistant and compatible in CO2 environments.

The following water-based polymer systems have successfully limited the flow of produced formation water into the wellbore: •

PermSeal service

•

PermTrol service

•

H2ZeroSM service

•

Injectrol® service

•

Relative permeability modifiers, including Kw-FracSM stimulation service

For production wells, PermSeal is recommended for the treatment of bottomwater coning problems or for treatment of zones with a high degree of permeability variation. For injection wells, PermSeal is used for the treatment of high-permeability streaks in wells with

Table 5.1 shows the various water-control uses for each chemical.

Table 5.1—Recovery Effeciency Problems and Solutions Solutions ®

Problems Producing Wells Acid job went to water Bottomwater coning Bottomwater shutoff Casing leaks Channel behind casing Channel from injector Early water breakthrough Frac job went to water High-permeability streaks No shale barrier Plugging well Seal high-pressure zone Injection Wells Casing leaks Channel behind casing Channel to producer High-permeability streaks Injection out of zone Plugging well Drilling Wells

Injectrol Sealant

PermTrol Service

H2Zero Service

X X X X

X X X X

X X X

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Relative Permeability MOC/One Modifiers X

X X X X

X X X

X X X X

X X X

X X X

X X X

X

X

X X

X X X X X

X X

X X X X

Lost circulation

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PermSeal Service

X X X X

X X X

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channeling problems or for injection out of zone. PermSeal treatment volumes can vary considerably depending on the application. Because the treatment is a porosity-fill-type sealant, engineers can use simple volume-fill calculations to estimate the treatment size.

1000

RRF

PermTrol Service PermTrol service is used in injection wells to treat highpermeability streaks or poor injection profiles for waterfloods and CO2 water-alternating-gas (WAG) floods. To improve waterflood efficiency, operators pump the treatment as a water-thin monomer solution at normal injection conditions to help ensure that the monomer placement is proportional to the amount of injection water entering each zone. After placement, the well is shut in to allow the fluid to polymerize. Once water injection is resumed, the resulting high-viscosity polymer increases volumetric sweep efficiency by diverting injection water from the most highly permeable zones to previously unswept oil-bearing zones. The injection water following a PermTrol service treatment will slowly finger through the thick, watersoluble PermTrol service polymer slug. This water becomes viscous as it solubilizes the polymer, yielding a more favorable water-oil mobility throughout the reservoir. The viscosified water behaves as a polymer fluid treatment with the associated increase in volumetric and unit displacement efficiency. A typical PermTrol treatment volume ranges from 25 to 30% of daily injection. The minimum recommended PermTrol service treatment volume is 4,000 gal or a volume sufficient to provide 5 ft of radial penetration in the net pay interval, whichever is greater.

H2ZeroSM Service H2ZeroSM is a crosslinkable polymer system that forms a rigid gel capable of permanently sealing the target zone, effectively preventing water and gas flow. The H2Zero system can provide the following benefits over chrome-crosslinked gel systems: Depth of Penetration. H2Zero penetrates deeper into the formation than chrome-crosslinked gel systems (Figure 5.1). At temperatures above 158°F (80°C) in matrices containing carbonate, chrome crosslinkers do not remain in solution. As a result, the amount of chrome-complexed gel placed may not provide a sufficient seal. For example, placing a volume of a chrome-crosslinked gel that should be sufficient for extending a 5-ft seal around the wellbore may actually Chapter 5

Gel Damage (RRF) vs. Distance from Injection Face 10000

H2Zero System Test 2

H2Zero System Test 3

100

10

Chrome-crosslinked System Test 1

1 0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

Penetration Depth (ft)

Figure 5.1—Penetration depth of the H2Zero system.

only provide a 3-ft seal, wasting large amounts of gel and money. However, the organic crosslinker in H2Zero sealant remains in solution during injection, resulting in a strong seal throughout the entire treated interval. Temperature Stability. H2Zero is applicable in hightemperature formations. This system can be used at temperatures as high as 320°F (160°C). Chromecrosslinked systems have limited success at temperatures above 225°F (107°C). H2Zero consists of two components: a base polymer (HZ-10) and an organic crosslinker (HZ-20). HZ-10 is a low-molecular-weight polymer solution that can be crosslinked with either organic or metallic crosslinkers. It is an acrylamide copolymer with enhanced thermal stability that forms strong covalent bonds with the system’s organic crosslinker, HZ-20. Because both components of the H2Zero system are in solution, they can be diluted in the mixing brine. Therefore, system formulations can be batch-mixed or blended on-the-fly. The two blended components are placed as a single, low-viscosity fluid (3 to 35 cP) that is thermally activated to form a solid gel. H2Zero can be used for preventing or treating water-management problems or gas-management problems. H2Zero system treatment solutions contain HZ-10 polymer and HZ-20 crosslinker diluted in treatment water. The quality of the treatment design increases with the amount of available information, and treatement designs are based on two interrelated parameters: polymer formulation and treatment volume. Volume requirements are based on how far a gelant must enter into a formation and how much pore space it must fill. Polymer formulation depends on strength requirements and placement times.

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Injectrol® Service Injectrol® service is an internally catalyzed silicate system that achieves intermediate depth-of-matrix penetration. Injectrol is primarily used to decrease water-to-oil ratios and water-injection profiles. The internal catalyst allows operators to pump a low-viscosity solution (1.2 cp) into the formation matrix before the material sets to a stiff gel. The stiff gel formed in the matrix seals the formation pores and diverts or blocks water production. This sealant can be used alone or with a tail-in cement squeeze. When run with the cement, the Injectrol chemical reacts with the cement to become a gel, while the cement hydrates almost immediately. The resulting cement has a high compressive strength near the wellbore where the differential pressure is the highest.

column in the tubing tends to choke off oil flow from the k1 through k3 lenses. Therefore, without an effective correction treatment, such as Injectrol, large volumes of oil can be left in place. Typical reservoir conditions assist the effectiveness of a large-volume Injectrol treatment to correct the bottomwater production described. Usually, vertical permeability is lower than horizontal permeability. As the distance away from the wellbore increases, less pressure drop is available to drive the fluid vertically through the zone. For example, at 40 ft from the perforations, 60% of the pressure drop is lost. Therefore, Injectrol sealant is placed in the bottom few feet of the zone, extending 20 to 40 ft from the casing to form a long-lasting barrier against water production (Figure 5.4).

Example In the well shown in Figure 5.2, the oil is in lenses of varying permeability. Under waterdrive conditions, the k4 lens produces the most volume (oil and some water). Out of the total of 206 barrels of fluid per day (BFPD), 6 bbl is water, all produced from the k4 lens at the bottom. With time, the water production in this well should increase. The harder the well is drawn, the faster the water production increases.

Typical BOPD 50 BWPD 180

k1 < k2 < k3 < k4

k1 k2 k3

In an advanced stage in the life of a waterdrive reservoir, water production through the high-permeability lens dominates (Figure 5.3). Because of its high mobility, water is easily drawn up through the k4 lens. The increased hydrostatic pressure from the water-dominated

k4

Figure 5.3—Secondary oil production from a waterdrive reservoir

k1 < k2 < k3 < k4

Typical BOPD 200 BWPD 6

8 in. k1

Percent of Pressure Drop 30 40 50 55 60

k1 k2

k2

k3 k3 k4

k4 5

Figure 5.2—Initial oil production from a waterdrive reservoir

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10

20

30

40

Figure 5.4—Water production corrected with a largevolume Injectrol treatment

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Treatment Procedure

Relative Permeability Modifiers

A generalized treatment procedure used for all Injectrol systems includes (1) isolating the problem zone if possible, (2) pumping preflush fluids where indicated, (3) pumping the Injectrol® sealant with spacers, and (4) tailing-in with cement slurry (most generally used in producers).

Relative permeability modifiers (RPMs) have properties that help reduce water flow from the treated area of a water-producing zone into the wellbore. In the treated zone of a hydrocarbon-producing layer, the RPMs should result in little or no damage to the flow of hydrocarbon. A universally accepted concept of exactly how RPMs function has not been agreed upon. Although several theories have been proposed to describe the RPM mechanism, detailed testing has indicated that many of these theories are invalid. Perhaps the best explanation is that no single factor determines the success of an RPM. Rather, an RPM’s success depends on many well/ reservoir characteristics, including

Other features common with all Injectrol treatments include (1) low injection rates, (2) injection pressure well below fracturing pressure, and (3) exact displacement into the formation or a small underdisplacement.

Injectrol Sealants and Services By selecting one of three Injectrol catalysts, operators can control the gel time of the Injectrol from a few minutes to several hours at temperature ranges of 60° to 300°F (16° to 149°C).

• chemistry • lithology • problem type

Injectrol G Sealant

• pore-throat size

Injectrol G is a three-component system consisting of an Injectrol concentration, an activator, and water. The activator controls the wide range of gel (pumping) times. The gel times include a temperature range of 70° to 150°F (21° 66°C) BHIT. Pump times of a few minutes to 600 minutes are possible at 74°F (23°C) BHIT. Pump times of a few minutes to 180 minutes are possible at 150°F (66°C) BHIT.

• permeability • saturation • wettability • capillary pressure • adsorption • gravity effects

Injectrol IT Injectrol IT service uses a different activator to provide field-suitable pump times within an injection BHIT range of 120° to 180°F (49° to 82°C). At higher temperatures, the gel quality of Injectrol IT is better than Injectrol G. Injectrol IT can be mixed as a single solution. Because of slight variations in chemicals and mixing waters, engineers must order laboratory-scale tests before making job recommendations to ensure that pump times are accurate. Injectrol U Injectrol U sealant is used only when temperatures of 180°F (82°C) or higher are encountered. It can be successfully used in wells with BHITs as high as 300°F (149°C). The activator for Injectrol U sealant provides widely variable set times and precipitates particles of hard solids when this time has elapsed. Laboratory testing shows it is an effective plugging agent in rock matrices.

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RPMs are primarily applied in layered, heterogeneous reservoirs with distinct barriers between higher permeability hydrocarbon-producing zones (Figure 5.5, Page 5-6). If RPMs are placed in homogeneous zones that produce both water and hydrocarbon, the RPM may tend to decrease both water and hydrocarbon permeability substantially.

