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WELL COMPLETION
WELL COMPLETION
Introduction - generalities
Well completion: It covers the process and equipment (down-hole & surface) allowing to produce the well after it has been drilled.
© - IFP Training
Completion F.J.P.B
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WELL COMPLETION
Introduction - generalities Objectives of the well completion to ensure … - a good and “Safe” link between the reservoir and the surface - an optimal production, using specific equipment - safety in case of incident, in the well or at surface. and, - to produce selectively several reservoirs, - to isolate layers producing substantial water or gas, - to control sand production from unconsolidated formations .
© - IFP Training
New technologies …Furthermore, completions have evolved to incorporate down-hole sensors that measure flow properties, such as rate, pressure and gas-to-oil ratio. Known as intelligent wells or smart wells, these completions help to achieve optimum production rates. Completion F.J.P.B
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WELL COMPLETION
Surface treatment facilities
X-Mas tree
Flow lines
Reservoir
Flare. (obsolete)
© - IFP Training
Well
Oil storage tanks
Completion F.J.P.B
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WELL COMPLETION
Introduction - generalities
Production wellhead Christmas Tree section
Drilling wellhead section hanger Tubing spool – tubing Drilling wellhead section Drilling wellhead Drilling wellhead section © - IFP Training
Drilling wellhead section
Completion F.J.P.B
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WELL COMPLETION
Introduction - generalities
Well completion will include : • The design of the « liaison reservoir – bore hole” , • The design of the tubing (and therefore the design of the production casing), • The design and installation of the tubing spool+hanger and of the christmas-tree, But also … • The design of the safety equipment to close the well normally or in case of an emergency. • The design and installation of all auxiliary equipment for the full control the well production. © - IFP Training
All these equipment must provide the necessary safety barriers to produce the well safely. • (If necessary , the equipment necessary to lift the produced fluids). Completion F.J.P.B
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WELL COMPLETION « Liaison reservoir – bore hole »
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WELL COMPLETION
« Liaison reservoir – bore hole » Open hole completion application: only with consolidated formation advantages: - better productivity - savings on casing, cementation and perforations
© - IFP Training
Cased hole completion advantages: - to selectively produce several reservoirs, - to isolate zones producing too much water or gas but … requires perforations of casing/liner requires pre-perforated or slotted casing/liner
Completion F.J.P.B
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COMMUNICATION RESERVOIR – WELL-BORE
This type of completion does not allow to produce a reservoir with several type fluids; no selective capability. The formation (reservoir formation) must be stable during production. Completion F.J.P.B
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COMMUNICATION RESERVOIR – WELL-BORE Examples : Cemented casing or liner
Completion F.J.P.B
© IFP Training
This type of completion allows selective production of fluids.
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WELL COMPLETION Types of completion
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WELL COMPLETION
X-MAS TREE
TUBING HANGER
Most simple form of a completion. Either the well effluent is produced through the tubing. or/and the casing.
CASING VALVE
Drawback: when the well effluent is aggressive,(H2S, CO2 etc..) it will attack the casing, which is difficult to replace. EFFLUENT
Completions like this you’ll find in SA, some wells produce 14 000 BOPD TUBING
PERFORATIONS
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RESERVOIR
Tubing without packer
Completion F.J.P.B
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WELL COMPLETION
X-MAS TREE
TUBING HANGER
CASING VALVE
EFFLUENT
COMPLETION FLUID
TUBING
Simple completion where the packer isolates the well effluent from the casing. In general the completion or packer Fluid is a “brine” (salt water) with chemicals. The function of the completion fluid is: Create a hydrostatic pressure on the packer to give a counter force on the reservoir pressure in order to balance the packer forces.
Hyd Pr completion fluid PACKER
Reservoir pressure
PERFORATIONS
Completion F.J.P.B
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RESERVOIR
Tubing with packer 13
WELL COMPLETION
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BRINE A water-based solution of inorganic salts used as a well-control fluid during the completion and wor-kover phases of well operations. Brines are solids free, containing no particles that might plug or damage a producing formation. In addition, the salts in brine can inhibit undesirable formation reactions such as clay swelling. Brines are typically formulated and prepared for specific conditions, with a range of salts available to achieve densities ranging from 8.4 to over 20 lbs/gal (ppg) [1.0 to 2.4 g/cm3]. Common salts used in the preparation of simple brine systems include sodium chloride, calcium chloride and potassium chloride. More complex brine systems may contain zinc, bromide or iodine salts. These brines are generally corrosive and costly. Completion F.J.P.B
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WELL COMPLETION Tubing hanger
Single completion 1 reservoir layer to produce
Tubing
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Perforations
Completion F.J.P.B
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WELL COMPLETION
Dual completion 2 reservoirs to produce The x-mas tree consist out of 2x2 master valves.
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Completion F.J.P.B
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WELL COMPLETION
1
TUBING
TUBING
LATCH PROFILE CASING
SEAL
2
SLOTTED PORTS
SLEEVE
1 CASING
3 2
TUBING
TUBING
3 Completion F.J.P.B
SSD OPEN
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SSD CLOSED
SSD Sliding Side Door MULTIPLE ZONE COMPLETION (selective completion) 17
WELL COMPLETION
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In a multiple zone completion we can produce: Produce only zone 1 SSD 1 closed SSD 2 open SSD 3 closed Bottom of the tubing a plug is installed Produce only zone 2 SSD 1 closed SSD 3 open SSD 2 closed Bottom of the tubing a plug is installed Produce only zone 3 SSD 1 closed SSD 2 closed SSD 2 closed Plug is removed from bottom of the tubing
Completion F.J.P.B
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WELL COMPLETION
9 5/8” casing
Tubing 6 ½” to surface Liner hanger Polished bore receptacle Liner 7”
Perforations © - IFP Training
MONO-BORE COMPLETION Completion F.J.P.B
