Tension Leg Platform - ALRDC - Home - Artificial Lift … · A" Annulus Packer Brine = 8.4 lb/gal...

1© 2004 Weatherford. All rights reserved.

Jerry W. RobinsonFebruary, 2006

Tension Leg PlatformGas Lift


Tension Leg Platform – Gas LiftJerry W. Robinson

• Deepwater TLP completions in the Gulf of Mexico present special challenges because of the water depths, pressures and environment.

• Because each of these completions are unique from one another, equipment is designed to meet specific parameters.

• There are many design variations for gas lift/chemical mandrels already available __ I’m sure there’s more to come.

• The gas lift design process and specific equipment used in several deepwater installations will be presented today.



• In some instances the riser sections of these completions must be unloaded. There are several methods used:1. Most TLP’s production casing runs through the riser

to the surface. Generally unloaded through gas lift mandrels placed in the production string.

2. Unload through a sliding sleeve placed in the gas lift injection line when production casing does not run to surface.

3. Unload through a control line installed in the riser section when production casing does not run to surface.



• The method used in the gas lift design of deepwater wells is essentially the same as in other gas lift installations witha few other considerations such as:

– water depths – production rates – tubing sizes – gas injection system pressures (KO & OP)– Temperature profiles– Special metallurgy



1. Water depths = 3,000’ to 6,000’2. 1500 to 10,000 BLPD3. 3.5”, 4.5” and 5.5” tubing4. 1400 psi to 3200 psi kickoff pressure5. 1400 psi to 3000 psi operating pressure6. Temperature profiles; Shelf Well vs. Deepwater Well. 7. Inconel, Super 13 Chrome-110 and 13 Chrome-85

material


TYPICAL TEMPERATURE PROFILE FOR ONSHORE OR SHELF (SHALLOW WATER) OFFSHORE WELL


EXAMPLE of FLOWING TEMPERATURE PROFILE for DEEPWATER OFFSHORE



• Reservoir information for initial and future production rates are evaluated with various nodal analysis programs (WellFlow, WEM, Prosper) for predicting:

– Optimum tubing size(s) for natural flow conditions

– Predicted reservoir pressure declines– Gas lift performance (injection depth,

injection pressure, injection rates, etc)– Production system upgrades



• Other parameters can effect the gas lift design and gas lift equipment in deepwater TLP well completions. For this presentation, there are three (3) examples:

– EXAMPLE (1) __ Casing restrictions & H2S Environment

– EXAMPLE (2) __ 2940 ft Water Depth, Casing & Liner restrictions, gas injection pressure upgrade from 1400 psig to 2950 psig

– EXAMPLE (3) __ 3400 ft Water Depth, Casing restrictions, gas lift design & mandrel spacing for unloading purpose



• EXAMPLE (1)– Six control lines are run in the well. 8-5/8” casing is

run to 9207’ MD, 7-5/8” to 9300’ and a 5.5” production liner run to depth.

– Production tubing is 4” 10.9# from 0 to 9000’ .– SBHP = 3000 psi.– Well is located in a water flood field and future H2s

production is a possibility. Metallurgy for tubing and accessories is 25 Chrome and Inconel.


Mudline at 3214+ below MSLA" Annulus Packer Brine = 8.4 lb/gal 2% KClB" Annulus Brine = 11.2 lb/gal CaCl2

PROPOSED MECHANICAL SKETCH*

Prod Csg Prod Tbg8 5/8" 44 lb/ft 4" 10.9 lb/ft - from 0' to 9,000' * Completion detail only; ML wellhead, outer casings, riser, tree omitted7.626" ID 25Cr-125M, VARST1

7.560" Spec. Drift 3.351" Drift Xmas Tree Wellbay Slot 143.476" ID Config. = B Water Depth 3214'

WP = 10 ksi RT Elevation 191' above MSLBore = 4 1/16" *All depths based on H&P 202 TLP rig

4 1/2" Baker Mudline Hanger @ 3639' except as noted(86'+ below DrillQuip 8 5/8" casing hanger) Production Riser

Nominal OD: 10 3/4"ID: 9.835" + 0.010"

