stybarrow subsea & fa for subsurface grp

STYBARROW EXECUTION PHASE

SUBSEA & FLOW ASSURANCE OVERVIEW for information only information may not be latest

AOAT21 April 2005Page 2

Revised Stybarrow Subsea Configuration


Flowline Sizing: Stybarrow Production Flowlines A paired 8 flowline from H3 and H4 is specified, with a design liquids rate of

35000 bpd. Minimum turndown for stable flow from these wells is ~13500 blpd. A paired 7 flowline from H1 and H2 is specified, with a design liquids rate of

25000 bpd. Minimum turndown for stable flow from these wells is ~6000 blpd. The paired flowline configuration for the Stybarrow production wells is required to

allow hot oil circulation to warm the flowlines prior to restart. This minimises the volume of MeOH required to inhibit hydrates on restart (see later).

Insulation of 5.5W/m2K is specified for the Stybarrow production flowlines to achieve an 8 hour no touch cooldown period.

Ramp up rates are limited by sand control considerations only. Some ramp up slugging is evident, but this is within the surge capacity of the Test and HP separators.


Stybarrow flowlines gas and liquid rates early life (~yr 1)STYBARROW H2 EARLY RISER TOP GAS AND LIQUID RATES

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Liquid flow rate at riser top Gas flow rate at riser top

STYBARROW H1 EARLY RISER TOP GAS AND LIQUID RATES

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Stybarrow flowlines gas and liquid rates mid life (~yr 3)STYBARROW H1 MID RISER TOP GAS AND LIQUID RATES

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STYBARROW H2 MID RISER TOP GAS AND LIQUID RATES

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STYBARROW H4 M ID RISER TOP GAS AND LIQUID RATES

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Stybarrow flowlines gas and liquid rates late life (~yr 8+)STYBARROW H1 LATE RISER TOP GAS AND LIQUID RATES

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Flowline Sizing: Stybarrow Gas Lift Flowline The gas lift flowlines have been sized for a gas flow rate of 35 MMscfd to H3 and

H4 and then for 21 MMscfd from H3/H4 to H1/H2. A 4inch flowline from the riser base to Sty H3/H4 and on to Sty H1/H2 is

required. A 6inch riser is specified. For a gas lift compressor discharge pressure of 200 bara, the pressure at H3/H4

wellhead is 193-198 bara, and 183-194 bara at H1/H2 wellhead. The minimum gas lift rate for flow stability is ~2MMscfd


Flowline Sizing: Eskdale Gas Injection Flowline A 6-inch riser and flowline for gas injection to Eskdale is specified. For a gas injection compressor discharge pressure of 280 bara (4060 psia), the

pressure at the injection wellhead is 296 bara (4298 psia). This exceeds the advised required injection pressure of 276 bara (4000 psia) at the wellhead.

The design flowrate of the gas injection flowline is 36MMscfd

GI Riser/Flowline Profile Pressure Profile


Flowline Sizing: Stybarrow Water Injection Flowline Fracture pressure injection has been selected as the base case for water

injection based on the results of the injectivity studies. The required water injection pressure at the reservoir is;

For 25,000 bwpd to I1 with I2/I3 shut in, minimum 383 bara at I1 injection point For 110,000 bwpd total to I1/ I2 and I3, minimum 338 bara at any of the

injection points. The water injection system comprises a 10inch riser, a smooth bore 9 flowline to

I2 with an 9 jumper between I2 and I3, and a 6 flowline to I1. For the selected flowline configuration

The required topsides discharge pressure to flow 25,000 bwpd to I1 at an injection pressure of 383 bara is 185 bara.

A topsides pressure of 170 bara will provide 360 and 358 bara pressures at I1 and I2/I3 respectively.

The water injection pump has been specified with characteristics of a 200 bara(2900 psia) discharge pressure @ 25,000 bwpd and 170 bara discharge pressure at 110,000 bwpd.


Flow Assurance IssuesISSUE PREVENTION MITIGATION REMEDIATION

Hydrates Insulation for steady state. CI for Eskdale Prod well.

Hydrate inhibitor injection during transient events (startup / shutdown).

Circulation of non-hydrating (stabilised crude oil) fluid to displace FWS fluid and warm flowline for start-up for Sty wells.

Blowdown and possibly flushing.

Hydrate inhibitor injection. MeOH

Blowdown from both sides of blockage.

Methanol injection to melt hydrate.

Pigging & flushing with non -hydrating fluid. Dead Crude

Sand Downhole sand control Ensure erosionalvelocities not exceeded

Provision for sand production monitoring and handling equipment on topsides

Asphaltenes Asphaltene risk considered low. Downhole CI not provided.

Well workover, chemical soak.

Scale Scale inhibitor injection at subsea tree.

Emulsions Continuous injection of demulsifier (at well/manifold).


Hydrate Management: Stybarrow Production FlowlinesSHUTDOWN 8 hour no touch time on shutdown is achieved by flowline insulation Blowdown to the FPSO is required if start-up within 8 (4) hours cannot be achieved. The residual pressure at the wellhead is between 3 and 9 bara after blowdown. Batch MeOH injection into the tree and uninsulated piping between the tree and flowline

will be required for all production wells on shutdown. This should be carried out as soon as practical after the well is shut in.