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WELL COMPLETION MONO-BORE COMPLETIONS In highly prolific reservoirs, tubing of 6 ½” and larger diameters is required to meet cost-effective production and injection objectives. The use of big mono-bore completion techniques can increase production rates significantly while decreasing both capital and operating expenses. The advantages of the big mono-bore completion systems include the elimination of gas-turbulence areas and restrictions on production. This can translate to fewer wells required for optimized reservoir production, resulting in a faster return on initial investments and lower long-term operating expense. MONO-BORE COMPLETIONS ARE MAINLY USED IN THE “DEEP” OFF-SHORE FEWER WELLS, MORE PRODUCTION PER WELL WELL INTERVENTION ALLMOST NOT POSSIBLE MONO-BORE COMPLETIONS ARE FITTED WITH PRESSURE AND TEMPERATURE TRANSMITTERS
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Completion F.J.P.B
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WELL COMPLETION
MONO-BORE COMPLETIONS Mono-bore completions are basically liner-top completion systems. The key is the large inside diameter (ID) tubing that allows increased production rates and provides full-bore access to the production liner. Full-bore access gives the operator the ability to run conventional tools through the tubing to perform remedial work in the production liner without disturbing the completion or pulling the production tubing. There are many styles of mono-bore completions from which to choose. The selection of the type system that is used depends largely on the pressure integrity, and the pressure capability, of the liner top and intermediate casing string. © - IFP Training
Completion F.J.P.B
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WELL COMPLETION
MONO-BORE COMPLETIONS
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In the most basic mono-bore-completion design , the production liner is run and cemented in the hole. At the top of the liner hanger is a polished bore receptacle (PBR) to accept a seal assembly. The production tubing that is used has basically the same ID as the liner. When the completion is run, a seal assembly is run on the bottom of the production tubing and landed in the PBR. The seal assembly and liner top provide the annular barrier for the tubing string. The constraints of this system are: The ID of the polished bore receptacle can become damaged during liner cleanout trips and fail to seal. The ability of the liner top to hold pressure is totally dependent on the quality of the cement job. • Remedial work to the liner may be required before running the completion. Completion F.J.P.B
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WELL COMPLETION
ADVANCED MONO-BORE COMPLETION A more reliable mono-bore system will use a packer above the liner top. In this system, the liner is run and cemented as before. When the completion is run, a large-bore hydraulic-set permanent packer is installed. The packer will have a PBR (Polished Bore Receptacle) located above it, with the tubing seals run in place. There is also a seal assembly on the tailpipe below the packer, which is stabbed into the liner top. The packer provides a more positive annular barrier, and a new PBR has been installed. © - IFP Training
Completion F.J.P.B
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WELL COMPLETION
9 5/8” casing 6 ½” tubing Polished bore receptacle 9 5/8” packer
Liner hanger Polished bore receptacle 7” Liner © - IFP Training
ADVANCED MONO-BORE COMPLETION Completion F.J.P.B
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COMPLETION EQUIPMENT
WELL COMPLETION
THE MAIN ELEMENTS OF A COMPLETION
1) X-Mas tree c/w Tubing hanger 2) Tubing: the flow path for the well effluents to the x-mas tree 3) Packer: isolates the tubing from the annulus 4) Various seats and safety equipment
© - IFP Training
Completion F.J.P.B
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WELL COMPLETION
A BASIC SINGLE STRING COMPLETION
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Completion F.J.P.B
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WELL COMPLETION A SINGLE STRING COMPLETION IN TANZANIA SONGO SONGO 10 (GAS WELL) 1 2 3
4
1- Control line for TRSCSSSV 2- Flow-coupling 3- TRSCSSSV 4- Tubing 5” 5- Baker nipple AR bottom no-go 4,125” 6- Baker SB packer 7- Liner 7” 8- Baker nipple AF top no-go 3,125” 9- Perforated joint 10- Baker AR nipple bottom no-go 3,125” 11- SXAR wire-line entry guide
5 6 7 © - IFP Training
8 9 10 11 Completion F.J.P.B
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CHRISMAS TREES
CHRISMAS TREES
THE “CHRISTMAS TREE” IS FITTED ONTO THE “WELLHEAD” IT CONSIST OUT OF A SERIES OF VALVES FITTED ONTO A CROSS BY FLANGES. CHRISTMAS TREES ARE RATED TO THEIR WORKING PRESSURE, AND INTERNAL DIAMETER. THE VALVES ARE NORMALLY “GATE” VALVES VERY OFTEN, A CHOKE IS FITTED ONTO THE OUTLET OF THE TREE. FROM THE CHRISTMAS TREE THE WELL EFFLUENT IS ROUTED TO THE PROCESS FACILITIES.
© - IFP Training
Completion F.J.P.B
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CHRISMAS TREES Christmas tree Control line for SCSSV Pressure test port Lock-down screw (or tie down screw) Tubing hanger
Lateral outlet to control the annulus Tubing Tubing head spool © - IFP Training
Casing
Completion F.J.P.B
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CHRISMAS TREES
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Completion F.J.P.B
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CHRISMAS TREES X-MAS TREE TYPES
HORIZONTAL TREES
CONVENTIONNAL VERTICAL TREES
DUAL COMPLETION TREES
SOLID BLOCK TREES
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Completion F.J.P.B
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CHRISMAS TREES CHRISMAS TREE DESIGN
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Completion F.J.P.B
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CHRISMAS TREES
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Completion F.J.P.B
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CHRISMAS TREES
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Completion F.J.P.B
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CHRISMAS TREES
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Completion F.J.P.B
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CHRISMAS TREES
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Completion F.J.P.B
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CHRISMAS TREES
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Completion F.J.P.B
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CHRISMAS TREES “Y” DESIGN CHRISMAS TREE
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Completion F.J.P.B
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CHRISMAS TREES
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“Y” Design Chrismas tree Completion F.J.P.B
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CHRISMAS TREES
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Completion F.J.P.B
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CHRISMAS TREES GATE VALVE
Used on x-mas trees
WP:3 000 – 5 000 – 10 000 Psig
ID ; depends on the tubing size
Sour Service
API Flanged
Can hold pressure both sides
Seat API Flange
Completion F.J.P.B
© - IFP Training
Gate
CHRISMAS TREES ADJUSTABLE CHOKE SEAT TIP
WP: 10 000 Psig Size: 3” Tungsten seat and tip OUT
Choke size 2½”
In
Never have the choke closed completely with pressure behind it. Impossible to open it. © - IFP Training
Completion F.J.P.B
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CHRISMAS TREES
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Completion F.J.P.B
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TUBING
TUBING TUBING EIGHT TUBING DESIGN FACTORS