Kw-FracSM Stimulation Service Kw-FracSM service combines Halliburton’s RPM technology with Delta Frac service treatments to provide control of produced water resulting from fracture growth into water-productive layers. A special polymer in the prepad portion of the Delta Frac treatment limits water influx into the created fracture during post-treatment production. Because the polymer can alter the relative permeability to water, it is classified as an RPM.

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CONFORMANCE TECHNOLOGY

• Formation brines can be used as a base fluid for diluting the KW concentrate. High Sw

• The treatment can be removed, if desired, with a strong oxidizer such as OXOL II or CAT-1. Kw-Frac service is recommended for reservoirs with permeabilities ranging from 0.1 to 1,000 md, and bottomhole static temperatures (BHSTs) below 200°F.

Shale Streaks

The Kw-Frac system most successfully reduces flow in intervals with high water saturation (Figure 5.6, Page 5-7).

High Sw

Therefore, the most likely candidates for the treatment include the following:

om001402

Low Sw

Figure 5.5—Vertical permeability isolation results in unswept layers with low water saturation.

Reducing the matrix relative permeability to water allows oil-saturated intervals to produce with higher drawdown pressures. The polymer system does not seal the matrix pore throats, and some continued water production should be expected. The Kw-FracSM service uses a special prepad treatment as part of a Delta Frac treatment. A portion of the prepad fluid contains two polymer components, KW-1 and KW-2, that penetrate the created fracture-face matrix and react in situ to form an RPM polymer. The RPM polymer will attach to pore throats in the rock matrix in both sandstone and carbonate reservoirs. The reacted polymer has hydrophilic polymer “branches” that create resistance to water flow in a high-water-saturation matrix. The apparent permeability of the rock to oil or gas is affected very little, but the matrix permeability to water is significantly reduced. The system is compatible with CO2, H2S, and high-salinity brines after in-situ formation of the RPM polymer. The Kw-Frac system has four primary benefits:

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•

Only minor changes to the Delta Frac system are required.

•

No complicated procedures are required for mixing materials on location that can affect the performance of the polymer, such as crosslinking agents or gelling agents.

Treatment Options

• wells with water-coning problems in nonfractured, water-drive, homogeneous reservoirs with high vertical permeability (Figure 5.7, Page 5-7) • layered reservoirs with distinct vertical permeability barriers (Figure 5.5) The system will have the poorest oil production results in wells that have been swept and are producing oil and water through the matrix at high water-saturation levels (Figure 5.8, Page 5-8). Unfavorable results could also occur if the system is used on • wells with interwell communication (Figure 5.9, Page 5-8) • reservoirs with a high mobility ratio, resulting in fingering (Figure 5.10, Page 5-8)

Oxol II RPM Removal System If removal of an RPM is required, Oxol II is recommended. Oxol II treatments break down the backbone of the polymer, reducing the effect of the damage caused by polymer blockages in the pore throats. As a solid, Oxol II service offers several handling advantages. It is safer to work with than comparable concentrated liquid systems, and it has a shelf life of at least one year. Generally, operators run a tubular cleanup ahead of Oxol II treatment to remove as much rust as possible. Oxol II service spends on rust, resulting in lower effective concentrations downhole. Spacers between acids and Oxol II solutions are required. Treatment volumes can range from 50 to 100 gal/ft of net pay. Oxol II cleaner is generally slightly overdisplaced and left in place for 12 to 48 hours.

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KW-Frac Treatment

Low Water Saturation

Oil Flow

Oil Flow

om001405

Transition Zone

Figure 5.6—Under optimum treatment conditions, oil flows through a density-segregated portion of the reservoir that has low water saturation. The treated region resists water flow into the fracture; oil and water flow through the reservoir together only in the transition zone. This condition requires high vertical permeability

Squeeze Cementing Many of the previously described chemical systems can be enhanced with water-based or hydrocarbon-based cement slurries as a tail-in to the chemical treatment. This section describes basic cement slurry designs and provides specific information about MOC/One diesel cement slurry systems.

Low Sw

General Design Principles

High Sw

om001401

Water Coning

Figure 5.7—Good vertical permeability allows density segregation of oil and water

Chapter 5

Two of the most important and useful pieces of information needed for the design of a successful zone isolation cementing treatment are formation pressure and fracturing pressure. With this information, Halliburton can (1) design a cement job that will not lose a large volume of cement slurry into the formation, (2) determine a realistic column height for recementing treatments, and (3) control cement fallback. Pressure buildup and injectivity tests indicate whether a well can hold a full column of fluid.

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5-7

CONFORMANCE TECHNOLOGY

KW-Frac Treatment

High Water Saturation

Oil and Water Flow

om001406

Oil Flow

Figure 5.8—Streaks of high horizontal permeability allow oil and water to flow through the matrix together. No vertical permeability barriers are present. A Kw-Frac treatment would allow oil to flow to the wellbore, but an envelope of high water saturation would result around the treated interval. Over time, lower total production would result

Low Sw

High Sw High Horizontal Permeability Streaks

Interwell Channeling High Sw

Figure 5.9—A high mobility ratio could result in channeling from the injector to the producer, making this formation a poor candidate for Kw-Frac treatment

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Treatment Options

om001404

Low Sw om001403

High Sw

Figure 5.10—In this formation, water and oil are flowing through the reservoir with little vertical permeability isolation. This formation would be a poor candidate for a Kw-Frac treatment

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If a job requires circulating cement into the open annulus, Halliburton uses formation pressure data and a series of “rate-in, rate-out” circulation tests to evaluate (1) perforation location, (2) a realistic cement column height, and (3) the need for additional cleaning, flushes, or the application of ultralight cements. Most commonly, a squeeze job fails because operators fail to place enough slurry in the areas where it could have been effective, and they do not hold the cement in the area long enough to form a permanent seal. The most common contributors to squeeze job failure and fieldproven methods of handling each problem are discussed in the following paragraphs.

Lack of Proper Fluid Control Improper fluid-loss control can result in either a premature squeeze (slurry dehydration) or no squeeze (caused by fluid loss being too low). Either condition can block an uncemented annulus and force cement into the wrong zone or prevent sufficient slurry from entering an injection zone. The degree of fluid-loss control during squeeze jobs depends mostly on the types of fluid-loss additives used in the slurry. Fluid loss can be reduced by large precharge volumes and reactive flushes pumped ahead of the cement.

Improper Perforation Cleanup Many squeeze jobs fail because the perforations were not cleaned properly. For example, if a mud-filled casing is perforated with a pressure differential to the formation, the perforations are likely to be plugged with mud, crushed formation material, and debris. The zone should be tested to ensure cleanliness.

Low Placement Rates A low injection rate simply allows more time for a specific volume of cement slurry to lose fluid and become a solid mass. In effect, the placement rate supplies the time factor for fluid loss.

No Knowledge of Where Cement Is Needed Some squeeze jobs are apparently performed with little more knowledge than the approximate depth of the casing leak. If more than one formation is open in an uncemented annulus, the slurry enters the formation with the lowest fracture gradient, which frequently is not the formation that produced the brine.

Chapter 5

Poor Injection Point Control Slurry entrance into at least one formation is normally required for a successful squeeze treatment. Simply isolating a hole in the casing with packers does not ensure that the slurry can be forced into the formation at that point. In some instances, a zone cannot be successfully squeezed until the uncemented annulus below it is blocked.

Effect of Bottomwater If naturally induced fractures extend into lower zones, bottomwater control problems will occur. To combat bottomwater, Halliburton may recommend injecting a low-viscosity, temporary blocking material into the upper zone before squeezing the bottom zone. The success ratio of this type of treatment is greatly improved when reactive preflushes are used ahead of the cement.

Crossflow High-volume water flow in an uncemented annulus (often referred to as crossflow) can dilute a cement slurry until it can no longer seal effectively. To control this condition, operators must eventually squeeze off the brine-producing zone with treatment pressures greater than the producing-zone pressure. If a weak zone is open in the same uncemented area, special materials, such as foam cements, thixotropic cements, and reactive preflushes may be needed. A multiple-stage cement job with selective injection can also prevent crossflow if the slurry injection points can be controlled.

Poor Bonding Poor bonding to the formation is common in salt formations. Salt-saturated slurries are necessary for good bonding, but these slurries can have long thickening times and may set at low to moderate temperatures. This dual problem can complicate squeeze procedures. The slurry must remain static from the placement time to the initial set time. High-pressure water can easily enter and disrupt the integrity of a cement during its transition from a fluid to a solid.

Cement Flowback When pumping stops, the downhole pressure is initially equal to the hydrostatic pressure and any remaining surface pressure. If no squeeze pressure is obtained, some formations continue to take slurry until the hydrostatic pressure is equal to the fracture extension pressure. As the cement gels and fluid is lost from the slurry (to permeable

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5-9

CONFORMANCE TECHNOLOGY

formations), the pressure in the cement rapidly decreases. This pressure decrease allows gas or brine to enter the cement column, migrate upward, mix with the cement slurry, or form-flow channels for the brine or gas. Foam cement, Gas-Chek, GasStop, and thixotropic cements can often effectively control this phenomenon.

Multiple Injection Zones Difficulties of squeezing more than one area with a single job are mostly self-evident. However, treating multiple injection points or paths in a single zone is less understood. For instance, a reactive preflush or pad ahead of the slurry can result in complete blockage of one flow path, yet the following slurry meets very little added restriction and no squeeze pressure is evident. This condition is best solved with either multiple-stage squeeze jobs with a Flo-Chek® component preflush ahead of each stage or treatment with a large volume of an Injectrol® solution that reacts with the formation brine and has time-dependent gelation.

