Lecture 8 Subsurface Equipment.pdf

EG318 - WELL COMPLETION Lecture 8 Subsurface Equipment

What is Subsurface Equipment? A production/injection is equipped with many surface and subsurface equipment.  The surface equipment are x-mas tree, wellhead, surface safety valve, etc.  There are many subsurface equipment installed in a tubing string in order to perform their respective functions.

2

Type of Subsurface Equipment Can be categorized as follows: Subsurface Safety Equipment

Auxiliary equipment

Subsurface Equipment

Flow control equipment

Communication Equipment

3

Subsurface Equipment

4

Subsurface Equipment

Single Completion

Dual Completion

5

Sub Surface Safety Equipment

Flow Control Equipment Surface control Sub Surface Safety Valve

Production packer

Subsurface Safety Equipment

6

Sub Surface Safety Valve (SSSV) • A safety device installed in the upper wellbore to provide emergency closure of the producing conduits in the event of an emergency.

Sub Surface Safety Valve

Flapper inside SSSV

Source: Schlumberger

Source: Baker Hughes

7

Sub Surface Safety Valve

• Primary Purpose – Emergency well flow control device – Prevents losses – Personnel, environment, reserves, image

• Secondary Purpose – Downhole Flow Control – Allows for wellhead problem corrections – Serves as a secondary barrier

8

Sub Surface Safety Valve

• Regulations – API 14 A, Specification for SSSVs – API 14 B, Install, operate SSSVs – ISO 10432, Standard for SSSV products – ISO 10417, Installation et al for SSSVs – MMS, Department of the Interior – CFR 250, USA federal laws – International standard bodies

9

Sub Surface Safety Valve Types of SSSVs 1. Surface Controlled • Tubing retrievable • Wireline/Slickline retrievable • Others, pump-in-place: coiled tubing 2. Subsurface Controlled • Velocity • Injection

10

Sub Surface Safety Valve

11

Sub Surface Safety Valve

Flapper-Type Closure

Ball-Type Closure

12

Sub Surface Safety Valve

 Check valves - installed in the tubing string to prevent the back flow of injection well.  Bottomhole chokes/beans and regulators - to reduce the wellhead flowing pressure and prevent the freezing of surface controls and lines by taking pressure drop down hole.

13

Flow Control Equipment

• • • • • •

Flow Couplings. Blast Joint. Selective Landing Nipple No-go Landing Nipple Tubing Plug Seal Units

14

Flow Coupling & Blast Joint

15

Flow Coupling & Blast Joint Flow Coupling • Flow couplings have a wall thickness greater than the corresponding tubing to inhibit erosion caused by flow turbulence. • Should be installed above and below landing nipples or other restrictions that may cause turbulent flow.

Blast Joint • Help inhibit erosion caused by jetting action near perforations (Installed opposite perforations) • Heavy walled and are sized to help prevent tubing damage from the jetting action of the zone perforations • Helps extend the life of the well completion Flow Coupling & Blast Joint Source: Baker Hughes

16

Landing Nipple

17

Landing Nipple Landing Nipple • A completion tool fabricated as a short section of heavy wall tubular with a machined internal surface that provides a seal area and a locking profile. • Landing nipples are included in most completions at predetermined intervals to enable the installation of flowcontrol devices, such as plugs and chokes • Two common type: 1. No go Landing Nipple 2. Selective Landing Nipple

18

Landing Nipple No-go Landing Nipple • Reduced diameter internal profile that provides a positive indication of seating by preventing the tool or device to be set from passing through the nipple • Preferred for the deepest nipple location, providing a no-go barrier to protect against a tool string being run or dropped below the tubing string.