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Tension-It must withstand its own weight in the running environment. Tubing must stand additional loads when pulling out or setting packers and forces due to temperature and pressure changes. Burst-Tubing must maintain integrity with high internal pressure and little or no annular Pressure support. Collapse-Proper tubing must maintain integrity with high annulus pressure with little or no internal pressure support. Compression-The tubing must withstand compressive loads when setting some packers and in high deviated wells or “dog legs” Couplings-Should be free from leaks, maintain the ID clearance, strength through bend areas and in compression and tension loads. Corrosion-Tubing must designed to counter corrosion reactions with the following fluids over it’s lifetime (ex:CO2, H2S, Acid, Cracking). Abrasion/Erosion-Equipment must withstand abrasion and erosion loads over lifetime. Stimulation loads -Tubing must withstand loads from Acid, Fracturing or other stimulation Completion F.J.P.B
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TUBING TYPES OF TUBING CONNECTIONS (thread)
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Hydril dopeless
New VAM
VAM TOP
Hydril
Completion F.J.P.B
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TUBING
VAM HWST premium thread
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Completion F.J.P.B
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TUBING
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RTS6 Connection premium thread
Completion F.J.P.B
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TUBING
VAM TOP premium thread
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Completion F.J.P.B
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TUBING
TUBING SPECIFICATIONS
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Completion F.J.P.B
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TUBING
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Completion F.J.P.B
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TUBING
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Completion F.J.P.B
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TUBING
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Completion F.J.P.B
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TUBING
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Completion F.J.P.B
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TUBING
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Completion F.J.P.B
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TUBING
Production tubing Inside NominNominal aNominal lNominal Nominal Inside Drift Oil flow Gas flow rate NoNominal mNominal inal Nominal Inside Drift Oil flow Gas flow rate Inside weight diameter tubing wetubing igtubing ht diameter rate (P= 15MPa tubingweight weight diameter rate (P=15MPa diameter 2 20 psi) 2 20 psi) diamdiameter ediameter tediameter r diameter (in) 2 3/8" 2 7/8" 3 1/2" 4" 4 1/2" 5 1/2" 7"
CRITERIA
a) OIL : Pfriction b) GAS : Pfriction
(mm) (mm) (m3/d) (103 Sm3/d) (lb/ft) (lb/ft) (in) (lb/ft) (lb/ft) (in) (in) (b l/d) (106 cuft/d) 50.7 48.3 150 150 2 3/8" 4.64.6 4.6 1.945 1.901 90 5 62 59.6 275 275 6.4 6.4 2 7/8" 6.46.4 2.4 1 2.347 1 70 10 76 72.8 450 450 3 1/2" 9.29.2 9.2 2.9 2 2.867 2 80 16 10.9 4" 10.9 10.9 8 .3 85.1 70 70 10.9 3.476 3.351 4 40 25 10 .5 97.4 10 0 10 0 12.6 4 1/2" 12.6 12.6 3.958 3.83 6 30 35 17 5 1/2" 17 17 124.3 121.1 170 170 17 4.892 4.767 1 0 0 60 29 7" 29 29 157.1 153.9 30 0 30 0 29 6.184 6.059 19 0 0 105 47 9 5/8" 47 47 2 0.5 216.5 70 0 60 0 8.681 8.525 4 0 0 210
(mm) (mm)
(in) (in)
50.7 50.7 1.945 1.945 62 62 2.441 2.441 76 76 2.992 2.992 88.3 88.3 3.476 3.476 100.5 100.5 3.958 124.3 4.892 4.892 157.1 157.1 6.184 6.184 220.5 220.5 8.681
(mm) (mm) 48.3 48.3 59.6 59.6
72.8 85.1 85.1 97.4 97.4 121.1 153.9 153.9 216.5 216.5
0.25 MPa/1000 m (10 psi / 1000 ft) 1 MPa/1000 m (40 psi / 1000 ft)
Oil flow rate
(in) (in) 1.901 1.901
(m3/d)
900
Nominal Nominal Inside tubing weight diameter diameter
2.347 2.867 2.867 3.351 3.351 3.833 4.767 4.767 6.059 6.059 8.525 & &
(in)
(mm) (in)
2 3/8"
4.6
50.7
2 7/8"
6.4
62
3 1/2"
9.2
76
450
4"
10.9 12.6
5 1/2"
17
7"
29
9 5/8"
47
Drift
Oil flow rate
(mm)
(lb/ft)
4 1/2"
(P = = 15 15 MPa MPa (P 200 psi) psi) 2 200 2
(bbl/d)
150 275
Gas flow rate
(in) 48.3
1.945
88.3
85.1
700
153.9 8.681
1000 1700 3000 7000 velocity velocity
19 000
7000 8.525
(P = 15 MPa 2 200 psi)
2 800 11 000
3000 6.059
216.5
700
6 300 1700
4.767
6.184 220.5
4 400 1000
3.833 121.1
4.892 157.1
2 800
3.351 97.4
3.958 124.3
900
1 700
450 2.867
3.476 100.5
Gas flow rate (103 Sm3/d) (106 cuft/d) 150 5 275 10 450 16 700 25 1000 35 1700 60 3000 105 6000 210
1 700
275 2.347
72.8 2.992
(bbl/d)
150 1.901
59.6 2.441
(m3/d)
44 000
4 400 6 300 11 000 19 000 44 000
(1033 Sm Sm33/d) /d) (1066 cuft/d) cuft/d) 150 5 5 275 10 450 16 16 700 25 25 1000 35 1700 60 60 3000 105 105 6000 210
2 m / s (6.5 ft / s) 10 m / s (33 ft /s)
© - IFP Training
9 5/8"
(mm) (mm) (m3/d) (103 Sm3/d) (lb/ft) ((in) in(in) )(in) (in) (b l/d) (106 cuft/d) 53/8" 0.7 48.3 150 150 3/8" 222 4.6 3/8" 1.945 1.901 90 5 67/8" 2 59.6 275 275 7/8" 222 6.4 7/8" 2.4 1 2.347 1 70 10 71/2" 6 72.8 450 450 1/2" 333 9.2 1/2" 2.9 2 2.867 2 80 16 84" .3 85.1 70 70 10.9 4" 4" 3.476 3.351 4 40 25 101/2" .5 97.4 10 0 10 0 1/2" 44 14 2.6 1/2" 3.958 3.83 6 30 35 121/2" 4.3 121.1 170 170 1/2" 55 15 7 1/2" 4.892 4.767 1 0 0 60 157" 7.1 153.9 30 0 30 0 29 7" 7" 6.184 6.059 19 0 0 105 2 5/8" 0.5 216.5 70 0 60 0 5/8" 99 49 7 5/8" 9 5/8" 8.681 8.525 4 0 0 210
Drift
Completion F.J.P.B
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TUBING
Completion string consist out of tubing lengths screwed together.
Lengths are in general +/- 10 meter.
To avoid thread galling, the thread has to be greased.
Disadvantage of using grease is that a lot of grease will drop inside the tubing and might fall on top of an installed plug, which makes it impossible to fish the plug after packer setting. Excess of grease fallen in the well, might damage the formation.
In order to avoid the use of grease, new ways are found to “pre-grease” the threads.
We call this “dopeless” © - IFP Training
Completion F.J.P.B
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TUBING GALLING WHILE SCREWING PIPE THREADS TOGETHER
Galling is a form of wear caused by adhesion between sliding surfaces. When a material galls, some of it is pulled with the contacting surface, especially if there is a large amount of force compressing the surfaces together. Galling is caused by a combination of friction and adhesion between the surfaces, followed by slipping and tearing of crystal structure beneath the surface. This will generally leave some material stuck or even friction welded to the adjacent surface, while the galled material may appear gouged with balled-up or torn lumps of material stuck to its surface. Once the “galling starts the parts are in a way welded together and almost impossible to unscrew the two screwed parts.
© - IFP Training
Completion F.J.P.B
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TUBING
Dopeless® technology is a dry, multifunctional coating applied to TenarisHydril premium connections for casing and tubing in the mill.
The coating is applied in a fully automatic process, assuring that the exact amount of the lubricant required by each connection is distributed in a controlled and uniform way on its surface.
The process is carried out on dedicated production lines at the mills and manufacturing facilities.