Landing Nipples Control LinesType Size Bore No-Go Depth Type Size Wall Material DepthRPT 3 1/2" 2.750" ------ 5900' MLTH 1/2" .049" 316L 3639 XN 2 3/8" 1.875" 1.791" 15073' Chem Inject 3/8" .049" 825 5708'

Chem Inject 3/8" .049" 825 5858'SCSSV 1/4" .065" 825 5900Hydraulic GLM 1/4" .049" 825 9079'DHPG 1/4" .028" 825 14926'

3 1/2" & 2 3/8" Gas Lift Mandrels MD TVD Mandrel Valve TRO Choke / Port

9079' 8600' 3 1/2" Hydraulic 10024' 9200' 2 3/8" 1.0"10989' 9800' 2 3/8" 1.0"11925' 10400' 2 3/8" 1.0"12752' 11000' 2 3/8" 1.0"13512' 11600' 2 3/8" 1.0"14255' 12200' 2 3/8" 1.0"

3 1/2" RPT Profile (2.750" Seal Bore)3 1/2" HES SP 10K SCSSV, alloy 718@ 5900' (max allowable depth=6100')

8 5/8" X 7 5/8"

X-over @ 9207Prod casing

TOL 5 1/2" @ 9300' 7 5/8" 39.0 lb/ft6.625" ID

Prod Liner 6.500" Drift5 1/2" 20 lb/ft From 9207' to 9300'CYP-110 Hydril 5134.778" ID Prod Tubing 1st KOP: 4.653" Special Drift From 9000' to 15,046' will have SC-80 couplings 2nd KOP:

3 1/2" 10.2# 2.922" ID, 2.797" Drift Hole Angle through perforations = 36 deg22Cr-125, VARST1 SC-80

Prod Tubing2 JTS BELOW DHPG AT 14,926'3 1/2" 10.2# 2.922" ID, 2.797" Drift22Cr-125, VARST1

Production Packer Assembly

2 3/8" SCHL. DHPG Mandrel; Bore = 1.991" @ 14,926'HES "HVT" Production Packer alloy 718 ; Bore = 2.375" @ 15,046'3 1/2" "XN" Nipple (1.791" no-go) Set at < ?? Degrees @ 15,073'Ported sub @ 15,095'Production stinger Bore = 2.???" Push thru collect and indexing mule shoe

"N" SANDHES VTA Gravel Pack Packer @ 15,102'; Bore - 2.750"Ceramic Fluid Loss FlappersShear Sub (50,000# Shear Value)

20x40 US Mesh Perforations: 15330-430' (100')GP Sand 12 JSPF

Alloy 825 All Welded WWS (0.008" slot) on 2 3/8",4.7 lb/ft super 13CR95 Pipe, VARST1 Push Thru Collet, Seal Stinger with Mule Shoe

Sump Packer 15,440' (Min 10' below bottom perf)

PBTD = 15,550'TD 15,655' 5 1/2" ,20#, CYP-110, Hydril 513, casing Shoe @ 15,645'

Directional Detail

Completion Design SummaryOne perforated, gravel packed completion is installed in the N sand. High rate acid jobs and gravel packs were pumped to achieve low skin. 3 1/2" 22 chrome production tubulars are installed due to the H2S expected. A permanent downhole pressure gauge (i.e., PDG) will provide continuous reservoir pressure information. A 4-1/16" bore Xmas tree (10 ksi WP) utilizes a single wing and choke with a 6" Coflexip flow line leading to the TLP hard piped flow line. The production tubulars are installed through a large bore 10 3/4"x8 5/8" dual casing riser.


TLP – Gas LiftJerry W. Robinson

• The top gas lift mandrel (Hydraulic Valve) is located as deep as possible without going into the 5” liner.

• The depth of the hydraulic gas lift valve is not effective as the SBHP declines to 3000 psi or less.

• For deeper injection depths, retrievable, slimhole gas lift mandrels are positioned in the liner section every 600’to the top of the packer. This 600’ spacing was selected because it would provide for optimum gas lift operations over a broad range of rates and pressures.