Methanol injection into the well bore is required for shutdowns >8hours. Delayed SSSV closure to allow draining of fluids below SSSV is being considered.

START-UP Hot oil circulation will be used to warm the flowlines above the hydrate formation

temperature prior to restart of the production wells. Batch MeOH injection into the wellbore prior to restart (if not injected on shutdown). MeOH injection required for SSSV equalisation required if SSSV is closed. MeOH injection at tree during first 20-30mins of flow until well fluids are warmed as

indicated on the tree temperature monitoring may be required for shutdowns >2weeks.NORMAL OPERATION No continuous MeOH injection is required for Stybarrow.


Hydrate Management: Eskdale Production and Gas Injection, and Stybarrow Gas Lift FlowlinesESKDALE PRODUCTION FLOWLINE High GLR makes the use of insulation to prevent flowline operation within the

hydrate formation region impractical. Insulation specification allows 2-3 hour period between shutdown and blowdown. Continuous MeOH injection at the well head is proposed. Alternatives to MeOH

(eg LDHIs) to be investigated during operations phase. Condensed water only is predicted during early years of operation. Free water

production is evident in late life.

GAS LIFT and GAS INJECTION FLOWLINES Gas will be dehydrated to a water dewpoint of -1degC at 300 bar at topsides. If glycol dehydration unit is unavailable or off-spec MeOH injection into the gas

compressor discharge lines will be utilised to inhibit condensed water. Provision for MeOH injection at the GI tree for use during backflow of gas for fuel

gas or well kickoff.


Stybarrow Field Layout and Flowline Lengths


Stybarrow Drill Centre A Water Injection I2, I3

Water Injection

10 riser

6 flowline to I1

9 smooth bore flowline to I2, I3

9 30m jumper between I2,I3

Future WI flowline will tie into I3


Stybarrow Drill Centre B I1, H3, H4Production

8 flowlines to H3, H4

8 30m jumper between H3,H4 with isolation valve on each tree

4 gas lift to H4, then through tree to H3.

4 Gas lift flowlinecontinues to H1 and H2


Stybarrow Drill Centre C H1, H2Production

7 flowlines to H1, H2

7 30m jumper between H1,H2 with isolation valve on each tree

4 gas lift to H2, then through tree to H1.


Stybarrow Drill Centre D Esk H1, Esk I1Eskdale

4 flowline to Esk H1 (riser is 6)

4 30m jumper between production and injection trees.

6 gas injection flowline(and riser) to Esk I1.


STY, ESK PROD TREEAAV

PMV PWV PCAWV

GLC

XOV

AMV

CIV1 CIV2 CIV3

Position TBD

Tree Frame

FIVProduction 8"

e.g. Scale Inhibitor 1/2" ID

e.g. Demulsiifier 1/2" ID

MeOH 1" ID

Annulus / Gas Lift 4"

SCSSV

DHPT

TT

PT

PT

PT

XSD

ZT

PT

TT

ZT

Subsea sand detectors installed on each tree

SSSV to be 400m below mudline to avoid hydrate formation in Stybarrow wells, and 500m below the mudline for the Eskdale wells

Non self-equalising SSSVsselected. This will require methanol injection for pressure equalisation prior to opening on restart.

Demulsifier, scale inhibitor and methanol to be injected at tree.


ESK GI TREEAAV

PMV PWV PCVAWV

XOV

AMV

CIV1

Tree Frame

Injection / Production 8"

MeOH 1/2" ID

Annulus 4"

SCSSV

DHPT

TT

PT

PT

ZT

PT

TT

Upstream and downstream choke pressure and temperature monitoring and choke position provided.

Flow measurement at topsides

Annulus pressure monitoring

Downhole pressure monitoring


STY WI TREEAAV

IMV IWV

ICV

XOV

AMV

Water Injection 8"

SCSSV

(Well I-1 only)

PTPT

PT

ZT

DHPT

Upstream and downstream choke pressure plus choke position monitoring provided.

Total water injection flow is measured topsides.

Annulus pressure monitoring provided.

Downhole pressure monitoring on I1 only

STYBARROW EXECUTION PHASERevised Stybarrow Subsea ConfigurationFlowline Sizing: Stybarrow Production Flowlines Stybarrow flowlines gas and liquid rates early life (~yr 1)Stybarrow flowlines gas and liquid rates mid life (~yr 3)Stybarrow flowlines gas and liquid rates late life (~yr 8+)Flowline Sizing: Stybarrow Gas Lift Flowline Flowline Sizing: Eskdale Gas Injection FlowlineFlowline Sizing: Stybarrow Water Injection FlowlineFlow Assurance IssuesHydrate Management: Stybarrow Production FlowlinesHydrate Management: Eskdale Production and Gas Injection, and Stybarrow Gas Lift FlowlinesStybarrow Field Layout and Flowline Lengths Stybarrow Drill Centre A Water Injection I2, I3Stybarrow Drill Centre B I1, H3, H4Stybarrow Drill Centre C H1, H2Stybarrow Drill Centre D Esk H1, Esk I1STY, ESK PROD TREEESK GI TREESTY WI TREE

stybarrow subsea & fa for subsurface grp

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