The main objective of the Dopeless® coating is to eliminate the thread compounds used for casing & tubing, providing a “ready-to-use” product
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Completion F.J.P.B
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TUBING
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PIN Completion F.J.P.B
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TUBING COMPLETION
BOX
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Completion F.J.P.B
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TUBING
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Completion F.J.P.B
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TUBING
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Completion F.J.P.B
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TUBING
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Completion F.J.P.B
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TUBING
© - IFP Training
Over “Greasing” Completion F.J.P.B
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TUBING COMPLETION
Advantages of “dopeless” technology: (According to the vendor)
0% grease spillage (environment)
Nearly “0” re-makes and rejects
10% savings of total pipe cost
Running time reduced by 25%
© - IFP Training
Completion F.J.P.B
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TUBING
TUBING MOVEMENTS / FORCES due to Pressure Changes Temperature Changes
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Completion F.J.P.B
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TUBING
Tubing calculations depends on how the tubing is attached in/onto the packer. (The tubing is fixed with the tubing hanger in the well-head, so no movement will occur)
Two ways to attach the tubing in or to the packer:
Tubing fixed onto the packer, which means no tubing movement in the packer. In this case only forces on the packer or tubing hanger have to be calculated.
Tubing can move in or around the packer with a seal bore and expansion joint mechanism. In this case only tubing length changes have to be calculated
© - IFP Training
Completion F.J.P.B
70
TUBING There are four factors that tend to cause a change in the length or force in the tubing string: Temperature effect, which is directly influenced by a change in the average temperature of the string. Piston effect, caused by a change in the pressure in the tubing or annulus above the packer acting on a specific area. Ballooning effect, caused by a change in average pressure inside or outside the tubing string. Buckling effect, which occurs when internal tubing pressure is higher than the annulus pressure.
© - IFP Training
Tubing movements due to pressure and temperature changes Completion F.J.P.B
71
TUBING
X-MAS TREE
TUBING HANGER
CASING VALVE
Tubing in a landed position. Able to move inside of the packer. So everybody happy, but during the well’s life, the tubing Is directly attacked by it’s enemies. Not only by corrosive effluents, but as well by pressures and temperature changes.
EFFLUENT
TUBING
STINGER IN SEAL-BORE
PACKER
PERFORATIONS
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RESERVOIR
Completion F.J.P.B
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TUBING
TEMPERATURE CHANGES:
Temperature changes will occur when the well is put on production. Downhole temperatures are higher than the surface temperature ,therefore the tubing will become longer Temperature changes will occur when the well is treated from the surface. (acid job, frack, etc..) It cools down the surface temperature and therefor the tubing will shorten.
© - IFP Training
Completion F.J.P.B
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TUBING
PRESSURE CHANGES
Pressure changes may occur when the well is put on production. Annulus pressure increases due to the warm up of the completion fluid, when the well is put on production. Annulus pressure increases during reverse circulation, pumping fluid into the annulus from the surface. Tubing pressure increases when the packer is hydraulically set, by means of a plug inside the tubing.
© - IFP Training
Completion F.J.P.B
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TUBING : PISTON EFFECT
The length change or force induced by the piston effect is caused by pressure changes inside the annulus and tubing at the packer, acting on different areas. The length and force changes can be calculated as follows:
∆L1
∆L1
Pr Annulus
Pr Tubing
Pr Annulus
Pr Tubing
ΔL1 = length change because of the piston effect, F1 = force change because of the piston effect, L = tubing length, E = modulus of elasticity (30,000,000 for steel), As = cross-sectional area of the tubing wall, Ap = area of the packer bore (values for common sizes can be found in table )
Ai = area of the tubing ID, Ao = area of the tubing OD, Δpi = change in tubing pressure at the packer Δpo = change in annulus pressure at the packer. © - IFP Training
Completion F.J.P.B
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PISTON EFFECT
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Completion F.J.P.B
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TUBING CALCULATIONS
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Completion F.J.P.B
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BUCKLING EFFECT
X-MAS TREE
TUBING HANGER
CASING VALVE
EFFLUENT
TUBING
STINGER IN SEAL-BORE
PACKER
PERFORATIONS
Completion F.J.P.B
ΔL2 = length change because of the buckling effect; r = radial clearance between tubing OD and casing ID,[(ID C – ODt)/2]; Ap = area of the packer bore; Ai = area of the tubing ID; Ao = area of the tubing OD; Δpi = change in tubing pressure at the packer; Δpo = change in annulus pressure at the packer; E = modulus of elasticity (30,000,000 for steel); I = moment of inertia of tubing about its diameter I = π/64 (D4 – d4), w D = the tubing OD and d is the tubing ID*; Ws = weight of tubing per inch*; Wi = weight of fluid in tubing per inch*; and Wo = weight of displaced fluid per inch.* (* = values for common tubing sizes can be found in Tables 2 and 3).
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RESERVOIR
Tubing strings tend to buckle only when the internal tubing pressure (pi) is greater than the annulus pressure (po). The result is always a shortening of the tubing string, but the actual force exerted is negligible. The decrease in length occurs because of the tubing string being in a spiral shape rather than straight. The tubing-length change is calculated with the following:
78
TEMPERATURE EFFECT
X-MAS TREE
TUBING HANGER
CASING VALVE
EFFLUENT
TUBING
Thermal expansion or contraction causes the major length change in the tubing. Heated metal expands, and cooled metal contracts. In a long string of tubing with a temperature change over its entire length, this contraction or elongation can be considerable. The three operational modes that influence temperature effect are producing, injecting (water, gas, or steam), and treating. The change in tubing length because of temperature effect is calculated as follows:
STINGER IN SEAL-BORE
PACKER
PERFORATIONS
where ΔL= change in tubing length, L = tubing length, ẞ = coefficient of thermal expansion (0.0000069 for steel), and Δt = change in average temperature
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RESERVOIR
∆L=Lxẞx∆t
Completion F.J.P.B
79
TEMPERATURE EFFECT
Length changes are calculated readily if the average temperature of the tubing can be determined for the initial condition and then again for future operations. The average string temperature in any given operating mode is approximately one-half the sum of the temperatures at the top and the bottom of the tubing. Thus, in the initial condition, the average temperature would be based upon the mean yearly temperature and the BHT. The mean yearly temperature is generally considered to be the temperature 30 ft below ground level; Δt is the difference between the average temperatures of any two subsequent operating modes.