Selective Landing Nipple • Selective nipples incorporate internal profiles that enable the associated slickline tools and equipment to be run through, or set in the nipple profile, under the control of the slickline unit operator 19

Plug Assembly

20

Communication Equipment

 Sliding Sleeve  Perforated Joint  Side-pocket Gas Lift Mandrel

21

Sliding Sleeve Sliding Sleeve • Used to shut off flow from a zone for economic reasons or to shut off a zone that is depleting or producing too much water. • In multi-zone wells, they are used to regulate which zones to produce from and which ones to shut off • Mechanically actuated sleeves are simple and inexpensive but require actuation by a "lock," which must be run in the well on wireline or coiled tubing. • Hydraulically actuated sleeves are more complicated but can be actuated from a small pump at surface. 22

Sliding Sleeve Sliding Sleeve

23 Hydraulic Controlled Sliding Sleeve Source: Bellarby

Sliding Sleeve

24

Perforated Joint Perforated Joint • This is a length of tubing with holes punched into it. If used, it will normally be positioned below the packer and will offer an alternative entry path for reservoir fluids into the tubing • Usually installed in between two nipples – upper nipple connected to tubing below packer and lower nipple allows for setting of downhole device operation e.g temperature probe, etc..

25

Side Pocket Gas Lift Mandrel • A gas-lift valve is a device installed on (or in) a gas-lift mandrel, which in turn is put on the production tubing of a gas-lift well. Tubing and casing pressures cause the valve to open and close, thus allowing gas to be injected into the fluid in the tubing to cause the fluid to rise to the surface

• In a conventional gas-lift mandrel, a gas-lift valve is installed as the tubing is placed in the well. Thus, to replace or repair the valve, the tubing string must be pulled. • In the side-pocket mandrel however, the valve is installed and removed by wireline while the mandrel is still in the well, eliminating the need to pull the tubing to repair or replace the valve. 26 Gas Lift Mandrel Source: Pacific Nova

Side Pocket Gas Lift Mandrel

Side Pocket Gas Lift Mandrel Source: Weatherford

Well Completion with Gas Lift Source: Schlumberger

27

Auxiliary Equipment

 Double pin sub  Rigid blade tubing centralizer  Straight-slot or J-slot body  Mule/guide shoe.

28

Production Packer & Tubing Seal Assembly

What is Production Packer? 

Is a subsurface equipment used to seal the annulus between the tubing string and production casing.



Is also known as secondary subsurface safety valve.



All production and injection wells in Malaysia are equipped with production packer.

29

Production Packer

30

Production Packer

Single Completion

Dual Completion

31

Application of Packer • To guide fluid flow into tubing string - subsurface safety control. • Used as an isolation barrier - to isolate non productive zone and also equipment above the topmost packer from reservoir fluid and pressure. • Assists artificial lift - Gas lift. • Elimination of surging or heading. • To separate multiple zones.

32

Components of Packer The two most important basic components of a packer construction are the slips and the sealing/packing elements. • Slips - designed to resist force for either direction. • Sealing elements - must be compressed to affect a seal against the casing wall.

33

Components of Packer

34

Types of Packer Packer Retrievable • • • •

Expected to be retrieved More prone to leaks Need an equalizing port Release mechanism must be possible with well design

Permanent • Can be removed from the wellbore only by milling. • The permanent packer is fairly simple and generally offers higher performance in both temperature and pressure ratings than the retrievable packer. • In most instances, it has a smaller outside diameter (OD), offering greater running clearance inside the casing and help to negotiate through tight spots and deviations in the wellbore. 35

Types of Packer  Three types:  Permanent packers.  Hydraulically-set packers  Mechanically-set packers  Weight-set packers  Tension-set packers  Rotational-set packers

 Permanent packers are widely used as the only packer in a well or as the bottom-most packer.  Hydraulically-set packers are normally used as intermediate packer or top-most packer  Mechanically-set packers are hardly used in production well.  Can cement packers be considered as one of the production packers? 36

Types of Packer

37

Permanent Packer

38

Retrievable Packer Seal Bore Packer Allow tubing movement; however: • • •

Too much contraction can pull seals out of PB Seals can “bond” to the seal bore over long time at higher temperatures Debris on top of packer can stick assembly

General properties • High pressure & temperature ratings available • Multiple packing elements available • Short units are desirable for use in tight doglegs (>5°) and high (>8°/100ft) departure angles • Ability to set on wireline or with a hydraulic setting tool • Rotationally locked units needed for mill-ability • Share Seal Assemblies with permanent seal bore packers • Critical metallurgical and seals (O-rings, etc) should be isolated from wellbore fluids by main elements.

