Reservoir Engineering Overview

Reservoir Engineering Overview

Presented by: Aung Myat Kyaw Reservoir Engineer MPRL E&P Pte, Ltd.

Myanmar Engineering Society 20-Dec-2008

Overview Objectives

§ Introduction to reservoir management and it’s benefits § Introduction to reservoir simulation and it’s benefits § Introduction to reserve estimation and it’s benefits

2

Reservoir Management - Definition

The use of available resources (human, technological and financial) to maximize profits from a reservoir by optimizing recovery while minimizing capital investments and operating expenses(*)

(*)“Integrated Reservoir Management” by Abdus Satter, SPE, James E. Varnon, SPE and Muu T. Hoang, SPE, Texaco Inc., SPE 22350 JPT, December 1994 3

Reservoir Management Approach 1.

Timing

2.

Integration of Geoscience and Engineering

3.

Reservoir Management Process

4.

Establishing Purpose of Strategy

5.

Developing a Plan

4

Reservoir Management Approach 1. Timing The ideal time to start managing a reservoir is at discovery. However it is never too late to initiate a wellthought-out, coordinated reservoir management program. An early start not only produces better overall project planning, implementation, monitoring, and evaluation but also saves money in the long run, maximising the profits.

5

Reservoir Management Approach 2. Integration of Geoscience and Engineering Synergy and team concepts are the essential elements for integration of geoscience and engineering. Integration involves people, technology, tools and data. Its success depends on the following An overall understanding of the reservoir management process, technology and tools through integrated training and integrated job assignments. Openness, flexibility, communication and coordination Working as a team Persistence

6

Reservoir Management Approach 3. Reservoir Management Process

7

Reservoir Management Approach 4. Establishing Purpose of Strategy a. Reservoir Characteristics c.

Total Environment i. Corporate – goals, financial strength, culture and attitude. ii. Economic – business climate, oil/gas price, inflation, capital, and personnel availability. iii. Social - conservation, safety and environmental regulations.

d. Technology and Technological Toolbox

8

Reservoir Management Approach 5. Developing a Plan

9

Integration for Effective Reservoir Management

10

Standard Technology and Technological Toolbox

11

Conclusion For Reservoir Management Management Geology & Geophysics

Legal

It is becoming more recognized that reservoir management is not synonymous with reservoir engineering and/or reservoir geology. Success requires multidisciplinary, integrated team efforts. The players are everyone who has anything to do with the reservoir.

Reservoir Engineering

Land

Environment

Economics

Reservoir Management Team

Drilling Engineering

Service

Design & Construction Engineering

Research & Development Gas and Chemical Engineering

Production & Operation Engineering

12

Reservoir Simulation As applied to petroleum reservoirs, simulation can be stated as: The process of mimicking or inferring the behavior of fluid flow in a petroleum reservoir system through the use of either physical or mathematical models.

13

Reservoir Simulation

As used here, the words petroleum reservoir system include the reservoir rock and fluids, aquifer, and the

14

MODELING METHODS

•Any problem is solvable if you can make assumptions- the key is determining the right assumptions.

15

DATA CONSIDERED BY MODELING METHOD

16

Key Steps in a Simulation Study 1. Clear Objectives and Preplanning 3. Reservoir Characterization 5. Model Selection 7. Model Construction 9. Model Validation 11.Predictions 13.Documentation

17

Pre-planning the reservoir simulation study •Objective of the study •Assess uncertainties •Data requirements and availability •Modeling approach •Limitations of proposed procedures •Resources Project budget Time available Hardware Software. ScaleGeolog y

Up

Data Quality & Quantity

Mathematic al

SOURCES OF UNCERTAINTY IN SIMULATION 18

Reservoir Characterization

19

Geological Description

*Geological description must identify the key factors which affect flow through the reservoir. 20

Fluid Characterization Fluid characterization defines the physical properties of the reservoir fluid mixture, and how they vary with changes in pressure, temperature and volume. Steps to characterize the reservoir fluids: •Classify the fluid type •Determine reservoir fluid properties •Describe reservoir production mechanisms.

Pressure Liquid

Bubble point

FIRST BUBBLE OF GAS

Dew point

LAST DROP OF LIQUID

Gas

Volume

21

22

Petrophysical Model The petrophysical model defines where the volumes of oil, water and gas are located in the reservoir, as well as how fluids behave in the presence of the rock. To define the petrophysical model of the reservoir, you must determine: •Rock Wettability A •Capillary Pressure •Relative Permeability •Residual Oil Saturation h1-h2 q •Fluid Contacts A Oil

Air

1.0

θ

h2

(SandPackLength) L

θ

0.8 0.6

Oil

OIL

OIL

0.4

θ

0.2

SOLID (ROCK)

n o c ,F y b rm P tiv la e R

Water 0

20

40

WATER

60

q

WATER

WATER

WATER

θ < 90°

SOLID (ROCK)

80

Water Saturation (% PV)

h1

23

24

Model Selection •The Black Oil Models (Primary depletion, secondary recovery and immiscible gas injection) •The Compositional Models(CO2 flooding, gas injection into near critical reservoir, condensate reservoirs) •The Chemical Flood Models ( Polymer/surfactant/Low-tension polymer flooding/Alkali/ Foam flooding) •Thermal Models (Steam soaks/drive, In situ combustion) •Dual-Porosity Models of Fractured Systems