Liquid Rate Gas Inj Depth

Qg inj (Mscfd)50004000300020001000

LIQ

UID

RA

TE

(b

bl/d

)

2600

2400

2200

2000

1800

1600

1400

GA

S IN

J D

EP

TH

(f

t)

10050

10000

9950

9900

9850

9800

9750

9700

9650

System Deliverability Plot

Fluid Properties : Oil Gr = 34.0 API Gas Gr = 0.66 Water Gr = 1.06 WLR = 50.0 % GOR = 500.0 scf/bbl

Wellbore Data : WHP = 250.0 psig TVD = 13029. ft Corr =Hage/Brown Tbg/4.000/15150 Csg/0.00/15151

Reservoir Data : Pr = 3000.0 psig BHT = 220.0 deg F

PI = 8.0 b/d/psi

LIQ

UID

RA

TE

(b

bl/d

)

2600

2400

2200

2000

1800

1600

1400

GA

S IN

J D

EP

TH

(f

t)

10050

10000

9950

9900

9850

9800

9750

9700

9650


Liquid Rate�OPER P DIF = 150.0 Liquid Rate�OPER P DIF = 200.0Liquid Rate�OPER P DIF = 268.0 Liquid Rate�OPER P DIF = 400.0Liquid Rate�OPER P DIF = 500.0 Gas Inj Depth�OPER P DIF = 150.0Gas Inj Depth�OPER P DIF = 200.0 Gas Inj Depth�OPER P DIF = 268.0Gas Inj Depth�OPER P DIF = 400.0 Gas Inj Depth�OPER P DIF = 500.0

Qg inj (Mscfd)50004000300020001000

LIQ

UID

RA

TE

(b

bl/d

)

3000

2500

2000

1500

1000

GA

S IN

J D

EP

TH

(f

t)

10500

10000

9500

9000

8500

8000





PI = 8.0 b/d/psi

LIQ

UID

RA

TE

(b

bl/d

)

3000

2500

2000

1500

1000

GA

S IN

J D

EP

TH

(f

t)

10500

10000

9500

9000

8500

8000



• Because H2s production is possible, it was necessary to use a gas lift mandrel that would not allow any produced fluids to enter into the casing annulus in any circumstance, even if the pocket was empty.

• The DVX mandrel was developed to meet this criteria.• External check valves are installed on the gas lift mandrel

and injection gas passes through them into the valve pocket area and out into the tubing string.

• The external checks prevent any flow from the tubing back into the casing regardless of what type of valve or check mechanism if any, is loaded into the pocket. Valve changes can be done without any worry of tubing-to-casing communication path.

• Status: installation of equipment pending.



DVX mandrel features true secondary pressure barrier from tubing to casing provided by external check valves



• EXAMPLE (2)– Water Depth: 2940’– Production Casing: 7-58” 33.7# , 7-5/8” 39# and 5.5”

20#– Production Tubing: 4.5” 15.10# to SSCSV and 3.5”

10.2# to depth, 13 chrome 110 ksi– Gas lift operating pressures of 1400 psi and 2400 psi

are evaluated


Tubing4 1/2", 13.5#, SM25CR125, VARST-1ID 3.920", Drift 3.795"Coupling OD 5.030"(Max) Beveled

3 1/2", 10 ksi Schumberger HPCI-DC-II CIN w/ sliding sleeve VARST-1-SB5.50"±OD x 2.902" Min ID, 2.797" Drift, w/Pup Joints T&B **

3 1/2", 10 ksi SCSSV HES SP VARST-1-SB5.40" OD x 2.750" ID, w/Pup Joints T&B **2.750" Bore "RPT" LN Profile in Top Sub

6007' MD

Hanger Setting / Annulus Displacing Tube

Production Casing

Cameron Back Pressure Valve Prep

Chemical Injection 3/8" OD x .065" Wall,

x 7", 38#, P-110, 10,650'-TDID 6.625" Drift 6.50" x ID 6.094", Drift 5.969"

3 1/2", 10 ksi, Schlumberger PDPG Mandrel

PDPG TEC 1/4" OD x .028" wall, I825 (Encapsulated 9MM round)

H:/c

once

pt/m

ars/

mar

-a15

-a.d

wg

04/1

2/04

SCSSV 1/4" OD x .065" Wall, 2205 Duplex

2.656" Drift. Production Pkr, Baker HP/HT Edge7", 38#, VARST-1 T&B, 5.70" Max OD, 2.70" Min ID