39

Hydraulic Set Packer

Permanent Packer

Retrievable Packer with Releasing Tool 40

Hydraulic Set Packer

Hydraulic Set RH Packer

Hydraulic Set RDH Packer

Hydraulic Set PHL Packer

Source: Halliburton

Hydraulic Set AVATM RHD Dual Packer

41

Hydraulic Packer Setting

RH Hydraulic Packer Source: Halliburton

42

Hydraulic Packer Setting

RH Hydraulic Packer Setting Source: Halliburton

43

Single Packer

Example: Halliburton 13-3/8” packer *notice the casing min & max ID?

44

Dual Packer

Hydraulic Set Dual String Packer

45

Swell Packer Swell Technology is based on the swelling properties of elastomers. Halliburton currently has three types of swelling elastomer systems. • • •

Swell when exposed to hydrocarbons. Swell upon exposure to water. Hybrid swelling polymer, which combines the capabilities of both oil swelling and water swelling polymers into a single compound.

These products have no moving parts and require no inflation to seal, removing the inherent risks of mechanical and inflatable tools. Swell Packer Source: Halliburton

46

Packer Data – Single Production

Perma-Lach® PLS Packer 47 Source: Halliburton

Packer Data – Single Production

Hydraulic Set RH Single Packer Source: Halliburton

48

Packer Data – Dual Production

Hydraulic Set RDH Dual Packer 49 RDH dual packer data Source: Halliburton

Packer & Tubing Selection Example 1 A well section with 7” casing 29 lb/ft is to be completed with single string completion and a Perma-Lach® PLS single packer. What would be the suitable tubing size to use?

Solution From Packer data:

Two sizes of tubing are possible: 3½” and 2⅞”

50

Packer & Tubing Selection Solution

51

Note that there are ranges of Internal Diameter for each tubing size!

Packer & Tubing Selection Solution

52

Note that there are ranges of Internal Diameter for each tubing size!

Packer & Tubing Selection Solution Sealing element PLS Single Packer Packer OD = 5.90”

Packer ID : 2.36” 2.97”

Tubing ID : 2.259” – 2.441” (Tubing 2⅞”) 2.750 – 3.068” (Tubing 3½”)

Casing 7” 29 lb/ft • OD = 7” • ID = 6.184” • Drift ID = 6.059”

53

Packer Data – Dual Production Example 2 A completion engineer wishes to design a well which are producing from two payzones such that one zone is produced with 2⅞” tubing and another one with 3½” tubing. If an RDH dual packer is used to separate these two payzones inside a 9-5/8” production casing, determine the suitable casing and tubing size and weight to be used

54

Packer Data – Dual Production Solution From Packer data:

Tubing ID : 2.259” – 2.441” (Tubing 2⅞”) 2.750 – 3.068” (Tubing 3½”) Possible casing to use: • OD Size: 9⅝ in • Weight: 40 lb/ft; 43.5 lb/ft; 47 lb/ft; and 53.5 lb/ft

Packer ID : 2.44” 2.90”

55

Packer Data – Dual Production Solution

For example, choose tubing with upset regular type..

From tubing data:

56

**Check and confirm your tubing can be run into the casing!

Packer & Tubing Selection Solution

RDH Dual Packer Packer OD = 8.34 in

Dual string configuration inside 9⅝” casing 43.5 lb/ft

Sealing element Tubing Body OD 3.50”

Casing 9⅝” 43.5 lb/ft OD = 9.625 in ID = 8.755 in Drift ID = 8.599 in Tubing e.g using regular upset type 1. 3½” tubing; upset regular coupling 2. 2⅞” tubing; upset regular coupling

4.50”

2.875”

3.668”

OK

✓

Tubing Coupling OD = 4.50 + 3.668 = 8.168” < 8.599” OK

✓ 57

Packer & Tubing Selection Solution Suitable tubular to use: Packer – Halliburton RDH 9⅝” Dual Packer • OD Size: 8.34 or 8.44 in

Casing • OD Size: 9⅝ in • Weight: 40 lb/ft; ; 43.5 lb/ft; 47 lb/ft; or 53.5 lb/ft Tubing 1. 3½” tubing;

2. 2⅞” tubing; • • •

All grade All weight – 6.4, 6.5, 8.6, or 8.7 lb/ft All type of coupling – Non upset, Upset Regular & Special

58

Packer Selection  Viscosity-related characteristics • • • • • • • • • •

Purchase price. Availability of the packer. Packer mechanics. Sealing element. Corrosive well fluids. Retrievability. Fishing characteristics. Through-tubing operations. Surface equipment-downhole correlation. Company policy/strategy.