MOC/One Cement The one disadvantage of using DOC as a treatment method is that the standard cement’s larger particle size (up to 120 µm) limits its penetration into the leak. As a result, a job may have to be repeated several times before it is even marginally successful. In these situations, the use of the MOC/One service could provide more positive results. MOC/One consists of Micro Matrix cement, diesel or kerosene, and MOC-A surfactant. MOC-A, when used at the recommended concentration by volume of diesel, yields a densified slurry, which when contacted by water, delivers a lowpermeability slurry with high compressive strength. With a maximum particle size of 10 µm or less, Micro Matrix cement can penetrate areas in the wellbore and surrounding formation that would otherwise be inaccessible. When this cement is used, MOC-A is necessary to prevent the immediate oil-wetting of the ultrafine cement. Like a standard DOC slurry, the ultrafine, hydrocarbon-based slurry only sets when it contacts mobile water. Since ultrafine slurries have a delayed gelation, however, they usually penetrate fractures more deeply before they set. The system can be used up to temperatures of 400°F (204°C). For example, a well with an initial production of 10 BOPD and 300 BWPD was first treated with hydrocarbon-based, standard cement. Only 470 to 940 lb of

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Treatment Options

standard cement could be placed in the formation, and water production did not decrease. A 4,000-gal, complexed polyacrylamide treatment was then placed in the zone. Again, water production remained the same. Eventually, production increased to 10 BOPD and 600 BWPD. At this time, operators placed 2,500 lb of ultrafine cement in a diesel slurry behind a 1,500-gal MOC-A treatment. After two months, the well stabilized at 17 BOPD and only 200 BWPD. When MOC-A contains 20 gal/Mgal of hydrocarboncarrying fluid, the resulting Micro Matrix cement slurry has a delayed gelation that allows it to be placed into water-bearing formation fractures some distance from the wellbore. The small size of the Micro Matrix cement also allows for placement into near-wellbore microchannels that may be communicating with adjacent water-bearing formations.

Conclusions Once a treatment design has been established, engineers must determine the proper placement technique for optimal treatment results. Chapter 6 provides information regarding placement methods and mechanical equipment.

Bibliography Advances in Well Test Analysis, SPE Monograph Vol. 5, Page 86. Avery, M.R. and Sutphen, J. A.: “Field Evaluation of Production Well Treatments in Kansas Using a Crosslinked, Cationic Polymer Gel,” presented at the 8th University of Kansas Tertiary Oil Recovery Conference, Wichita, KS, March 8-9, 1989. Bonifay, W.E., Wheeler, J.G., and Garcia, J.G.: “Cementitous Compositions and Method,” U. S. Patent 5,071,484, Dec. 10, 1991. Broussard, G.L., et al.: “Fluid Loss Control Using Crosslinkable HEC in High-Permeability Offshore Flexure Trend Completions,” paper SPE 19752 presented at the 1989 SPE Annual Technical Conference and Exhibition, San Antonio, TX, Oct. 8-11. Clampitt, R. L., Al-Rikabi, H. M., and Dabbous, M. K.: “A Hostile Environment Gelled Polymer for Well Treatment and Profile Control,” paper SPE 25629 presented at the 8th Middle East Oil Show and Conference, Manama, Bahrain, April 3-6, 1993.

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Clarke, W.J.: “Formation Grouting Method and Composition Useful Therefor,” U.S. Patent 5,106,423, April 21, 1992. Cole, R.C. and Lindstrom, K.: “Well Integrity Maintenance Using Pumpable Sealants,” presented at the 1987 Underground Injection Practices Council International Symposium, New Orleans, LA, May. Cole, R.C. et al.: “Chemical Process Seals Leaks in Injection Wells,” presented at the 1987 Southwestern Petroleum Short Course, Lubbock, TX, April. Crook, R.J., Lizak, L.F., and Zeltmann, T.A.: “Permian Basin Operators Seal Casing Leaks with SmallParticle Cement,” paper SPE 23985, presented at the 1992 Permian Basin Oil and Gas Recovery Conference, Midland, TX, March 18-20. Dahl, J. and Harris, K.: “Uses of Small Particle Size Cement in Water and Hydrocarbon Based Slurries,” presented at the 1991 9th Tertiary Oil Recovery Conference in Wichita, KS, May. Dalrymple, D., Maughmer: “Treatment Helps Decrease Water and Reduce Costs,” American Oil and Gas Reporter (June 1992) 114. Dalrymple, D., Sutton, D., and Creel, P.: “Conformance Control in Oil Recovery,” presented at the 1985 Southwestern Petroleum Short Course, Lubbock, TX, April. Dalrymple, E. D. et al.: “A Selective Water Control Process,” Presented at the 1992 Rocky Mountain Regional SPE Meeting in Casper, WY, May 18-21. Dalrymple, E.: “Two Stage Treatment Reduces Water/Oil Ratio,” Oil & Gas J (Sept. 10, 1990) 73. Dawson, D.D. Jr. and Goins, W.C. Jr.: “Bentonite-Diesel Oil Squeeze,” World Oil (Oct. 1953) 222. Ewert, D.P., Almond, S.W., and Bierhaus, W.M.: “Small Particle Size Cement,” paper SPE 20038, presented at the 60th California Regional Meeting, Ventura, CA, April 4-6, 1990. Ewert, D.P. et al.: “Squeeze Cementing,” U.S. Patent 5,121,795, June 16, 1992. “General Rules and Regulations of the Oil and Gas Conservation Division,” Oklahoma Corporation Commission, 1986 Edition. Great Britain Patent 2,099,412A, U. S. Patent 4,466,831, Canada Patent 1,201,274.

Chapter 5

Hanlon, D. J., Fulton, S., and Beny, M.: “New Chemical and Mechanical Technology for Injection Profile Control,” presented at the 1987 Southwestern Petroleum Short Course, Lubbock, TX, April. Harris, K.L. and Johnson, B.J.: “Successful Remedial Operations Using Ultrafine Cement,” presented at the 1992 Mid-Continent Gas Symposium, Amarillo, TX, April 13-14. Harris, K.L. et al.: “Repairing Leaks in Casings,” U.S. Patent 5,123,487, June 23, 1992. Harris, S.H.: “Control of Water Production Using CrossLinked Polymers,” 1988 United States Dept. of Energy Improved Oil Recovery Conference, Abilene, TX, Sept. 11-13. Heathman, J.F. and East, L.E. Jr.: “Case Histories Regarding the Application of Microfine Cements,” paper SPE/IADC 23926 presented in 1992 in New Orleans, February 18-21. Herring, G.D., Milloway, J.T., and Wilson, W.N.: “Selective Gas Shut-Off Using Sodium Silicate in the Prudoe Bay Field, AK,” paper SPE 12473 presented at the 1984 Formation Damage Control Symposium, Bakersfield, CA, February 13-14. Himes, R.E. and Sandy, J.M.: “A New Crosslinkable HEC—Its Application in Completion Work,” presented at the 6th Offshore Southeast Asia Conference, Singapore, Jan. 28-31, 1986. Himes, R.E. et al.: “Low Damage Fluid Loss Control for Well Completions,” paper SPE 22355 presented at the 1992 International Meeting on Petroleum Engineering, Beijing, March 24-27. Hower, W.F. and Montgomery, P.C.: “New Slurry Effective for Control of Unwanted Water,” Oil and Gas Journal (Oct. 19, 1953). Koch, Ronney R. and Diller, John E.: “An Economical Large Volume Treatment For Altering Water Injectivity Profiles,” Paper No. 851-40-A American Petroleum Institute Division of Production. Koch, Ronney R. and McLaughlin, Homer C.: “Field Performance of New Technique for Control of Water Production or Injection in Oil Recovery,” paper SPE 2847 presented at the Practical Aspects of Improved Recovery Techniques Meeting in Fort Worth, TX, 1970.

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CONFORMANCE TECHNOLOGY

Kohler, N. et al.: “Weak Gel Formulations for Selective Control of Water Production in High-Permeability and High-Temperature Wells,” paper SPE 25225 presented at the 1993 Oilfield Chemicals International Symposium, New Orleans, March 2-5. Lange, K.R. and Weldes, H.H.: “Properties of Soluble Silicates,” Ind Eng Chem (April 1969) 61, 29-44. Maughmer, R.E. et al.: “Cement System Reduces Water Production,” The American Oil and Gas Reporter (May, 1992) 114. McKown, K. et al.: “Strategies for Obtaining Effective Injectivity Patterns,” presented at the 1987 University of Kansas Tertiary Oil Recovery Project, Lawrence, KS, March. McLaughlin, Homer C., Jewell, Robert L., and Colomb, Glenn R.: “A Low Viscosity Solution For Injectivity Profile Change,” Paper No. 851-41-1 American Petroleum Institute Division of Production. Meek, J.W. and Harris, K.L.: “Repairing Casing Leaks Using Small-Particle-Size Cement,” paper SPE/IADC 21972, presented at the 1991 SPE/IADC Drilling Conference, Amsterdam, March 11-14. Messenger, J.U.: “Lost Circulation Techniques Can Solve Drilling Problems, Part 3,” Oil and Gas Journal (1968) 66, No. 22, 94-98. Messenger, J.U.: “Lost Circulation,” PennWell Publishing, 16-18, 21-22, 33, 35, 56, 58, 60-63, 70-77.

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Murphey, J.R.: “Rapidly Dissolvable Silicates and Methods of Using the Same,” U. S. Patent No. 4,521,136 (1981). Murphey, J., Young, W., and Oberpriller, F.: “Treatment of Lost Circulation and Water Production Problems with a Powdered Silicate,” CIM 82-33-46 presented at the 1982 33rd Annual Meeting, Calgary, Alberta, June 6-9. Quarnstrom, T.F. and Cavender, T.W.: “Fluid Loss to Formation Stopped Before Gravel Packing,” Technology, Oil & Gas J (1989) Sept. 25, 101. Ramos, Joe, and Hower, Wayne F.: “Selective Plugging of Underground Well Strata,” U. S. Patent 2,837,163 (June 3, 1958). Rensvold, R.F., Ayres, H.J., and Carlile, W.C.: “Recompletion of Well to Improve Water-Oil Ratio,” paper SPE 5379 presented at the 45th Annual California Regional Meeting, Ventura, CA, April 2-4, 1975. Smith, C.W., Pugh, T.D., and Bharat, M.: “A Special Sealant Process for Subsurface Water,” presented at the 1978 Southwestern Petroleum Short Course, Lubbock, TX, April 20-21. Wood, F. et al.: “Converting a Producing Well to an Injection Well in the State of Kansas,” presented in 1987 at the University of Kansas Tertiary Oil Recovery Project, Lawrence, KS, March.