© - IFP Training
Completion F.J.P.B
80
BALLOONING EFFECT
X-MAS TREE
TUBING HANGER
CASING VALVE
EFFLUENT
TUBING
STINGER IN SEAL-BORE
PACKER
PERFORATIONS
© - IFP Training
RESERVOIR
The ballooning effect is caused by the change in average pressure inside or outside the tubing string. Internal pressure swells or "balloons" the tubing and causes it to shorten. Likewise, pressure in the annulus squeezes the tubing, causing it to elongate. This effect is called "reverse ballooning.“ The ballooning effect will always result in tubing-length changes, but it does not become a force unless the tubing movement is restrained at the packer. The ballooning and reverse ballooning length change and force are given by:
Completion F.J.P.B
81
BALLOONING EFFECT
ΔL = length change because of ballooning/reverse ballooning, F = force change because of ballooning/reverse ballooning, L = tubing length, γ = Poisson’s ratio (0.3 for steel), E = modulus of elasticity (30,000,000 for steel), Δpia = change in average tubing pressure, Δpoa = change in average annulus pressure, Ai= area of the tubing ID, Ao = area of the tubing OD, and R = ratio of tubing OD to ID (given in Table) for common tubing sizes and weights. © - IFP Training
Completion F.J.P.B
82
COMPLETION EQUIPMENT
Completion F.J.P.B
COMPLETION
COMPLETION EQUIPMENT Some completion equipment suppliers:
Halliburton
Baker
Camco
Weatherford
Hunting © - IFP Training
Etc…
Completion F.J.P.B
84
WELL COMPLETION
CROSS-OVERS
NIPPLES
SLIDING SIDE DOORS
FLOW COUPLINGS
BLAST JOINTS
PERFORATED JOINTS
ENTRY GUIDE
SIDE POCKET MANDRELS
© - IFP Training
Completion F.J.P.B
85
WELL COMPLETION Cross Over (X-over)
BOX
PIN
© - IFP Training
Cross-overs are used when we want to connect two different sized tubing with different thread sizes. Ex: 4 ½” x 3 ½” Completion F.J.P.B
86
NIPPLES HALLIBURTON LANDING NIPPLES
“X”
“XN”
“R”
“RN”
© - IFP Training
Completion F.J.P.B
87
NIPPLES BAKER LANDING NIPPLES (“sure set” family)
Bottom No-Go
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Top No-Go
Completion F.J.P.B
88
COMPLETION EQUIPMENT BAKER LANDING NIPPLES
Profile for the dogs
Seal bore
Top No-Go Seal bore
Bottom No-Go
AR
© - IFP Training
AF
A nipple is fitted in the tubing, in which we can hang-off gauges or set plugs. They come in different sizes, main dimensions are their “no-go” and “seal bore”
Completion F.J.P.B
89
COMPLETION EQUIPMENT
The flow coupling is used to protect the integrity of the tubing from erosive turbulence. Flow couplings are often used above and below a geometric restriction in a flow path, depending on the well conditions. API recommended practices 14B advises use of two flow couplings above and below safety valves.
© - IFP Training
FLOW COUPLING
Completion F.J.P.B
90
COMPLETION EQUIPMENT
The blast joint positioned opposite the perforations in the casing, is used in the tubing string of a flowing well to protect it from the abrasive action of the flowing well. It exposes the maximum of metal in the abrasive area, maintaining at the same time API tubing ID and coupling OD. Length 10’ or 20’
© - IFP Training
BLAST JOINT Completion F.J.P.B
91
COMPLETION EQUIPMENT
The perforated tubing is used at the end of a tubing string to provide an alternate flow path in cases where wireline measuring devices are used.
Completion F.J.P.B
© - IFP Training
Nipple in which we can hang-off gauges.
PERFORATED TUBING 92
COMPLETION EQUIPMENT The wire line entry guide is designed to be run on the bottom of the tubing string. It will aid wire line tools re-entry in the tubing especially in deviated wells Casing Tubing WIRE LINE ENTRY GUIDE Wire-line string © - IFP Training
Completion F.J.P.B
93
COMPLETION EQUIPMENT
PACKERS
© - IFP Training
Completion F.J.P.B
94
PACKERS F
F
RETRIEVABLE MECHANICAL PACKER
© - IFP Training
Tension setting
Compression setting
Completion F.J.P.B
95
PACKERS
THE “PACKER” FORMS THE BASIS OF THE CASED HOLE COMPLETION DESIGN. The Packer is a sealing device that isolates and contains produced fluids and pressures within the well bore to protect the casing and other formations above or below the producing zone This is essential to the basic functioning of most wells.
© - IFP Training
Completion F.J.P.B
96
PACKERS USES OF PACKERS In addition to providing a seal between the tubing and casing, other benefits of a packer are as follows:
Prevent downhole movement of the tubing string Support some weight of the tubing Often improve well flow and production rate Protect the annular casing from corrosion from produced fluids and high pressure Provide a means of separation of multiple producing zones Limit well control to the tubing at surface for safety purposes Hold well-servicing fluid (kill fluids, packer fluids) in the casing annulus
© - IFP Training
Completion F.J.P.B
97
PACKERS PACKER COMPONENTS Packers have four key features: Slip Cone Packing element system Body or mandrel The slip is a wedge-shaped device with wickers (or teeth) on the face, which penetrates and grip the casing wall when the packer is set. The cone is a beveled to match the back of the slip and forms a ramp that drives the slip outward and into the casing wall when setting forces are applied to the packer. Once the slips have anchored into the casing wall additional applied setting force energizes the packing element system and creates a seal between the packer body and the inside diameter of the casing.
© - IFP Training
Completion F.J.P.B
98
PACKERS F
F
SETTING THE PACKER The slip is a wedge-shaped device with wickers (or teeth) on the face, which penetrates and grip the casing wall when the packer is set. Slips The cone is a beveled to match the back of the slip and forms a ramp that drives the slip outward and Cone into the casing wall when setting forces (F) Are applied to the packer. Once the slips have Packer seals anchored Into the casing wall additional applied setting force (F)energizes the packing element system and creates a seal between the packer body and the inside diameter of the casing.
© - IFP Training
Completion F.J.P.B
99
PACKERS
Packer classification Production packers can be classified into two groups:
Retrievable
Permanent
© - IFP Training
Completion F.J.P.B
100
PACKERS PERMANENT PACKERS Permanent packers can be removed from the wellbore only by milling. Retrievable packers may or may not be reusable, but removal from the wellbore normally does not require milling. Retrieval is usually accomplished by some form of tubing manipulation. This may necessitate rotation or require pulling tension on the tubing string. The permanent packer is fairly simple and generally offer higher performance in both temperature and pressure rating than does the retrievable packer. In most instances, it has a smaller outside diameter (OD) offering greater running clearance inside the casing string than do a retrievable packers. The smaller OD and the compact design of a permanent packer help the tool to negotiate through tight spots and deviations in the wellbore. The permanent packer also offers the largest inside diameter (ID) to make it compatible with larger-diameter tubing strings and mono-bore completions. © - IFP Training
Completion F.J.P.B
101
PACKERS RETRIEVABLE PACKERS The retrievable packer can be very basic for low pressure/low temperature (LP/LT) applications or very complex in high pressure/high temperature (HP/HT) applications. Because of this design complexity in high-end tools, a retrievable packer offering performance levels similar to those of a permanent packer will invariably cost more. However, the ease of removing the packer from the wellbore as well as features, such as reset ability and being able to reuse the packer often, may outweigh the added cost
© - IFP Training
Completion F.J.P.B
102
PACKERS
RETRIEVABLE TENSION PACKER
© - IFP Training
The tension packer is typically used in medium- to shallow-depth (LP/LT) production or injection applications. The tension packer has a single set of unidirectional slips that grip only the casing when the tubing is pulled in tension. Constant tubing tension must be maintained to keep the packer set and the packing element energized. Tension packers, typically, are set mechanically and are released by means of tubing rotation. Most models also have an emergency shear-release feature should the primary release method fail.