59

Effect of Temperature & Pressure on Packer

 Must consider the temperature and pressure ratings of the respective packer.  The steel body of the packer may expand or contract when there is a change in temperature.  Production well may not give serious problems.  Serious consideration must be given to the retrievable packers (i.e. hydraulically-set packers) when installed in a water injection well.  Contraction is equivalent to 15K pull. May unseat packer.

 Pressure differential across a packer must be kept as minimum as possible. Balanced pressure is the ideal condition.

60

Effect of Temperature & Pressure on Packer Tubing Elongation • Expand in oil production – tubing may buckle! • Contraction in water injection – equivalent to 30k lb pull  May unseat retrievable hydraulic packer!!

Production casing Tubing 30,000 lb pull

Packer 15,000 lb pull

water

Total contraction on tubing and packer = 30000 + 15000 = 45000 lb pull

12 holes with shear pins on packer 1 shear pin = 5000 lb pull 12 x 5000 = 60,000 lb > 45,000 lb ∴ packer will not be unseat 61

Effect of Temperature & Pressure on Packer Example 2 How much force does it take to unseat the packer? Weight of tubing (both strings) 150,000 lb Dual Packer (Retrievable) 16 shear pins

1. 2. 3.

Weight of elevator (Top drive or Kelly/swivel) 60,000 lb

16 hole x 5000 lb per release screw = 80,000 lb to keep the packer in setting position Weight of tubing string = 150,000 lb Weight on elevator = 60,000 lb

∴ to unseat the packer  60,000 + 80,000 + 150,000 = 290,000 lb (min force to apply) 62

Completion and Workover Fluids



Is a fluid that placed against the producing formation while conducting operations such as well killing, cleaning out, hardware replacement, gravel packing, etc.



Workover fluid is used when a workover job is done on a well. In this discussion, it refers to the same completion fluid.



Workover fluid does not include well stimulation fluid, fracturing fluid, cement slurry, etc.

63

Tubing Seal Assembly  Is installed at the end of a tubing string. Long string for the case of dual completion.  Comprises a straight-slot or J-slot body, seal units, and a mule shoe.  Rigid blade tubing centralizer is encouraged to be part of the tubing seal assemblies.  Installed mule shoe only on the short string. 

Well spaceout starts from the straight slot or J-slot body.

64

Tubing Assembly

65

Plug Assembly

66

Casing Scraper

Do you know what is the function of this equipment?

67

Fishing

68

Fishing Definitions Fish - any undesirable object in the well bore that cannot be withdrawn (e.g. bit cones, broken pipe, spanner, wire line, etc.) Junk – generally considered to be any relatively small, non-drillable objects

Fishing tool - any and all special pieces of equipment that must be added to the string to enable the operator to engage and retrieve the fish Fishing - is used in the manner that encompases both the special equipment and the special procedures required to remove undesirable object from the well hole 69

Fishing

Causes of fishing jobs • • • • •

Drill string failure (twist-off) Sticking the string Bit failures Junk in hole Accident or error in judgments • Other equipment failures

70

Fishing Preventing fishing jobs • • • • • • •

Do not compress the drill string (bend, crooked hole) Rotate the drill string in tension (use sufficient drill collar) Use new drill strings (old pipes tend to corrode, wear, etc.) Check the equipment (connections, repair, replace, etc.) Tight the connection properly (do not over or under tighten) Use proper muds Unhurried, extreme caution should be exercised

71

Wireline / Slickline Operations

SLICKLINE OPERATIONS …manipulation of downhole tools from the surface using wireline. No need to pull out tubing string.