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Chapter 6 Placement Techniques Placement techniques used in treating unwanted water and/or gas production should be chosen on a well-by-well basis. This section discusses placement differences between injection and production wells, the nature of fluid movement, and the following placement methods: • bullheading • mechanical packer placement/ inflatable packer placement • dual-injection placement • chemical packer placement • isoflow placement • transient placement

Placement in Injection vs. Production Wells Injection Wells Treatment placement in injection wells is relative to the ongoing water, steam, CO2, water-alternating-gas (WAG), or other flooding method used to maintain formation pressure, replace volumetric removal, and sweep the reservoir to the best mobility efficiency. To alter the indepth injection profile of these wells, engineers strive to change the flow throughout the reservoir to modify existing inefficient patterns or paths.

Chapter 6

Generally, the conformance-control treatment is performed based on the same injection method (pressure-rate) currently used on the well. If possible, even the fluid used should be similar to the one used to flood the well. Logically, if the same injection method and fluid are used, the treatment should enter the formation in the same path. The injection pressure must remain below parting pressure; if injection pressure approaches fracture initiation pressure during treatment, a rate decrease will be necessary. Although results are rarely immediate, treatments of injectors can have a significant effect on the long-term production and the ultimate volume of oil produced from a reservoir.

Placement Techniques and Equipment

Production Wells Generally, placement in production wells is based on the idea that an aqueous fluid will enter the formation in the same area through which an aqueous fluid is being produced. For example, once produced water has broken though, the mobility ratio of the aqueous solution in the waterbearing strata is much more favorable than the mobility ratio of the aqueous solution in the oil-bearing strata. As a result, at reasonable pressures and rates, the solution treatment should preferentially enter the waterproducing portion of the zone.

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6-1

CONFORMANCE TECHNOLOGY

Controlling Fluid Movement To effectively use the conformance technology processes available, engineers must consider the following conditions: •

•

•

Unless the formations are highly stratified with little or no vertical permeability and no random fracture systems, the corrective materials must penetrate deeply into the formation to influence fluid flow for a significant time in injection or producing wells. The best fluid to perform deep formation placement is a low-viscosity, solids-free fluid that improves mobility or has a high resistance to extrusion in a controlled manner. When injection wells are treated at less than parting pressure with a fluid that has viscosity comparable to the floodwater viscosity, selective injection may result. The rate and pressure of injection should be maintained at or less than the rate and pressure of injection of the floodwater. The same may hold true for producing wells if the fluid is comparable to produced water, and fracturing rates and pressures are avoided.

To prevent uncrosslinked polymer from entering the formation, operators must hold the polymer fluid in the mixing container until the crosslinking reaction is well underway. If crosslinking is completed before the material is pumped out of the blender, it will still be pumpable and control fluid loss when placed. The crosslink reaction rate depends on a variety of factors, such as brine type, brine weight, and polymer fluid temperature. Usually, higher-weighted solutions have a faster complexation rate. The rate is fluid/temperature-dependent. A warmer polymer fluid crosslinks faster than a cooler one. As the polymer fluid is heated by the formation temperature during placement, the reaction rate accelerates. When coiled tubing is used to place K-Max, the friction pressures through the smaller-diameter coiled tubing restrict the gel concentration of the K-Max treatment. Under these conditions, a 60-lb/Mgal formulation is recommended. Pumping rates are restricted by the pressure rating on the tubing (a maximum of approximately 0.5 bbl/min is expected for 1 1/4-in. tubing). Figure 6.1 (Page 6-3) shows typical friction pressures through coiled tubing.

Bullheading K-MaxSM Service The K-MaxSM service is a water-based polymer system that can limit the flow of produced formation water into the wellbore. K-Max service involves the use of a crosslinkable hydroxyethyl cellulose (HEC) in the form of a liquid gel concentrate (LGC). K-Max forms a highly complexed gel downhole that prevents completion or treatment fluids from flowing into the isolated areas. Specifically, K-Max is used as a temporary pill to shut off production or injection at various depths. This application allows engineers to pinpoint water- or gas-producing zones and determine production effects that might occur after the zone is treated. The K-Max base fluid is mixed, hydrated, and allowed to partially or fully crosslink on the surface before it is pumped. The fluid is allowed to complex fully before final placement of the uncrosslinked polymer into the formation matrix. K-Max service fluid can be prepared in brines having density ranges from 8.33 to 15.2 lb/gal of fresh water. These brines include KCl, NaCl, NaBr, CaCl2, NH4Cl, seawater, and CaCl2 - CaBr2. Brine formulations and polymer fluid mixing procedures must be strictly observed.

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Placement Techniques and Equipment

The simplest, most economical treatment placement method is the bullheading technique, in which operators inject the treatment through existing tubulars. This technique can be used effectively for entry into zones that will take 100% of fluids or for entry into perforations where a permeability decrease is necessary. Bullheading is seldom recommended, however, because without zonal isolation, the treatment may seal not only the intended water zone but the oil zone as well. Figure 6.2 (Page 6-3) shows a bullhead treatment that has sealed both zones. Bullheading can be performed with slickline tool isolation, sand plugs, etc. To design an effective placement procedure and responsive treatment, engineers must carefully consider well conditions and reservoir characteristics. Specifically, they must analyze injectivity profiles and perform a multi-rate injection analysis to determine variances in entry that are associated with variances in injection pressures/rates. The possibility of static condition crossflows that might continue after placement should also be considered. The profile entry logs generated during these tests are visuals for near-wellbore entry only, and analysts must always consider the possibility that conditions may differ deeper in the formation.

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Friction Pressure (psi/ft)

10

1.0

ax

gal K-M

90 lb/M

ax

gal K-M

60 lb/M

0.1 10

20

30

40

50

60

70

80

Flow Rate (gal/min)

Figure 6.1—Typical friction pressures through coiled tubing.

Cement

Oil Zone

Water Zone

Injection profile entries for wells can often change over the life of a well. For example, damage such as scaling, paraffin buildup, and plugging caused by fines can divert fluid movement. Frequently, this damage is actually an asset to treatment placement, because it prevents treatments from entering into possible preferred flood intervals. Once the solution treatment is in place, this damage can be removed through stimulation. If available, computer simulators can also interpolate pressure responses. Specifically, engineers can use the maximum bottomhole injection pressure (BHIP) determined during the multi-rate injection/profile analysis to establish the limits for a treatment.

Figure 6.2—Bullhead placement technique.

Chapter 6

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6-3

CONFORMANCE TECHNOLOGY

Mechanical/Inflatable Packer Placement Cement

For added control, operators can use mechanical packers, bridge plugs, or selective zone packers to isolate perforations or a portion of an openhole completion into which a treatment will be placed (Figure 6.3). This method protects critical perforations in the adjacent oil sands from sealant invasion. When selecting tools, engineers should consider how the treatment materials could affect the performance of the tool. Depending on the circumstances, the tools could also be left in the well as a control for injection or production. To determine the packer’s degree of placement control on the zone, engineers must test for injectivity and communication aspects.

Dual-Injection Placement When performing dual-injection placement (Figure 6.4), operators use the well’s tubulars to inject fluids down the tubing and down the annulus. Packers, bridge plugs, sand plugs, chemical plugs, chemical packers, and other mechanical means are usually used with this technique. By isolating intervals with tools or covering intervals with sand backfill, operators can more accurately target the preferred treatment intervals. The dual-injection placement technique offers efficient placement control. To protect critical perforations in the adjacent hydrocarbon-producing zone from the treatment solution, operators inject a nonsealing fluid that is compatible with the formation. Frequently, the fluid used to protect the adjacent intervals from the influx of treatment solution is reactive to the sealant fluid. Therefore, when the treating pressure increases, the fluid interface builds a reacted seal between the formation intervals, creating a barrier that may allow the treatment to be placed farther into the formation. Ideally, dual-injection placement directs fluids along the interface away from the wellbore and far enough into the formation to change the injectivity or the production. After considering the density, viscosity, and frictional pressure differences of the two injection streams, engineers normally equalize the BHIP to control placement when using this technique. Dual-injection placement techniques can also be designed based on injectivity profiles and multi-rate injection analyses used for determining variances in entry associated with variances in injection pressure/rates. The profile analysis can provide percentages of fluid entry throughout the entire interval and can help analysts determine the

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Placement Techniques and Equipment

Oil Zone

Water Zone

Figure 6.3—Mechanical packer placement technique.

Compatible Nongelling Fluid

Oil Zone

Sealant

Sealant Water Zone

Figure 6.4—Dual-injection placement technique.

tubular and annular rates for performing a dual-injection placement technique. The possibility of static condition crossflows or transient flow that might continue after placement can be determined by profile analysis, but the profile entry logs generated during these tests only apply to near-wellbore entry; conditions deeper in the formation could differ. If pressure responses vary from the initial analysis, the control materials could be placed into the wrong interval. Operators can also use dual-injection techniques to place treatments in which two incompatible fluids must be pumped separately into the well through the tubing annulus before they are injected into the interval. If the two systems cannot be mixed and pumped through the tubing annulus from the surface, they are pumped separately down the tubing and intermixed at the treatment interval.

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Chemical Packers In gravel-packed or openhole completions, mechanical packers or straddle systems cannot provide the isolation that is required for placing a treatment into the selected zone. To overcome this problem, chemical systems have been developed that can temporarily or permanently isolate a section of open hole behind the slotted screen or gravel-pack screen. For example, in a horizontal open hole with a slotted liner, zones exist that should be protected above and below the water-producing zone. Chemical packers can be placed in the annulus above and below the zone to be treated. Once in place, a mechanical system can be used to isolate inside the liner to allow the upper and lower zones to be properly sealed, and coiled tubing can be used to place the conformance treatment between the chemical packers.

