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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