2.562" Bore OTIS "RN" LN, 2.329" Min ID,VARST-1, w/Pup Joint ** @ 17,398'

3 1/2" Straight Slot LocatorGP Packer @17,293' MD WL

2 7/8", 26' Lead-in w/ Indexing Mule Shoe

Port Closing SleeveFluid Loss Control Device

w/ 25CR, 85 ksi mandrel

6136' MD

5.33"OD, 5.55" OD drift, 2.902" ID, 2.867" ID drift w/ Pup Joint T&B **

(1) Joint, Tubing **


6' Pup Joint **

Pup Joint,4 1/2", 13.5#, SM25CR125, VARST1

** 3 1/2", 10.2#, SM25CRW125, VARST-1 Beveled

6' Pup Joint **

3/8" OD x .049 Wall 316L SS

Baker Mudline Tubing Hanger, VARST-12.912"ID, 2.867" Drift, 6068' MD, w/Pup Joints T&B **

3 1/2" Blank, 232', 13CR

302', 316 SS Wire Wrap Screen

7" Casing Shoe @ 19,400' MD WL

Inconel 825

@ 17,333' MD Tubing Tally

on 13CR Base, 4.12 OD x 2.992" Drift

Packer Releases w/ Retrieving Tool.

17,253' MD

protector and centralizer placement.NOTE: See tubing detail for control line

Annular Fluid: 2% KCl water plus O and

Sump Packer @ 17,889' MD WL

Cement Retainer @ 19,324' MD WLwith 100' of Cement on top.

5.695" OD

7 5/8", 39#, P-110, 0'-2940' x 7", 32#, P-110, 2940'-10,650'

x ID 5.920", Drift 5.795"


17,418' MD Tubing Tally

(16' is 8 ga non-perf, 32' is 6 ga, 254' is 8 ga)

fish at 18,162 MD DP. (18,052' MD WL)Pushed 2 Sump Packers downhole. top of

No Shear Joint run below GP Packer

WATER DEPTH 2940'

I625 on 4130 75ksi material with 718 internals.NOTE: Tree is FMC 4 1/16", 10k, BMV is full clad

Remainder of tree is 410 SS body and trim.

Schlumberger WRFC-H GLM control line1/4" OD x .049" wall, 2205 Duplex filled w/ Diala-ax



2.867" Drift, 24CR, 85 ksi mandrel. Anchor has 100,000 lb

Baker SRA, sz 80-40, made up to top of packer5.558" Max OD, 2.972" Min ID

shear ring release or right hand rotation.

Hole angle through

is 68 @ 17,888'.Max hole angle

Note:

perfs is 65 - 68 .Perforate 17,610'-880'UPPER GREEN (M ) SANDwith 12 spf.

2

GP Packer are tied to WL depths.strap. Measurements below theGP Packer are from the tubing tallyMeasurements above the

w/ PQG gauge VARST-1-SB, 25Cr, 80 ksi

Pup Joint T&B **5.672" OD, 2.716" ID, 2.637" drift. Mandrels have dummies installedWeatherford 3 1/2" SBRO-2 GLM @ 7586', 10,411', 15,808',

Casing patch across EBO @ 7900'Weatherford-HOMCO .089" wall, 20' long, 5.894" ID

Casing patch across MLCH @ 3260'Weatherford-HOMCO .089" wall, 20' long, 5.894" ID

Weatherford-HOMCO .089" wall, 20' long, 5.894" IDCasing patch across FMC Casing hanger

I718 FMC Tubing Hanger

Tension rating of mandrel is 315,000 lbs. @ 6208'. Mandrel has turned down SM25CRW125 coupling. Schlumberger WRFC-H GLM, 5.70" OD, 2.724" ID, 2.681" drift

Choke in FCV has two 1/16"


slots, Pup joint T&B **

H S scavengers2

2



Qg inj (Mscfd)4000350030002500200015001000

LIQ

UID

RA

TE

(b

bl/d

)

4500

4000

3500

3000

2500

GA

S IN

J D

EP

TH

(f

t)

7200

7000

6800

6600

6400

6200





PI = 5.0 b/d/psi

LIQ

UID

RA

TE

(b

bl/d

)