Isoflow Placement When using the isoflow placement technique (Figure 6.5), operators direct the treatment solution into the selected interval(s) while protecting the hydrocarbon-producing or hydrocarbon-bearing zone by simultaneously injecting a nonsealing, formation-compatible fluid that contains a radioactive “tag” down the annulus. Before the treatment is run, a gamma-ray detection tool is run down the well inside the tubing and placed at the interface between the upper nonsealing and lower sealing point in the well. During the initial analysis and sometimes during the sealant placement, engineers analyze the output from the tool to regulate tubing and annulus pump rates. To adjust the location of the interface, operators can manipulate the pump rate of the tubing and annulus fluids.

Radioactive Compatible Fluid

During normal isoflow placement operations, the sealing solution is placed at a rate based on daily injection. This rate should be proportional to the interval’s percentage of fluid entry based on profile analysis. Before placement, engineers must also consider differences in each chemical’s viscosity and density. When adjusting to maintain the location of the fluid interface, engineers should use only the annular fluid’s rate if possible. The tubular fluid should remain constant. To save time, operators generally spot the annular fluid down near the preferred interface before the analysis is performed, because annular volumes are based on the daily injection volume for the upper interval. Rate adjustments can control the interface during treatments. As the location of the fluid interface is being tracked, rate, not pressure, controls these jobs; pressure restrictions of the casing are the only pressure consideration. To locate the interface and track the stationary injectivities for each annular rate adjustment, operators can move the gamma-ray logging tools to different locations in the wellbore. The isoflow method is uniquely suited to wells with negative surface pressures and wells in which the fluid stands static when they are shut in. On wells that flow back and have a charged-up bottomhole pressure, engineers may recommend the isoflow method to perform tests that will establish the appropriate rates for conducting a conformance job. This solution treatment should be performed with a stripper for the casing and a downhole flapper valve for the tubing, which both serve to negate the use of gamma ray tools and interface analysis during the actual treatment. If the treatment solutions do not cause a problem with the removal of the tubular from the well, the jobs are performed as in static-condition wells or low-pressure, vacuum-pressure injection wells.

Transient Placement Wireline

Oil Zone

Gamma Ray Logging Tool Sealant

Sealant

When the injectivity profile and shut-in crossflow on many wells are analyzed, it may become apparent that the well could produce fluid during static conditions from one interval into another. The analysis may also indicate that the well may be crossflowing at a particular rate from other intervals while injection is being performed at a particular rate. Once a sufficiently high rate is established, these wells may not show a crossflow.

Bottomwater Production

Figure 6.5—Isoflow placement technique.

Chapter 6

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6-5

CONFORMANCE TECHNOLOGY

Transient placement techniques (Figure 6.6) use crossflow to help eliminate entry into unwanted intervals as treatments are injected into the zones that will be sealed. The fluids from the treatment and crossflow are allowed to intermix in this placement procedure.

Cement

Crossflow from Interval

While designing treatments, engineers must perform tests to determine if compatibility and sealant concentration will seriously affect the treatment. For example, since transient flow and injection flow intermixing will occur, engineers must analyze injectivity profiles by performing multirate tests to determine the concentration of the treatment solution fluid.

Sand Plugback Fill

Service Equipment

Figure 6.6—Transient placement technique

Halliburton uses a variety of equipment to place and monitor conformance technology treatments. This equipment includes process monitoring and control systems, treating-fluid filtration systems, mixing systems, and high-pressure pumping systems.

Mixing and High-Pressure Pumping Systems

This section describes some of the different types of Halliburton equipment available for this service.

Monitoring Systems Halliburton’s INSITE™ for Stimulation portable data acquisition system (Figure 6.7, Page 6-7) is an IBM® PC-compatible laptop computer that records and processes data from proprietary data acquisition hardware. The basic INSITE for Stimulation system can monitor one density input, one temperature input, three pressure inputs, and three flow inputs. While monitoring the basic transducer inputs, the system can simultaneously acquire up to 80 different pressures, flows, temperatures, and densities from multiple remote digital panel meters, such as Halliburton Unipros.

Filtering Systems Several filtering systems are available for cleaning treating fluids. Figure 6.8 (Page 6-7) shows a lowpressure diatomaceous earth filter that can filter fluids at rates as high as 15 bbl/min. High-pressure filters that can withstand pressures up to 10,000 psi with a maximum flow rate of 2 bbl/min are also available.

6-6

Tubular and Crossflow Placement

Placement Techniques and Equipment

Mixing and high-pressure pumping systems are available as individual, standalone systems or as integrated systems that have been combined and mounted on a skid, truck, or trailer. Halliburton mixing systems incorporate the latest technology in high-energy mixing with computer controls. Fluids can be mixed continuously while being pumped downhole, or they can be mixed in batches before pumping.

Pumping Equipment Example The HCS Advantage skid (Figure 6.9, Page 6-7) has mixing and high-pressure pumping capabilities. This unit incorporates the RCM® II mixing system. This mixing system uses Halliburton’s patented Axial Flow Mixer (Figure 6.10, Page 6-8) and microprocessor-based control system. The unit has a 25-bbl tank that can be used as part of a continuous mix system or as part of a batch-mix system. It also includes Halliburton’s high-pressure HT400 pumps. The CMR-100R (Figure 6.11, Page 6-8) batch-mixing trailer contains two 50-bbl tanks and the RCM® II mixing system. This unit is suitable for mixing batches up to 100 bbl.

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Chapter 6

Figure 6.7—INSITE for Stimulation Portable Data Acquisition System

Figure 6.8—Halliburton Filtering System

Figure 6.9—Halliburton HCS Advantage Skid

Chapter 6

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Placement Techniques and Equipment

6-7

CONFORMANCE TECHNOLOGY

Bulk Cement

Bulk Cement Control Valve Bulk Cement Inlet

Mixing Water

H2 O

R/A Densometer

Recirculating Fluid

Turbine Agitator

Vent

Rubber Splash Sheath Screen

Slurry to Displacement Pumps

Recirculating Centrifugal Pump

Diffuser

Figure 6.10—RCM® Axial Flow Mixer flow schematic

Figure 6.11—Halliburton CMR-100R Batch-Mixing Trailer

6-8

Placement Techniques and Equipment

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Chapter 6

Coiled Tubing The coiled tubing unit (CTU) (Figure 6.12) is a selfcontained, easily transported, hydraulically powered workover unit that injects and retrieves a continuous string of tubing into a larger string of tubing or casing. The unit can be used on live wells and allows operators to inject fluids or nitrogen while continuously moving the pipe. When used to place conformance treatments, coiled tubing has the following advantages: • Coiled tubing isolates treatment materials from contaminants in the tubulars.

To prevent the treatment fluid from flowing past the proper point, operators can use inflatable straddle packers, single packers, and bridge plugs. Inflatable straddle packers can be used in selective chemical treatments for water-zone shutoff or for squeeze cementing or locating leaks. Inflatable packers can be used for selective chemical treatments, cement squeeze jobs, and zonal isolation in horizontal wells. Inflatable bridge plugs can be used to temporarily shut off water production from lower zones, or for selective chemical treatments or selective squeeze cementing.

Conclusions

• Because of the smaller tube capacity, required pumping times are shorter.

After the selected treatment has been placed in the hole, engineers must perform tests on the well to determine the success of the treatment. Chapter 7 provides conformance treatment evaluation methods and calculations.

• Treatments can be more accurately placed. • The smaller diameter of coiled tubing minimizes the intermixing of the staged treatments.

Figure 6.12—Halliburton Coiled Tubing Services

Chapter 6

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Placement Techniques and Equipment

6-9

Chapter 7 Introduction Engineers can evaluate conformance treatments using many of the same techniques that they initially used to identify the problem, including well logs, production logs, well testing, downhole video, reservoir description, reservoir monitoring, production performance, tracer surveys, and field-wide reservoir simulations. These topics were covered in detail in Chapters 2 and 3. This chapter briefly discusses the following additional methods that can be used as a part of a treatment evaluation: • • •

numerical methods production data injection well data (Hall plots)

Numerical Methods To properly quantify the effect of a treatment, engineers must carefully evaluate sophisticated well test data and use numerical simulation programs. Well test data evaluation programs simplify the complex results gained from numerical simulators to several equations. These equations include a mathematical definition of rate, pressure, and time behavior in dimensionless form and account for flow-rate variation based on the principle of superposition. A matching algorithm modifies the reservoir model parameters to provide calculated pressures that match those recorded during the well test.

Chapter 7

The time required for a numerical simulation is directly proportional to the number of factors that will be considered. The more factors involved in the test, the more computer time will be required. Other factors that can greatly complicate numerical solutions include reservoir boundaries, aquifer influence, gas cap, layering, partial penetration, and heterogeneities.

Conformance Treatment Evaluations and Calculations

Production Data Production data provide an accessible source of information for evaluating conformance projects. Comparisons of water-oil ratio, gas-oil ratio, oil production rate, and wellhead pressure and temperature data to pretreatment values can provide quantitative means of evaluating treatment success.

Injection Well Data (Hall Plot) If the cumulative volume of injected fluid and a good record of injection pressures are both available, engineers can use a Hall plot to evaluate injection well performance. This method assumes a series of steady-state injections, which means that dimensionless pressure, pD, is time-independent. This assumption is valid only as long the pressure transient has not encountered external boundaries, fluid contacts, and reservoir heterogeneities, and the rate variation is not frequent. The Hall plot provides an acceptable approximation over a reasonable period and is a simple means of monitoring injection-well performance.