25

Model Selection

26

Constructing the Reservoir Model QC the geologic model for errors and problems Scale-up the model

27

Constructing the Reservoir Model Zoning the geological model Layering the zone Making Local Grid Refinement Model the attached aquifer to reservoir Model the faults Model the Wells and Adding the Wells data

28

Model Validation

29

Predictions Important considerations when making reservoir model predictions: Prediction cases shouldn’t exceed capabilities of the model. Predictions need to be consistent with field practices. Simulation yields a non-unique solution with inherent uncertainties from: v Lack of validation (e.g., reservoirs with sparse geologic or engineering data). v Modeling or mathematical constraints because of compromises made in model selection. v Inherent uncertainties in reservoir characterization and 30

31

Documentati on Technical memorandum Formal report Presentation Store data files Share lessons learned with future project teams

32

Reserves Estimations •Reserves Estimations Rely on Integrity, Skill, and Judgment of Evaluator •Reserves Estimations Are Affected by Geological Complexity, Stage of Development, Degree of Depletion of Reservoirs and Amount of Available Data •All Reserve Estimates Involve Some Degree of Uncertainty and Is Done Under Conditions of Uncertainty •Uncertainty Depends Mainly on Amount of Reliable Geologic & Engineering Data at Time of Estimate and Interpretation of These Data

33

34

35

Methods of Petroleum Reserves Estimations •ANALOGY (Bbls per Acre Foot Period) •VOLUMETRIC(Bbls per Acre – Bbls Period) •PERFORMANCE (Bbls Period) Ø Simulation Studies Ø Material Balance Studies

EUR = OOIP x RF EUR; Estimated Ultimate Recovery OOIP; Original Oil-In-Place RF; Recovery Factor

EUR = ERR + Cum EUR; Estimated Ultimate Recovery ERR; Estimated Remaining Reserves 36

Analogy (Barrels per Acre Foot Period) Requirements : A field or well which is expected to perform similarly. Advantages : Fast, cheap, can be done before drilling. Disadvantages: Accuracy (Apples and Oranges)

37

Volumetric (Barrels per Acre to Barrels Period) Requirements: A well. Logs and/or Core. Estimate of drainage area, recovery factor (analogy), fluid properties (minor). Advantages : Minimal information. Can be done early in the life. Relatively fast. Disadvantages: Requires assumptions (Area, Recovery EUR = OOIP x RF EUR; Estimated Ultimate Recovery OOIP; Original Oil-In-Place RF; Recovery Factor

38

Decline Curves (Barrels Period) Requirements:

Production history (only).

Advantages: No assumptions about size, type or other properties of reservoir. Need only production history. Fast, cheap. Very accurate under certain circumstances. Results in production versus time prediction. Disadvantages: Well must be producing under “constant” conditions. Need at least 6 months history (better 2-10 years). Ambiguous (does not necessarily give unique

39

Decline Curves (Continue) 10000

1000

CV.DavgOil, bbl/d

100

10

1

Phase Case Name b Di qi ti te End Rate Final Rate Cum. Prod. Cum. Date Reserves EUR Forecast Ended By Forecast Date

: Oil : TPL : 0.55 : 0.05 A.n. : 67.0135 bbl/d : 12/30/2006 : 04/30/2014 : 1 bbl/d : 47.9872 bbl/d : 5939.15 Mbbl : 12/01/2006 : 151.793 Mbbl : 6090.95 Mbbl : Time :

197071 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99200001 02 03 04 05 06 07 08 09 10 11 12 13 14

40

Material Balance Requirements: Pressure, Production history, fluid properties, rock properties (relative permeability required for prediction). Advantages : No assumptions necessary for areal extent, thickness recovery factor. Low sensitivity to porosity, water saturation. Can be used to calculate oil-in-place, gasinplace, recoverable reserves (and therefore recovery factor), water influx, gas cap size. Disadvantages:

Pressure not usually available. Predictions

41

Reservoir Simulation Requirements: For each cell: permeability, porosity, thickness, elevation, initial saturation, initial pressure, rock compressibility. For each well: location, producing interval, production rates versus time, pressure versus time. For each rock type: relative permeability of each phase, capillary pressure. For each fluid type: formation volume factors, viscosity, gas solubility, density. Reservoir description: faults, pinchouts, aquifers, layering. Advantages: Ability to handle different rock and fluid properties in different areas of the reservoir. Can predict production from individual wells. Once history match is obtained, can study effects of different producing schemes. Input data requirements force close analysis of reservoir. Disadvantages: data, non-

Cost, time required to do study, amount of input 42

Conclusio ns •If the Material Balance and Decline Curves say there is more oil-in-place than the Volumetric, then there are probably un-drilled locations. •By comparing the results from the various methods, much can be learned about the reservoir, detach the faulty assumption and form a better picture of reservoir.

43

References 

Integrated Petroleum Reservoir Management (Abdus Satter, Ph.D and Ganesh C. Thakur, Ph.D)



Reservoir Simulation Overview ( Dale Brown, Subsurface Director, Chevron Bangladesh)



Oil Property Evaluation (Thompson and Wright)



Determination of Oil and Gas Reserves (SPE monograph No-1)



Oil & Gas Reserves Estimations {Saw Ler Mu, ME(CSM)}

44

Thanks You All.

45