72

Wireline Equipment

73

Wireline Equipment

74

Wireline Equipment

SURFACE EQUIPMENT: wireline unit, power supply unit, accumulator, wireline BOP, and lubricators. SUBSURFACE EQUIPMENT: standard wireline tool string (consists of rope socket, wireline stem, wireline jar, and knuckle joint) and special tools

75

Wireline Control Unit

76

Wireline Drum

77

Weight Indicator

78

Power Supply Unit

79

Wireline Pressure Control Equipment Grease Injection Control Head maintains a dynamic seal around wireline and is comprised of three major subassemblies: • Stuffing Box • Line Wiper • Flotube Assembly.

80

Wireline Pressure Control Equipment

Tool Catcher

Tool Trap

"Catches" cable head to prevent loss of tool string

prevents the loss of wireline tools downhole in the event of the wire being pulled-off the rope socket, by retaining the dropping tool on a flapper. The flapper has an opening larger than the wireline, but smaller than the tool string.

Lubricator Allow the wireline tool string to be raised above the wellhead prior to and after wireline operations, thereby enabling the wellhead valve to be opened and closed

Quick Test Sub pressure tests and verify the integrity of joint separately rather than having to test the whole assembly.

81 Wireline Equipment Source: Fountain Petro

Wireline BOP

82

Accumulator

83

Stuffing Box

84

Subsurface Slickline Tool Rope Socket A standard set of wireline tool string typically consist of: Stem

Stem

Mechanical Jar

Knuckle Joint

• Wireline Socket (Rope Socket) for attaching the wireline to the tool string • Wireline Stem (Sinker Bar) for adding weight to sink the tool in the well bore against the well pressure and different gravity fluids encountered. • Wireline Jars (Spang Link Jar) for securing the hammering effect by upward or downward movement. • Wireline Knuckle Joint for obtaining flexibility through the tool string. • Wireline running or pulling tool for running and retrieving devices from the well bore. 85 Subsurface Slickline Tools Source: Peak Well System & Leutert

Subsurface Slickline Tool Rope Socket Rope Sockets are used as a means to connect wireline to the tool string.

Wireline Stem / Weight Bar Wireline Stems are used to provide weight to tool string to eliminate friction with elastomers of stuffing box and for smooth running of wireline against well pressure.

Roller Stem Roller Stems are used with tool string in deviated wells. Its application is to reduce friction against tubing ID. 86

Subsurface Slickline Tool Wireline Link Jar Spang Link or Mechanical Jars are used in wireline fishing operations with stems. The weight of stems and jars can be used by operator for jarring by pulling and then releasing wireline.

Wireline Shock Absorber Wireline Shock Absorber is used to reduce the shocks to sub surface instruments, caused due to jarring, surging etc.

Wireline Knuckle Joint Knuckle Joints are used to add flexibility to the tool string and are effective in deviated wells. Knuckle Joints are run immediately below Mechanical Jar.

87

Subsurface Slickline Tool Wireline Accelerator Wireline Accelerator is used to run with Hydraulic Jar to reduce shocks at Rope Socket to avoid pulling of wire out of socket and accelerate movement of stem, to achieve effective jarring. Accelerator facilitate constant pull at the time of opening of Hydraulic Jar.

Tubing Swage Tubing Swages are used to remove large obstructions and restore light collapse in the tubing. This allows smooth running of tool string in well bore. The OD of tubing swage should be equal to tubing drift ID 88

Subsurface Slickline Tool Wireline Crossover Wireline Crossover are used to connect two tool string items with different threads & connection type

Swivel Joint The Swivel Joint is a wireline accessory used to minimize the effect of line twist caused by subsurface devices being run. The Swivel Joint has a bearing incorporated into its design and is used to minimize rotation whilst running tubing or casing calliper surveys 89

Subsurface Slickline Tool Quick Lock Connection Quick Lock Connections provide a fast safe and strong method of attaching and releasing tools by hand. The male half is mated with the female half, then rotated through 90 deg. It eliminates the chance of items backing off and does away with the need for pipe wrenches.