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7-1

CONFORMANCE TECHNOLOGY

Based on the constant pD assumption, Eq. 7.1 can be derived: Eq. 7.1

reflects conditions after the conformance treatment. This slope should be greater than the slope of the first line, mH1, which reflects pretreatment conditions. To evaluate injection performance before and after a conformance treatment, engineers can estimate the ratio of the new flow efficiency to the old flow efficiency: Eq. 7.4

where ptf = wellhead pressure in the injection well, psi pe = reservoir pressure, psi ∆ρtw = hydrostatic pressure inside the wellbore, psi t = injection time, D Bo = formation volume factor, RB/STB µ = injected fluid viscosity, cp s = skin factor k = permeability, md h = formation height, ft Wi = the cumulative water injected, STB When (pe - ∆ρtw)t is small compared to the integral, a plot of this integral, commonly approximated by the summation, Σptf ∆t, vs. cumulative water injected, Wi, will result in a straight line, the slope of which is given by Eq. 7.2

For a radial flow pattern, Equation 7.2 changes to Eq. 7.3

where Ef1 = old flow efficiency Ef2 =new flow efficiency A successful conformance treatment results in a flow efficiency ratio less than 1. The skin resulting from the treatment, s2, can be calculated from Eq. 7.5

where s1 is the pretreatment skin value. A wellbore will have a higher skin value after a successful conformance treatment. In addition to reflecting changes in permeability around the wellbore, this higher skin value also reflects changes in fluid properties and offset production, and the accumulation of skin damage on the wellbore face. The value of k/µ used in Eqs. 7.1 through 7.3 and Equation 7.5 is determined from conventional well tests, such as a pressure buildup test.

where Bo = formation volume factor of injected fluid, RB/STB re = drainage radius, ft rw = wellbore radius, ft If re/rw is known and s has been determined through a pressure transient test, k/µ can be estimated from Eq. 7.3. Likewise, if k/µ has been determined through a pressure transient test and re/rw is known, s can be estimated. When a successful conformance treatment has been performed, the graph should display two straight-line portions with the slope of the second line, mH2, which

7-2

Conformance Treatment Evaluations

Treatment Placement Calculations The modified Hall plot provides a method for monitoring the effectiveness of a permeability reduction treatment. The following is a step-by-step procedure for placing a treatment using the modified Hall plot technique. 1.

Plot cumulative injection pressure (psi) with respect to time (Σptfdt) on the y axis, vs. cumulative injection volume in bbl (on the x axis). Determine the slope of the best-fit straight line through the data. Calculate the current skin factor for the well from:

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Chapter 7

Estimate the depth of polymer penetration, rp, from: Eq. 7.8 d.

Eq. 7.6

where:

2.

3.

s1 = initial skin factor, mH1 = slope of the best fit line, psi-D/bbl, k = formation permeability, md, h = height of open interval, ft, Bo = formation volume factor of produced or injected fluid, RB/STB, m = fluid viscosity, md, re = drainage radius, ft, and rw = wellbore radius, ft. Perform a step-rate test on the well, and plot the data as ptf (y axis) versus injection rate (x axis). Fluid entry into the lower permeability zones is indicated by changes in the slope of the plotted data. Calculate the ratio of the slope of first straight line portion to the slope of the second. The step-rate test can be performed during the preflush stage of the treatment. During placement of the polymer, create a Hall plot for the treatment. For each data point taken, a. Plot Σptfdt in psi-D (on the y axis) versus cumulative injection volume in bbl (on the x axis) on the graph. b. c.

Determine the slope of the plot at the data point. Using the slope determined in Step 3b and the slope and skin factor determined in Step 1, calculate the current skin factor from: Eq. 7.7

where: frr = residual resistance factor. (Note: Determine frr in the laboratory using formation samples and the treatment polymer.) e.

Determine the ratio of mH2 for the current point to the initial value of mH2 for the treatment. If this value equals or exceeds the slope ratio determined for the step-rate test of Step 2 before the required penetration radius is reached, go to the flush/overdisplacement stage of the treatment. Such a slope ratio change indicates fluid entry into the lower-permeability portion of the interval.

Pressure-Transient Testing to Determine Treatment Volume Given any two of (1) treatment volume, (2) degree of mobility reduction, or (3) resulting skin damage, the third factor can be calculated, if formation porosity and height are known. This is seen through the following relationships. Assuming uniform invasion of the treatment polymer and a penetration radius much greater than the wellbore radius, the volume of polymer treatment injected, Vp, can be volumetrically related to penetration radius, rp, from: Eq. 7.9

or, equivalently, Eq. 7.10 where: s2 = skin factor at current data point, mH2 = slope at current data point, psi-D/bbl, B = formation volume factor of polymer fluid, RB/STB, and µ = viscosity of treating solution, cp.

Chapter 7

where φ is the formation porosity, and h is the height of the treated formation. Skin factor, s, is related to the penetration radius and the mobility of the treated zone, (k/µ)p by:

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7-3

CONFORMANCE TECHNOLOGY

Eq. 7.11

Where (k/µ) is the initial reservoir mobility and rw is the wellbore radius.

pressure lower boundary on the formation. In the simulations, the well is put on production. Then the time the bottom boundary is detected at the wellbore is observed. Plots of water breakthrough time versus rp or Vp/fh for several reduced mobility ratio values can be generated. Eq. 7.10 was used to calculate the minimum treatment volumes required to penetrate radii of 10, 25, and 100 ft. Table 7.2 presents these chemical volumes with equivalent radial flow skin values calculated from Eq. 7.11.

This can be rewritten as: Eq. 7.12

Table 7.1—Reservoir Data for Study Flow rate (STB/D)

20

Net pay thickness (ft)

20

Reservoir temperature (°F)

250

Porosity

0.2

Invaded zone permeability (md)

1

Formation permeability (md)

100

To examine the relationships between the parameters, plots of rp and s versus Vp/fh can be generated for several reduced mobility ratio values.

Vertical permeability (md)

0.2

Wellbore radius (ft)

0.4

Skin

0

These relationships can be used in different ways. For example, if it is beneficial to achieve a certain skin factor and the degree of permeability or mobility reduction is known, Eq. 7.11 can be rearranged and used to determine the penetration radius required. Once rp is known, Eq. 7.9 or 10 can be used to determine the treatment volume.

Wellbore storage (bbl/psi)

0.000183

Connate water saturation

0.2

Oil gravity (API)

40

Gas gravity

0.75

Solution gas-oil ratio (scf/STB) Formation volume factor (RB/STB)

300

In another potential application, well testing methods can be used to determine the skin factor resulting from a conformance treatment. The penetration radius of the treatment is determined from the treatment volume using Eq. 7.10. Once skin factor and penetration radius are known, Eq. 7.12 can be used to determine the mobility in the treated region. The mobility and the penetration radius can be subsequently used in a numerical simulator to model the expected well behavior with the treatment in place.

Total formation compressibility (1/Mmpsi)

10.78

Oil viscosity (cp)

0.736

Table 7.2—Calculated Values for Example rp (ft) 10 25 50 100

The following is an example of how these equations, coupled with Halliburton’s well test design software, RESULTS (REServoir ULtimate Test Simulator), are applied to identify water coning. Table 7.1 presents the reservoir data used for this study. This reservoir has a permeability of 100 md, which was reduced to 1 md out to a radius of rp by polymer injection. Bottomwater influx is represented by a constant-

7-4

Conformance Treatment Evaluations

1.218

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Vp/φh (gal/ft) 2,350 14,687 58,748 234,991

se 318.7 409.4 478 546.6

Chapter 7

Reservoir Simulation to Determine Treatment Volumes

Eq. 7.14: Water Coning

The pressure-transient testing approach is a quick and approximate representation of the coning phenomena. A proper reservoir simulator, which can duplicate the flow of the individual phases through the formation, generates graphs of water-cut or gas-oil ratio versus treatment volume for several reduced mobility values.

Coning and Cresting Calculations This section presents several relatively simple methods for estimating oil and gas coning and cresting behavior in vertical and horizontal wells. These methods cannot replace a detailed numerical simulation of a specific well in a specific reservoir but are much simpler to use and provide some reasonable estimates of coning behavior in several situations. The section includes methods for calculating (1) critical rate, i.e., the maximum rate a well can produce without water or gas breakthrough, (2) breakthrough time, i.e., the time the cone or crest breaks through to the well at a particular production rate, and (3) water cut, i.e., the fraction of production that is water at a particular point after breakthrough occurs. This section also includes methods for determining the optimal vertical position of a horizontal well, i.e., the depth water and gas break through simultaneously. For more specific information on the methods, refer to the original works from which the correlations were taken. Joshi also discusses many of the methods with example calculations.

Vertical Well Coning Calculations

Eq. 7.15: Simultaneous Water and Gas Coning

where the well completion is optimally placed so the bottom of the completion is at: Eq. 7.16

Chaperon4 Method This method, based on an approximate analytical solution, assumes the perforated interval is negligibly small compared to the reservoir height. Eq. 7.17

The quantity qc* is given by1: Eq. 7.18

where the dimensionless drainage radius, reD, is given by:

Critical Rate Calculations

Eq. 7.19

Meyer, Garder2 and Pirson3 Method Meyer and Garder developed approximate analytical solutions to water and gas coning based, among other things, on the assumptions that (1) the potential distribution in the oil phase is not influenced by the cone shape and (2) critical rate is determined when the water cone reaches the bottom of the well. Pirson extended this analysis to simultaneous coning of both water and gas. Eq. 7.13: Gas Coning

Chapter 7

If vertical permeability is unknown, qc* can be reasonably approximated as 1.

Chaney et al.5 Method Chaney et al. developed curves relating critical production rate to the oil-zone thickness and the height of the perforated interval using mathematical analysis and potentiometric model techniques. Kuo and DesBrisay6 performed a least squares fit on Chaney’s curves to put them in equation form. Because the curves were devel-

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Conformance Treatment Evaluations

7-5

CONFORMANCE TECHNOLOGY

oped for one particular set of fluid and rock characteristics, corrections must be applied to generalize them to other conditions. The resulting correlation is:

If the perforated interval extends to the top of the oil zone, Eq. 7.24 simplifies to: Eq. 7.25

Eq. 7.20

Schols7 Method

The average height of the oil zone can be determined from a material balance as:

The Schols Method is an empirical correlation based on experiments performed in Hele-Shaw models.

Eq. 7.26

Eq. 7.21

Høyland, Papatzacos, and Skjaeveland10 Method Chappelear and Hirasaki8,9 Method This theoretically derived model accounts for perforated intervals that do not extend to the top of the oil zone. It can account for moderate anisotropy and down-coning of oil into water.

The correlations of this method are based on more than 50 critical rates determined using a numerical reservoir model. Eq. 7.27: Isotropic Reservoirs

Eq. 7.22 For critical rate calculations in anisotropic reservoirs, two dimensionless quantities are used, dimensionless critical

where the average of the natural logarithm of the radius with an effective radius correction is given by:

q

rate,

HPS ocD

, defined by:

Eq. 7.28: Anisotropic Reservoirs

Eq. 7.23

and dimensionless radius, as defined by Eq. 7.19. The procedure for calculating critical rate is: 1.