4500

4000

3500

3000

2500

GA

S IN

J D

EP

TH

(f

t)

7200

7000

6800

6600

6400

6200



Qg inj (Mscfd)4000350030002500200015001000

LIQ

UID

RA

TE

(b

bl/d

)

5600

5200

4800

4400

4000

3600

3200

2800

GA

S IN

J D

EP

TH

(f

t)

16500

16000

15500

15000

14500

14000





PI = 5.0 b/d/psi

LIQ

UID

RA

TE

(b

bl/d

)

5600

5200

4800

4400

4000

3600

3200

2800

GA

S IN

J D

EP

TH

(f

t)

16500

16000

15500

15000

14500

14000


• The hydraulic valve at 6208’ is used with the operating pressure of 1400 psi.

• Future platform plans call for upgrading gas injection system to a 2950 psioperating pressure.



• The gas lift mandrels at 7586’, 10409’ and 15433’will be utilized if the operating casing pressure is increased to 2950 psi; under the assumed production rates of 6500 to 8000 blpd.

• Status: Shut in due to storm damage.




• EXAMPLE (3)– Water Depth: 3400’– Production Casing: 8-5/8”– Production Tubing: 4.5”– Gas lift operating pressure 1800 psi– Based on information supplied by operator for current

and future reservoir parameters, an unloading gas lift mandrel spacing was installed

– STATUS – currently flowing on its own, waiting on rig move so wireline operations be done



Qg inj (Mscfd)40003000200010000

LIQ

UID

RA

TE

(b

bl/d

)

12570

12560

12550

12540

12530

12520

12510

12500

GA

S IN

J D

EP

TH

(f

t)

5950

5945

5940

5935

5930

5925

5920

5915



Wellbore Data : WHP = 392.0 psig TVD = 19142. ft Corr =Hage/Brown Tbg/4.500/20259 Tbg/2.875/20506 Csg/8.63/20526 Csg/8.63/20850


PI = 16.64 b/d/psi

LIQ

UID

RA

TE

(b

bl/d

)

12570

12560

12550

12540

12530

12520

12510

12500

GA

S IN

J D

EP

TH

(f

t)

5950

5945

5940

5935

5930

5925

5920

5915


Liquid Rate

Qg inj (Mscfd)40003000200010000

LIQ

UID

RA

TE

(b

bl/d

)

8000

7800

7600

7400

7200

7000

6800

6600





PI = 16.64 b/d/psi


TVD vs Pres�Rate = 7800 TVD vs Inj Gas Pres�Rate = 7800Mandrel Depth�Mandrel = Mandrel 1 Mandrel Depth�Mandrel = Mandrel 2Mandrel Depth�Mandrel = Mandrel 3 Mandrel Depth�Mandrel = Mandrel 4Mandrel Depth�Mandrel = Mandrel 5 Mandrel Depth�Mandrel = Mandrel 6Mandrel Depth�Mandrel = Mandrel 7 Mandrel Depth�Mandrel = Mandrel 8Mandrel Depth�Mandrel = Mandrel 9 Mandrel Depth�Mandrel = Mandrel 10

PRESSURE (psig)6000500040003000200010000

TRU

E V

ER

TIC

AL

DE

PTH

(ft)

20000

15000

10000

5000

0NEW SPACING�

Pressure Profile

Rate = 7800.0 bbl/d Fluid Properties : Oil Gr = 27.0 API Gas Gr = 0.765 Water Gr = 1.06 WLR = 5.0 % GOR = 891.0 scf/bbl




• Summary– As can be seen in the gas lift deliverability plots, gas lift

had little impact based on original reservoir data. An unloading design was therefore chosen in the event the well loaded up. An unloading rate of 2000 BFPD was used to space out the unloading mandrels. Had the current reservoir data been used to design the gas lift spacing, a closer mandrel spacing would have been used in order to optimize production with gas lift. The new deliverability plot indicates an increase of 500 BFPD with 4 MMSCF of input gas at a depth of 6,600'.

Tension Leg Platform - ALRDC - Home - Artificial Lift … · A" Annulus Packer Brine = 8.4 lb/gal...

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Transcript of Tension Leg Platform - ALRDC - Home - Artificial Lift … · A" Annulus Packer Brine = 8.4 lb/gal...