90

Subsurface Slickline Tool Quick Lock Couplings Quick Couplings are used as a fast, safe & strong method of tool coupling. Coupling can be made by hand, eliminating requirement of wrenches / spanners etc.

Blind Box Blind Boxes are used when heavy downward jarring is required to dislodge a fish or push something down the hole. Bottom surface of Blind Box is flat and hardened to reduce wear and damage.

Gauge Cutter Gauge/Paraffin Cutters are run in hole before running sub surface equipment. Gauge/Paraffin Cutters are used to check if sub surface equipment can pass freely thru tubing & there are no obstructions and to locate top of nipple. The bottom of Gauge/Paraffin Cutter is suitable to cut paraffin, scale and any other obstacles in tubing.

91

Subsurface Slickline Tool Wireline Overshot Overshots consist of hardened steel slips with sharpened upward teeth to engage the fish.

Tubing End Locator Tubing End Locators are used to locate end of tubing during completions.

Releasable Overshot Releasable Overshot is used in Wireline Fishing Operation. Bowen and ‘O’ Banon type Overshot cannot be released once they are latched. However in Releasable Overshots, the slips can be released by downward jarring. 92

Subsurface Slickline Tool Pulling Tool Pulling Tools are used to unlock and pull various down hole equipment with Internal Fishing Necks.

93

Subsurface Slickline Tool Impression Block Impression Blocks are used during fishing operations to check the shape / size of the top of fish and to determine tool appropriate for fishing operation. Lead is filled within body of Impression Block

Magnetic Fishing Tool Magnetic Fishing Tools are used to remove small particles of metals from the top of tools during operations.

94

Subsurface Slickline Tool

Center Spear Center Spears are used to engage broken wire in hole when in balled condition. It is used in particular when the broken wire is badly balled and can not be engaged by wireline grab.

Wireline Grab Wireline Grabs are used in wireline fishing operations to engaged broken wire from the tubing to retrieve to surface. 95

Subsurface Slickline Tool Bow Spring Centralizer Bow Spring Centralizer is designed to keep gauges and tool strings centralized in tail pipes ranging from 2” through 4” ID.

Fluted Centralizer Fluted Centralizers are used in deviated wells to ensure that tool string is at centralized position.

96 Subsurface Slickline Tools Source: Peak Well System & Leutert

Subsurface Slickline Tool Wireline Cutter Wireline Cutters are used to cut the wire near the rope socket and retrieve to surface with cut end of wire. It can cut all sizes of wires of large dia. by changing its internals appropriately.

Wireline Snipper Wireline Snippers are used to cut / slice the wire when operator finds it necessary to cut the wire when struck in hole. 97

Subsurface Slickline Tool Go-Devil Go-Devils are used in wireline fishing operations when wireline is required to be cut. Go-Devils looks similar to wireline stem and has a longitudinal slot on body with a metallic strip pinned within slot to prevent wireline from coming out.

Roller Go-Devil Roller Go-Devil is used mainly in deviated wells to reduce friction when tool string is run in hole. Roller Go-Devil is similar to Go-Devil with exception of rollers. Available in various lengths and flat/angled bottom type.

98

Subsurface Slickline Tool Paraffin Scratcher Paraffin Scratchers are used to clean the paraffin deposition on the ID of tubing, nipple profile etc.

Tubing Broach Tubing Broach is used remove buss in the tubing. Tubing Broach is also used to remove scale, rust etc, from tubing I.D.

99 Subsurface Slickline Tools Source: Peak Well System & Leutert

Subsurface Slickline Tool

Anti Blow-up Tool Anti Blow-up Tool will help to prevent a toolstring being blown up the production string if the flow rates between zones try to push the toolstring upwards. The Anti Blow-up Tool has been designed so that if the lower part of the toolstring starts to lift, two arms are thrown outward to lock into the tubing wall, stopping any further upward movement. To release the arms, once engaged, you simply pick up on the wireline which lifts the upper body of the tool and closes the arms, releasing the toolstring.

100 Subsurface Slickline Tools Source: Peak Well System & Leutert

Subsurface Slickline Tool Can you identify these slickline tools now? 

101

Subsurface Slickline Tool

THANK YOU

102