Determine dimensionless radius, reD, using Eq. 7.19.

2.

Determine dimensionless critical rates,

and the effective radius is given by: Eq. 7.24

3.

4. 5.

7-6

Conformance Treatment Evaluations

q

HPS ocD

, for

several fractional well penetrations using Fig. 7.1. Plot dimensionless critical rate as a function of well penetration (Høyland, Papatzacos, and Skjaeveland use a semilogarithmic scale). Calculate fractional well penetration. Interpolate in the plot produced in Step 3 to determine dimensionless critical rate.

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Chapter 7

6.

Determine the critical rate using the following equation: Eq. 7.29

The optimum well penetration can be solved for numerically from: Eq. 7.33

Yang and Wattenbarger Method

where:

Unlike most previous correlations, that of Yang and Wattenbarger, developed from numerical simulations, assumes a no-flow outer boundary. The perforated interval does not need to extend to the top of the pay interval.

Eq. 7.34

Eq. 7.30

Eq. 7.35

Eq. 7.36 where the dimensionless critical rate is computed from: Eq. 7.31

and: Eq. 7.37

Guo and Lee12 Method Assuming a three-dimensional, combined radial-spherical flow pattern, Guo and Lee developed an analytical method that, unlike most previously developed correlations, accounts for the effect of limited wellbore penetration on oil productivity. And, unlike previous correlations that show that the greatest critical flow rate occurs with a wellbore penetration length of zero, they determined a relationship that gives a finite optimum completion length from the top of the formation. An excellent approximation of their critical rate equation is: Eq. 7.32

Chapter 7

Once xopt is determined, the maximum achievable waterfree rate can be calculated by substituting xopth for hp in Eq. 7.32.

Additional Methods Additional methods for calculating critical rates are derived from breakthrough time calculations, such as those of Sobocinski and Cornelius13 and Bournazel and Jeanson.14 These are presented with the breakthrough calculations in the following section. Wheatley15 developed an analytical solution that considers the influence of the cone on the potential distribution but requires an iterative procedure for determining the critical rate in oil-water coning. Piper and Gonzalez16 extended the method to determine the optimum completion interval in the presence of bottomwater and a gas cap. Both methods can be easily programmed on a computer, but they are too involved to present here.

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7-7

CONFORMANCE TECHNOLOGY

Comparisons Muskat and Wycoff’s analytical solution17 is generally agreed to give too high critical rates, 6,10,15 a conclusion extended to the Chaney et al. method.5 In contrast, Meyer and Garder’s method2 was found to underestimate critical rates,1,7,10 a conclusion extended to Pirson’s method.3 Schols’ method7 also underestimates critical rate when compared to the Høyland et al. or Wheatley methods,1,10,15 but not by as much. Høyland et al. found their method agrees very closely with the analytical solution of Wheatley for well penetrations in the rD interval from 2 to 50. Wheatley’s theory gives slightly higher values at the upper end of the interval and lower values at the lower end. The trade-off between these two methods is using a graph or performing iterative calculations. The Guo and Lee method12 differs from the others in that critical rates approach zero as the fractional well penetration goes to zero, which suggests an optimal penetration depth exists. The Chappelear and Hirasaki8,9 and Yang and Wattenbarger11 methods were developed primarily for use in large-scale reservoir simulators, but they can make coning calculations for a single well. No comparisons have been found in the literature for these particular models.

Breakthrough Time Calculations Sobocinski and Cornelius13 and Bournazel and Jeanson14 Methods Sobocinski and Cornelius developed a breakthrough time correlation based on a combination of experimental work and a computer finite difference model. Bournazel and Jeanson’s later work is based solely on laboratory results. 1.

Calculate the dimensionless cone height, z, according to:

or: Eq. 7.40: Bournazel and Jeanson

3.

Use the dimensionless breakthrough time and the following equation to calculate, tbt, the time of breakthrough in days: Eq. 7.41

where: Eq. 7.42a: Sobocinski and Cornelius

Eq. 7.42b: Bournazel and Jeanson

The breakthrough time and the dimensionless breakthrough time are infinite if the denominator of the relationship between dimensionless breakthrough time and dimensionless cone height is infinite, a condition met for the Sobocinski and Cornelius correlation if z = 3.5 and for the Bournazel and Jeanson correlation if z = 4.3. By plugging these values of z into Eq. 7.38, the definition of z, and solving that equation for qo, the critical rates predicted by these methods are: Eq. 7.43: Sobocinski and Cornelius

Eq. 7.38

and:

2.

7-8

Calculate the dimensionless breakthrough time from either of the following: Eq. 7.39: Sobocinski and Cornelius

Conformance Treatment Evaluations

Eq. 7.44: Bournazel and Jeanson

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Chapter 7

Wang and Wattenbarger Method11 (no-flow outer boundary)

and: Eq. 7.50

Eq. 7.45

Chappelear and Hirasaki8,9 Method

where:

This theoretically derived model accounts for perforated intervals that do not extend to the top of the oil zone. It can account for moderate anisotropy and down-coning of oil into water.

Eq. 7.46

In this method, solving the following quadratic equation for the water cut is necessary. Of the two roots to the equation, the one that falls between 0 and 1 is the correct value of fw.

Eq. 7.47

Eq. 7.51

where the mobility thickness ratio, Nmt, is found according to: Eq. 7.52

and: Eq. 7.48 the depth-averaged oil relative permeability is given by: Eq. 7.53

Water Cut/Water-Oil Ratio Calculations For any of these methods or those presented for horizontal wells, water cut and water-oil ratio can be determined from each other according to:

the depth-averaged water relative permeability is given by: Eq. 7.54

Eq. 7.49

and the critical rate is given by Eq. 7.22.

Chapter 7

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7-9

CONFORMANCE TECHNOLOGY

Kuo and DesBrisay6 Method The procedure for calculating the water cut at any time after breakthrough is: 1.

Calculate the breakthrough time, tbt, in days using either the method of Sobocinski and Cornelius or Bournazel and Jeanson. 2. Determine the dimensionless water cut time, twcD from the following equation: Eq. 7.55

Yang and Wattenbarger Method11 (no-flow outer boundary) This method assumes downhole production rate remains constant. Before breakthrough: Eq. 7.62

After breakthrough: Eq. 7.63

3.

Calculate the limiting water cut for the reservoir from: Eq. 7.56 where: Eq. 7.64

where: Eq. 7.57

Eq. 7.58

and Eq. 7.65

and Eq. 7.59

4.

Determine the dimensionless water cut, fwD from the following: Eq. 7.60

5.

Calculate the actual water-cut fraction as Eq. 7.61

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Conformance Treatment Evaluations

The (qoBo+qwBw) term in Eq. 7.65 represents a set downhole production rate. To approximate a constant surface rate, approximate the downhole rate or iterate the calculations of Eqs. 7.63 through 7.65 until sufficient accuracy is attained. (A few iterations should be sufficient.)

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Chapter 7

Effect of Horizontal Barrier Meyer and Garder2 derived a relationship for adjusting the critical rate if an impermeable barrier of some radius, rb, is placed at the bottom of the perforated interval for water coning or at the top of the perforated interval for gas coning.

Gas Cap or Bottomwater Drive with Constant Reservoir Pressure where1: Eq. 7.68

Eq. 7.66

where1: Eq. 7.69

Karp, Lowe, and Marusov,18 recognizing the small permeability such a barrier can have and that water is produced through the barrier, derived an equation for determining the produced water-oil ratio if the oil production rate is high enough to maintain a water cone under the entire barrier without producing any water around it. Eq. 7.67

and: Eq. 7.70

A quick estimate of qoc can be made for L » 2ye by setting F = 4. Pseudo-Steady State (Pressure Depletion) Substitute ye/2 for ye in Eq. 7.68.

Karp et al. also present an equation for the shape of the maximum stable water cone in a radial system.

Efros19,20 Method Eq. 7.71

Horizontal Well Cresting Calculations

Critical Rate Calculations Chaperon4 Method Based on approximate analytical solutions, this method assumes the horizontal well is placed at the top (for waterdrive) or bottom (for gas-cap drive) of the oil zone to minimize coning.

Chapter 7

Joshi suggests ye, rather than 2ye, should appear in the denominator of Eq. 7.71.

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7-11

CONFORMANCE TECHNOLOGY

Giger and Karcher et al.20-22 Method This method is based on an analytical solution that assumes the well is located near the top of the reservoir for bottomwater and edgewater drives and near the bottom for gas-cap drive.

where: Eq. 7.77

Eq. 7.72

Yang and Wattenbarger11 Method

Joshi23 Method (Gas Coning)

Unlike most previous correlations, that of Yang and Wattenbarger, developed from numerical simulations, assumes a no-flow outer boundary. Eq. 7.78

This method is simply an extension of the Meyer and Garder method for gas coning in vertical wells. It is made by substituting an effective vertical wellbore radius. Eq. 7.73

where: Eq. 7.79 where the effective wellbore radius, r, is calculated as: Eq. 7.74

Breakthrough Time and Calculations Ozkan and Raghavan25 Method

and the major half-axis of the drainage ellipse, a, is calculated as: Eq. 7.75

Ozkan and Raghavan developed a theoretical correlation to calculate water breakthrough time for a horizontal well in a bottomwater drive reservoir by assuming the pressure at the oil-water interface is constant. Because the calculation involves graphically determining sweep efficiency, with different graphs for different relative placements of the well from the oil-water interface, it is advisable to refer to the original work for more information.

Papatzacos et al.26,27 Methods Dikken24 Method (Edgewater Drive) Similar to other methods, this one assumes the well is placed at either the top or the bottom of the reservoir, depending on whether water or gas is present. Eq. 7.76

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Conformance Treatment Evaluations

Gas Cap or Bottomwater Papatzacos et al. developed a breakthrough time correlation using a semi-analytic method and assuming the well is located at either the top or the bottom of the oil zone to minimize water or gas coning. The problem was solved using two methods.