Completion F.J.P.B
103
PACKERS RETRIEVABLE TENSION PACKER WITH BY-PASS AND HOLD-DOWN ANCHOR
© - IFP Training
More common models of the compression packer with bypass have an additional set of hold-down slips, or an anchor system above the packing-element system. This packer sets and releases in much the same manner as the compression packer discussed previously. In this model, however, the addition of The hold-down slip helps to keep the pack-off force and bypass valve locked in place when pressure below the tool is greater than the pressure in the annulus. This variation can be used in limited treating operations, in gas lift applications, or in production applications in which tubing pressures are greater than annular pressures. However, there are limitations to the ability of the anchor to keep the bypass closed, and any operational modes that will result in loss of set-down weight must be planned carefully.
Completion F.J.P.B
104
PACKERS HYDRAULIC SET SINGLE STRING PACKER
© - IFP Training
The hydraulic-set packer has a bidirectional slip system that is actuated by a predetermined amount of hydraulic pressure applied to the tubing string. To achieve a pressure differential at the packer and set it, a temporary plugging device must be run in the tailpipe below the packer. The applied hydraulic pressure acts against a piston chamber in the packer. The force created by this action sets the slips and packs the element off. Some models have an atmospheric setting chamber and use the hydrostatic pressure of the well to boost the pack-off force. Regardless of design, all of the force generated during the setting process is mechanically locked in place until the packer is later released. Once the packer is set, the tubing may be landed in tension (limited by the shear-release value of the packer), compression, or neutral
Completion F.J.P.B
105
PACKERS HYDRAULIC-SET SINGLE-STRING PACKER.
Special considerations include the following: Well stimulation must be planned carefully to avoid premature shear release of the packer. Maximum tensile capabilities of the tubing string when selecting the shearrelease value of the packer are required. A temporary plugging device must always be incorporated below the lowermost hydraulic-set packer to facilitate hydraulic setting of the packer.
© - IFP Training
Because no tubing manipulation is required to set a hydraulic packer, it can be set easily after the wellhead has been flanged up and the tubing has been displaced. This promotes safety and allows better control of the well while displacing tubing and annulus fluids. The hydraulic-set packer can be run in a single-packer installation, and because no packer body movement occurs during the setting process, it can be run in tandem as an isolation packer in single-string multiple-zone production wells. The hydraulic-set single-string packer is ideal for highly deviated wells in which conditions are not suitable for mechanical-set packers.
Completion F.J.P.B
106
PACKERS RETRIEVAL OF THE PACKER Retrieval of the hydraulic-set single-string packer is accomplished by pulling tension with the tubing string to shear a shear ring, or shear pins, located within the packer. Most models also have a built-in bypass system that allows the pressures in the tubing and annulus to equalize, or balance, as the packer is released. The tension load required to release the packer must be considered carefully in the initial completion design and in the selection of the shear-ring value. The shear-release value must not be set too high so that it will not be beyond the tensile capabilities of the tubing string, yet it must be high enough so that the packer will not release prematurely during any of the planned operational modes over the life of the completion.
© - IFP Training
Completion F.J.P.B
107
PACKERS DUAL STRING PACKERS This is basically a “mid-string” isolation packer that is designed to seal off approximately two strings of tubing. The dual packer allows the simultaneous production of two zones while keeping them isolated. Most multiple-string packers are retrievable; however, some permanent models exist for use in HP/HT applications. Standard configurations have bidirectional slips to prevent movement and maintain pack-off with the tubing landed in the neutral condition.
© - IFP Training
Completion F.J.P.B
108
PACKERS
For the most part, multiple-string retrievable packers are set hydraulically because the tubing manipulation required to set a mechanical packer is not desirable or (often) not feasible in a dual-string application. However, mechanical-set models do exist, and in applications in which the tubing strings are run independently, the mechanical-set dual packer can be set with applied slack-off force by the upper tubing string.
The dual-string hydraulic-set packer is set much the same as the hydraulic-set single-string packer. The setting pressure typically is applied to the upper tubing (short string), but some models are designed to be set with pressure applied to the lower tubing (long string). A temporary plugging device is required to be run below the dual packer on the appropriate string to allow the actuating pressure to be applied.
© - IFP Training
Completion F.J.P.B
109
PACKERS PERMANENT AND RETIEVABLE SEAL-BORE PACKERS
The permanent and retrievable seal-bore packers are designed to be set on electric wireline or hydraulically on the tubing string. Wireline setting affords speed and accuracy; however, the one-trip hydraulic-set versions offer the advantage of single-trip installations and allow the packer to be set with the wellhead flanged up.
© - IFP Training
Completion F.J.P.B
110
PACKERS
SEAL-BORE PACKERS
Seal bore packers have a honed and polished internal seal-bore. A tubing seal assembly with elastomeric packing forms the seal between the production tubing and the packer bore. Well isolation is accomplished by the fit of the elastomeric seals in the polished packer bore. To accommodate longer seal lengths, a seal-bore extension may be added to the packer.
In the case of the one-trip hydraulic-set seal-bore packer system, the production tubing, tubing seal assembly, and packer are made up together and run as a unit. However, if the packer is to be installed on electric wireline or set on a work string, the seal assembly is run on the production tubing after the packer is installed and stabbed into the packer bore downhole.
© - IFP Training
Completion F.J.P.B
111
PACKERS
© - IFP Training
Completion F.J.P.B
112
PACKERS
LOCATORS
Locator type
© - IFP Training
Anchor type
The seal assembly may be a locator type, which allows seal movement during production and treating operations, or an anchor type, which secures the seals in the packer bore and restricts tubing movement. The decision about the best seal assembly to run depends on tubing movement and hydraulic calculations based on: Initial landing Flowing or shut-in conditions Any stimulation or treatment that may be planned for the well. The removable seal assembly allows tubing to be retrieved for work-over without the need of pulling and replacing the packer.
Completion F.J.P.B
113
PACKERS
Generally, the permanent seal-bore packers, both wireline and hydraulic set, afford much higher performance in both temperature and pressure ratings than do any of the retrievable packers. The one disadvantage is that the permanent packer must be milled over to remove the packer from the wellbore. For the most part, milling is not prohibitive and, in many cases, may never be required. However, removal may be necessary if subsequent work-over operations require full-bore access to the casing below the packer or if a packer failure should occur.
© - IFP Training
Completion F.J.P.B
114
PACKERS
Landing conditions
The tubing string is attached to the packer by two methods:
It is latched or fixed to the packer by means of an anchor seal assembly (in the case of a seal-bore packer) or tubing thread (most retrievable packers).
