application of surface controlled gas lift valves on … · application of surface controlled gas...
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Application of Surface Controlled Gas Lift Valves on BHPB Lennox Field
Eric Lovie, Schlumberger Aberdeen
Kevin Burke, BHP BillitonLondon
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Field Overview
• Lennox field is part of BHP Billiton’s Liverpool Bay Development
• Blocks 110/14 and 110/15 in East Irish Sea• Discovered in 1992 by Hamilton Brothers• First oil 1996• BHP Billiton 46.1% (operator), ENI Ltd 53.9%• Unmanned platform with twelve wells• Liverpool Bay is BHP Billiton Petroleum’s largest operated
producing asset
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Field Overview
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Field Overview - Reservoir
• Lennox is an oil and gas reservoir– Shallow (3200ft TVD SS)– Large gas cap (743 ft) – Normally pressured, thinner oil rim (143 ft)
• High quality Ormskirk Sandstone reservoir– Porosity 13% to 20%, Permeability from 200 mD to 1 Darcy– Competent sandstone
• Two distinct production phases– Current oil rim development, with gas re-injection– Future gas cap blowdown
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Production History
• Peak production 46,500 bbl/d in October 2001 dropping to 14,000 bbl/d in December 2004
• Decreasing reservoir pressure, increasing facilities back pressure due to gas breakthrough & increasing water cut– Coil tubing intervention to kick off with N2 after shut down
• Small unmanned platform– Only performed on campaign basis
• Reduced production & deferred oil recovery
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Gas Lift Options
Pros– Standard off the shelf
system
– Gas lift valve can be changed out with slickline or CT
– Check valve prevents back flow into annulus
Cons– Surface modifications & tie-ins
required (time, cost & field s/d)
– Gas filled annulus
– Large gas inventory
– Potential corrosion of annulus with re-injection gas (H2S)
– Full annulus pressure integrity & Annular Safety Valve
– Lead time impact
• Traditional annular gas lift
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Gas Lift Options
Pros– Minimises gas inventory
in annulus
– Down hole equipment available
– Gas lift valve can be changed out
– Check valve prevents back flow
• Dual string gas liftCons– Surface modifications & tie-
ins required (time, cost & fieldshut down)
– High pressure loss in gas injection string
– Inconel gas injection stringrequired for continuous gas lift (lead time)
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Pros– Equipment tried and tested
– No gas in annulus
– Minimal surface mods.
– Gas lift valve can be changed
– Check valve
– Shortest lead time
– Ability to turn well to gas production
• Gas cap gas liftCons– Highest cost
for downholeequipment
Gas Lift Options
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Surface Controlled Gas Lift Valve
• Schlumberger’s Wireline Retrievable Flow Controller -Hydraulic (WRFC-H)– Sidepocket mandrel based flow control valve– Slickline retrievable valve– Variable control (six position) – Surface actuated through single ¼” hydraulic control
line• Use current platform hydraulic system• Remote operation• No tubing hanger modifications required (Utilised CI
port)– Check valve system– Tested to 10,000 bfpd, 30 mmscf/d
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Gas Lift Design Calculations
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Gas Lift Design Calculations
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WRFC-H Installation
• During 2005, workover campaign to re-complete six wells– Wells killed with all returns taken to production
– Oil zone isolated with plug in liner top
– Tubing pulled (packer milled on two wells)
– Clean out trip and spot loss control fluid across gas zone
– Perforate gas zone (overbalance)
– Ran completion with WRFC-H (5 x 5-1/2” and 1 x 3-1/2”)
– Retrieved plug from liner top
– Coil tubing N2 lift to underbalance brine column to bring well on
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• Tubing hanger
• Safety valve
• Gas lift mandrel (Contingency N2 kick off via annulus)
• Nipple
• Upper packer
• Wireline retrievable flow control valve
• Sliding sleeve (turn well over to gas production)
• Lower Packer
• Nipple
• Pressure temperature gauge
• WEG
Completion Schematic
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Results
• Wells which could not flow naturally can now produce• No requirement for coil tubing after platform shut downs
– WRFC-H used for kick off• Minimum topsides modifications (control system)• Relatively straight forward completion
– No dual string gas lift or ASV• WRFC-H or sliding sleeve can be opened for gas
production
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Results
• Comparison of production rates
•*Pre workover rates are intermittent•Current oil rates are achieved 100% of well up time
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Gas Cap Gas Lift Results
• Current production rates
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Future Operations
• Possible additional wells
• Optimise lift gas for oil production– Accommodate reservoir pressure, PI and watercut changes
• Optimise gas production– Produce gas as required to meet contract requirements
• Open WRFC-H fully or sliding sleeve for gas blowdownphase
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Questions