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Chapter 7

In both methods, dimensionless production rate,

q

P D

, is

where gas and water breakthrough should occur simultaneously. These techniques involve the following steps: 1.

determined from the relationship in Eq. 7.80: Eq. 7.80

Calculate the ratio of density contrasts, y, according to: Eq. 7.84

2.

Determine the coefficients cWP,i and cbt,i from Tables 7.3 and 7.4 (Page 7-14). 3. Calculate the dimensionless production rate using Eq. 7.80. 4. Calculate the optimum well placement and the dimensionless breakthrough time from: Eq. 7.85

and the breakthrough time, tbt, is calculated from the dimensionless breakthrough time, ttD, according to: Eq. 7.81

The first method of solution used the assumption that the top gas or bottomwater can be represented as a constant pressure boundary. This leads to the relationship between dimensionless breakthrough time and dimensionless rate of:

and: Eq. 7.86

Eq. 7.82

where: Eq. 7.87

The second method considered gravity equilibrium within the cone, giving the relationship: Eq. 7.83 5.

Calculate the actual breakthrough time from Eq. 7.81 using ∆ρog for ∆ρ.

Yang and Wattenbarger11 Method (no-flow outer boundary) The two methods give very similar results for

q

Eq. 7.88

P D

³ 1.

Comparison with a numerical simulator shows the analytical solution has reasonable accuracy for all gas viscosities with

q

P D

£ 0.3. For gas viscosities greater than

0.15, reasonable accuracy is expected with

q

where: Eq. 7.89

P D

£ 0.6.

Gas Cap and Bottomwater Papatzacos et al. also presented methods to calculate breakthrough time for both top gas and bottomwater and the optimum well placement, i.e., the vertical position

Chapter 7

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7-13

CONFORMANCE TECHNOLOGY

Eq. 7.90

Water Cut/Water-Oil Ratio Calculation Yang and Wattenbarger11 Method (no-flow outer boundary) This method assumes that the downhole production rate remains constant.

and:

Before breakthrough:

Eq. 7.91

7-14

Conformance Treatment Evaluations

Eq. 7.92

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Chapter 7

= distance between perforated top of a vertical well and gas-oil interface, ft M = water-oil mobility ratio = [mo(kw)or/mw(ko)wc] where (kw)or is the effective permeability to water at residual oil saturation, and (ko)wc is the effective permeability to oil at connate water saturation Ms = surface-corrected water-oil mobility ratio = M´Bo/Bw N = initial oil in place, STB Np = cumulative oil production, STB q = production rate, STB/D lV

After breakthrough: Eq. 7.93

where: Eq. 7.94

re rw Swc Sor t xe

and: Eq. 7.95

The (qoBo+qwBw) term in Eq. 7.95 represents a set downhole production rate. To approximate a constant surface rate, approximate the downhole rate or iterate the calculations of Eqs. 7.93 through 95 until sufficient accuracy is attained. (A few iterations should be sufficient.)

Chapter Abbreviations Nomenclature A Bo fw H h hh hcb hct k kr L

Subscripts

= areal extent of well or reservoir, ft2 = formation volume factor, RB/STB = water cut = initial zone thickness, ft = zone thickness, ft = height of horizontal well from top of oil zone, ft = height of completion bottom from top of oil zone, ft = height of completion top from top of oil zone, ft = effective permeability, md = relative permeability = horizontal well length, ft

lH,go = distance between horizontal well and gas-oil interface, ft lH,wo = distance between horizontal well and water-oil interface, ft

= drainage radius, ft = wellbore radius, ft = connate water saturation, fraction = residual oil saturation, fraction = time of production, D = distance between horizontal well and constant pressure boundary, ft xopt = optimum fractional penetration of wellbore ye = half drainage length (perpendicular to horizontal well), ft µ = viscosity, cp ρ = density, g/cm3 ∆ρ = density difference, g/cm3 φ = porosity, fraction

b

= barrier

bt c D g H i o p t V w wc

= breakthrough = critical = dimensionless = gas = horizontal = initial = oil = perforated (from top of sand) = total = vertical = water = water cut

Superscripts -

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Bibliography

13. Sobocinski, D.P. and Cornelius, A.J.: “A Correlation for Predicting Water Coning Time,” JPT, (May 1965) 594-600.

Hall, H.N.: “How to Analyze Waterflood Injection Well Performance,” World Oil (Oct. 1963) 128-30. References for Seismic-Geologic Reservoir Characterization (Reservoir Description).

14. Bournazel, C. and Jeanson, B.: “Fast Water-Coning Evaluation Method,” paper SPE 3628 presented at the 1971 SPE Annual Fall Meeting, New Orleans, Oct. 3-6.

Marquardt, D.W.: “An Algorithm for Least Squares Estimation of Nonlinear Parameters,” J. SIAM (June 1963) 11, No. 2, 431-41.

References 1. 2.

Joshi, S.D.: Horizontal Well Technology, PennWell Publishing Company, Tulsa, OK, 1991. Meyer, H.I. and Garder, A.O.: “Mechanics of Two Immiscible Fluids in Porous Media,” Journal of Applied Physics, Vol. 25, No. 11, 1400 ff.

3.

Pirson, S.J.: Oil Reservoir Engineering, Robert E. Krieger Publishing Co., Huntington, NY, 1977.

4.

Chaperon, I.: “Theoretical Study of Coning Toward Horizontal and Vertical Wells in Anisotropic Formations: Subcritical and Critical Rates,” paper SPE 15377 presented at the 1986 SPE Annual Technical Conference and Exhibition, New Orleans, LA, Oct. 5-8.

5.

6.

7.

Chaney, P.E. et al.: “How to Perforate Your Well and Prevent Water and Gas Coning,” Oil and Gas Journal, (May 7, 1956) 108. Kuo, M.C.T. and DesBrisay, C.L.: “A Simplified Method for Water Coning Calculations,” paper SPE 12067 presented at the 1983 SPE Annual Technical Conference and Exhibition, San Francisco, CA, Oct. 5-8. Schols, R.S.: “An Empirical Formula for the Critical Oil Production Rate,” Erdoel Erdgas, Z., (Jan. 1972) Vol. 88, No. 1, 6-11.

8.

Chappelear, J.E. and Hirasaki, G.J.: “A Model of Oil-Water Coning for Two-Dimensional, Areal Reservoir Simulation,” SPEJ, (April 1976) 65-72.

9.

Chappelear, J.E. and Hirasaki, G.J.: “A Model of Oil-Water Coning for 2-D Areal Reservoir Simulation,” paper 4980 presented at the SPE-AIME 49th Annual Fall Meeting, Houston, Oct. 6-9, 1974.

10. Høyland, L.A., Papatzacos, P., and Skjaeveland, S.M.: “Critical Rate for Water Coning: Correlation and Analytical Solution,” SPE Reservoir Engineering, (Nov. 1989) 495-502. 11. Yang, W. and Wattenbarger, R.A.: “Water Coning Calculations for Vertical and Horizontal Wells,” paper SPE 22931 presented at the 1991 SPE Annual Technical Conference and Exhibition, Dallas, Oct. 6-9. 12. Guo, B. and Lee, R.L-H.: “A Simple Approach to Optimization of Completion Interval in Oil/Water Coning Systems,” SPE Reservoir Engineering, (Nov. 1993) 249-55.

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15. Wheatley, M.J.: “An Approximate Theory of Oil/Water Coning,” paper SPE 14210 presented at the 1985 SPE Annual Technical Conference and Exhibition, Las Vegas, Sept. 22-25. 16. Piper, L.D. and Gonzalez, F.M. Jr.: “Calculation of the Critical Oil Production Rate and Optimum Completion Interval,” paper SPE 16206 presented at the 1987 SPE Production Operations Symposium, Oklahoma City, March 8-10. 17. Muskat, M. and Wycoff, R.D.: “An Approximate Theory of Water Coning in Oil Production,” Trans., AIME (1935) 114, 144-61. 18. Karp, J.C., Lowe, D.K., and Marusov, N.: “Horizontal Barriers for Controlling Water Coning,” JPT, (July 1962) 783-90. 19. Efros, D.A.: “A Study of Multiphase Flows in Porous Media,” (in Russian) Gastoptexizdat, Leningrad, 1963. 20. Karcher, B.J., Giger, F.M., and Combe, J.: “Some Practical Formulas to Predict Horizontal Well Behavior,” paper SPE 15430 presented at the 1986 SPE Annual Technical Conference and Exhibition, New Orleans, LA, Oct. 5-8. 21. Giger, F.: “Evaluation Theoretique de l’Effet d’Arete d’Eau Sur la Production par Puits Horizontaux,” Revue de l’Institut Francais du Petrole, Vol. 38, No. 3, May-June 1983 (in French). 22. Giger, F.M.: “Analytic 2-D Models of Water Cresting Before Breakthrough for Horizontal Wells,” SPE Reservoir Engineering, (Nov. 1989) 409-16. 23. Joshi, S.D.: “Augmentation of Well Productivity Using Slant and Horizontal Wells,” JPT, (June 1988) 729-39. 24. Dikken, B.J.: “Pressure Drop in Horizontal Wells and Its Effect on Their Production Performance,” paper SPE 19824 presented at the 1989 SPE Annual Technical Conference and Exhibition, San Antonio, TX, Oct. 8-11. 25. Ozkan, E. and Raghavan, R.: “Performance of Horizontal Wells Subject to Bottom Water Drive,” paper SPE 18545 presented at the 1988 SPE Eastern Regional Meeting, Charleston, WV, Nov. 2-4. 26. Papatzacos, P., Gustafson, S.A., and Skaeveland, S.M.: “Critical Time for Cone Breakthrough in Horizontal Wells,” presented at Seminar on Recovery from Thin Oil Zones, Norwegian Petroleum Directorate, Stavanger, Norway, April 21-22, 1988. 27. Papatzacos, P. et al.: “Cone Breakthrough Time for Horizontal Wells,” paper SPE 19822 presented at the 1989 SPE Annual Technical Conference and Exhibition, San Antonio, TX, Oct. 8-11, 1989.

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