The tubing is landed with a seal assembly and locator sub in the polished bore of a permanent or retrievable seal-bore packer. In this case, the upward tubing movement at the packer is limited only by the length of the seal assembly. Any downward movement is restricted by the locator sub.
© - IFP Training
Completion F.J.P.B
115
PACKERS
Excessive tubing buckling can severely limit the length and diameter of throughtubing tools that can be run through the tubing string. Tubing buckling is caused by: Tubing landing conditions that require compression on the packer An overall increase in tubing temperature, which will cause the tubing to elongate An increase in internal tubing pressure The piston effect on locator type seal assemblies. These conditions can be minimized if the completion is designed properly. Care should be taken when planning the completion to thoroughly review the various operating conditions to which the well will be subjected and to select a packer to fit the operation.
© - IFP Training
Completion F.J.P.B
116
PACKERS
CASING CLEAN-UP OPERATIONS Any debris or obstruction that is present in the wellbore can cause most packers to malfunction. Any cement that may have been left on the casing wall from previous cementing operations, as well as scale buildup in the case of old wells, can also lead to poor packer performance. To properly grip the casing and form a leak-proof seal, the packer slip and element system must make 100% contact with the casing wall. It is advisable to run a casing scraper or other suitable casing cleanout tool and circulate the well clean before installing the production packer. A casing scraper should always be run in instances in which a packer is to be conveyed through new perforations.
© - IFP Training
Completion F.J.P.B
117
PACKERS
Casing scraper (left) wire-line junk basket and Gauge ring (right)
© - IFP Training
Completion F.J.P.B
118
PACKERS
Before running any packer on electric wireline, it is advisable to run a wireline junk basket and gauge ring. The gauge ring has a slightly larger outer diameter (OD) than the packer and “gauges” the hole to ensure that there are no tight spots that might cause the packer to become stuck, or accidentally set in the hole. The junk basket is also designed to collect any debris that is suspended in the completion fluid that otherwise might interfere with running the packer.
© - IFP Training
Completion F.J.P.B
119
PACKERS OTHER CASING CONSIDERATIONS Before installing the packer, a cement bond log should be considered to verify the integrity of the primary cementing job on the casing string. If a poor cement bond exists in the interval in which the packer is to be set, the packer’s ability to serve as a barrier may be compromised should a leak in the casing string occur. Such a leak could allow the formation below to communicate to the annulus above the packer. If such a channel is created, the annulus could be exposed to high formation pressures, or the formation itself may be damaged. Either case could lead to a costly work-over. There are special applications in which the packer is intentionally set in unsupported or un-cemented casing. Care should be taken in these instances to ensure that the design of the packer is such that radial loads and stresses created by setting the packer, and those anticipated to be encountered during various operating conditions, do not exceed the stress limitations of the casing. © - IFP Training
Completion F.J.P.B
120
PACKERS
METALLURGY FOR DOWNHOLE EQUIPMENT
© - IFP Training
Completion F.J.P.B
121
PACKERS
Corrosive conditions Metallurgical requirements are dictated both by the downhole well environment and the design and performance requirements of the packer. Consideration must be given to both when selecting and specifying materials for corrosive environments. Many types of materials that are applicable for tubing and casing in corrosive environments are not always suitable (or practical) for packer manufacture. The NACE International (formerly National Association of Corrosion Engineers) Standard MR-01-75 establishes guidelines and acceptance criteria for material selection for sour service in H2S environments.
© - IFP Training
Completion F.J.P.B
122
PACKERS COMMON MATERIALS USED FOR DOWNHOLE EQUIPMENT Some commonly used materials for manufacture of downhole equipment are as follows: •
•
•
•
© - IFP Training
•
Low-alloy steels with minimum yield strengths of 110 kpsi are used for standard service in noncorrosive environments. These materials are similar in property to P110 tubing and do not meet NACE MR-01-75 requirements for sour service. Low-alloy steels with a maximum hardness of Rockwell 22C, which meet NACE MR-01-75 requirements, are intended for use in both standard service and service in sour H2S environments. Materials that fall into this range would be similar in properties to J-55 to L-80 grades of tubing. Martensitic steels such as 9% chromium, 1% molybdenum, and 13% chromium alloy steels are used in some wet CO2 environments. Certain grades of these steels meet NACE MR-01-75 requirements and can be used in limited H2S applications. 22% chromium and 25% chromium duplex stainless steel are commonly used in some wet CO2 and mild H2S environments. Austenitic stainless steels, cold worked 3% Mo high-nickel alloy steels, and precipitation-hardening nickel-based alloys are suitable for some environments containing high levels of H2S, CO2, and chlorides at moderately high temperatures
Completion F.J.P.B
123
PACKERS
The successful application of any of these materials depends strongly on the specific downhole well environment. Many factors such as temperature, pH, chlorides, water, H2S, and CO2 concentrations can have adverse effects on the material performance and can lead to failures associated with: •
Pitting.
•
Corrosion.
•
Chloride stress cracking.
•
Hydrogen embrittlement.
© - IFP Training
Completion F.J.P.B
124
PACKERS
MATERIALS USED IN PACKERS Ideally, the packer should be built out of materials that will last the life of the well. Also, in the case of retrievable packers that may be reconditioned and used elsewhere, the advantage of being able to reuse the packer may be lost if the well environment corrodes or damages the tool beyond repair. In potentially corrosive environments, material failure can lead to a packer leak or difficulty in removing a retrievable packer from the wellbore. In these cases, corrosion-resistant alloy materials must be properly selected that are best suited to the downhole well environment. Because of the vast number and variations of packer designs and tensile requirements of their components, the consumer cannot know which materials are appropriate for each particular design. Ultimately, the user must rely on the packer manufacturer to help make the determination as to which materials will meet the downhole requirements without sacrificing packer performance and reliability. © - IFP Training
Completion F.J.P.B
125
PACKERS
PACKER ELASTOMERS
© - IFP Training
Completion F.J.P.B
126
PACKERS CONSIDERATIONS IN SELECTING AN ELASTOMER
© - IFP Training
There are many suitable elastomers on today’s market to match almost any downhole condition. Care must be taken to ensure that the elastomer selected for the packer and seal assembly meets all the downhole conditions to which it will be subjected. Things that must be considered are: Downhole operating temperature Exposure to produced or injected fluids and gases Exposure to completion fluids such as oil-based mud, brine, bromides, high pH completion fluids, and amine base inhibitors Exposure to solvents such as xylene, toluene, and methanol. There is no single best elastomer that will perform under all conditions combined, and selection must be tailored to suit individual well requirements and application. By far, the most common elastomer used in downhole completion packers is nitrile. Nitrile is used in low- to medium-temperature applications for packers and packer-totubing seal assemblies in one form or another. It shows good chemical resistance to oils, brines, and CO2 exposure. However, its use is limited in wells that contain even small amounts of H2S, amine inhibitors, or high-pH completion fluids. Exposure to high concentrations of H2S and bromides generally is not recommended.
Completion F.J.P.B
127
PACKERS TYPES OF ELASTOMERS Hydrogenated nitrile (HNBR) Hydrogenated nitrile or HNBR (chemical name: hydrogenated acrylonitrile butadiene) has a somewhat higher temperature rating and shows slightly better chemical resistance to H2S and corrosion inhibitors than standard nitrile. HNBR is more prone to extrusion than standard nitrile and, as a result, requires a more sophisticated mechanical backup system similar to that found on most permanent and higher-end retrievable packers. Fluor elastomers Two fluoroelastomers that are commonly used in the oil and gas industry are: • Hexafluoropropylene (vinylidene fluoride, commonly known by the trade name Viton) • Tetrafluoroethylene (propylene, trade name Aflas) © - IFP Training
These compounds are used in medium- to high-temperature applications. Both compounds show excellent resistance to H2S exposure in varying limits, CO2, brines, and bromides. However, the use of Viton should be questioned when amine inhibitors are present in packer fluids and in the case of high-pH completion fluids.
Completion F.J.P.B
128
PACKERS Examples of Fluor elastomers Aflas will swell when exposed to oil-based fluids and solvents. Swelling, because of exposure of Aflas to hydrocarbons, is generally only a concern when running the tool in the well. Element swell may cause the packer to become stuck on the trip in the hole, and swelling of the seals can result in seal damage during stab-in. After the packer is set and seals are in place, the swelling generally is no longer a concern. The use of Kalrez and Chemraz in the packer industry is by and large limited to chevron-type “vee” seals and “o”-rings. On the cost scale, they are by far some of the most expensive materials used in these designs. Kalrez and Chemraz show good resistance to most chemicals found in oil-well and gas-well environments. Because of their ability to maintain stability at extreme temperatures, they are normally recommended for use in HP/HT applications and in most environments in which high levels of H2S are encountered. © - IFP Training
Ethylene propylene (EPDM) is an elastomer commonly used in steam-injection operations. EPDM exhibits poor resistance to swelling when exposed to oil and solvents; however, EPDM can operate in pure steam environments to temperatures of 550°F. Completion F.J.P.B
129
PACKER
PACKING ELEMENT The term “packing element” is used to describe the elastomeric sealing system that creates the seal between the outside diameter (OD) of the packer and the inside diameter (ID) of the casing. The ability of the packing element to hold differential pressure is a function of the elastomer pressure, or stress across the seal. To form a seal, the elastomer pressure must be greater than the differential pressure across the packer. The elastomer pressure is generated by the pack-off or setting force applied to the packer. The packing-element system consists of the seal or packing element and a packingelement backup system. When energized, the packing element expands to conform to the ID of the casing wall. The packing-element backup system contains the energized packing element and restricts the element from extruding or losing its elastomer pressure © - IFP Training
Completion F.J.P.B
130
PACKERS
PACKING ELEMENT SYSTEM DESIGN There are many different packing-element-system designs. Each element-system design is suited to a specific application and covers a myriad of well environments. The most basic packing-element system consists of a single packing element with fixed metal backup rings located above and below the element. More sophisticated designs may consist of multidurometer elastomers using a lower durometer element between two elements of a higher durometer. In this design, the lower durometer, or softer-center element, creates the working seal while the higher durometer, or harder-end, elements expand to the casing ID to restrict extrusion. Fixed metal backup rings also may be replaced with flexible or expandable backup rings to further restrict the extrusion of the elastomer.
© - IFP Training
Completion F.J.P.B
131
PACKERS
PACKER-TO-TUBING SEAL STACKS Permanent and retrievable seal-bore packers contain a honed seal-bore to accept packer-to-tubing seals or seal assembly to connect the tubing string to the packer. This seal assembly, or stinger, consists of a seal sub with multiple packing units or seal stacks fixed on its OD. The packing units come in a variety of configurations and elastomeric compounds to suit a wide range of downhole conditions. There are two basic types of packing units: • •
Bonded Chevron
© - IFP Training
Completion F.J.P.B
132
PACKERS BONDED PACKING UNIT The bonded packing unit is composed of one or more metal rings, with a specific elastomer compound bonded or molded to the ring. The bonded seal by design is slightly larger than the ID of the seal-bore, and a predetermined amount of stress on the elastomer is created when the seals are inserted into the honed packer bore. The elastomer pressure generated by this stress creates a seal between the seal assembly and the honed packer bore.
© - IFP Training
Because the bonded seals are self-energized, they are particularly useful in low pressure/low temperature (LP/LT) gas-injection operations such as CO2 flood projects. The bonded seals are also less susceptible to dynamic unloading damage and should be selected any time that the seals must leave the honed bore under pressure. Only a few elastomer compounds are suitable for use in bonded seal designs. The three most common compounds found on bonded seal stacks are: • Nitrile • Viton • Aflas • Because the bonding tends to fail at higher temperatures, most bonded seals are generally not recommended for service above 300°F. Completion F.J.P.B
133
PACKERS CHEVRON PACKING UNIT Chevron seal stacks come in a wide variety of designs and elastomeric compounds. They consist of a number of “vee”-shaped chevron seal rings supported by metal (or a combination of metal and non-elastomeric) backup rings such as Ryton or Teflon. Each individual chevron seal ring holds pressure in one direction only, so each seal stack must contain a number of seal rings facing in either direction. The chevron seal stacks are the most versatile and widely used. They are available with various elastomers and designs. Common materials used for the “vee”-type seal rings include: • Nitrile (the most common) • Viton • Aflas • Kalrez Some specialized premium seal stacks can handle pressures up to 15,000 psi (and beyond) at temperatures approaching 550°F. Each has its own environmental application, as well as temperature and pressure rating. Matching the proper elastomer to the environment is a key to long-term sealing success. © - IFP Training
Completion F.J.P.B
134
PACKERS
The Chevron seal stacks do not lend themselves well to differential unloading conditions that might be experienced during fracturing or treating operations in which locator-type seal assemblies are used in seal-bore packers. The temperature and piston effects will cause the tubing to shorten, and the seal assembly will move upward out of the packer bore. Any Chevron seal that is allowed to leave the polished seal-bore will be subject to severe damage, because of the sudden change in differential pressure. Because of this, locator-type seal-assembly designs should be such that the working seals are never allowed to leave the polished packer bore under differential pressure.
© - IFP Training
Completion F.J.P.B
135
PACKERS
EFFECTS OF SEAL MOVEMENT To reduce the possibility of seal failure and greatly extend the life of the seal assembly, it is recommended that seal movement be restricted whenever possible. While both chevron and bonded seals are designed to hold pressure under dynamic conditions, completion designs that allow continuous seal movement over the life of the well can significantly shorten the life of the seal. Seal movement should be eliminated altogether if possible by anchoring the seals in the packer bore. Locator seal assemblies should be landed so that the locator sub will be in constant compression when the well is producing, thus limiting movement to those cases in which the well is either treated or killed.
© - IFP Training
Completion F.J.P.B
136