Barrier Philosophy for Wells on Gas lift and Ways of Reducing HSE Risks Alan Brodie Feb 2011 For more info visit www.ptc.as
Introduction Gas Lifted Well Integrity Management Incremental HSE risks Case histories The impact of getting it wrong Solutions to incremental HSE risks Image used with the permission of J Bellarby
Oil and Gas Well Integrity Management Basic Requirement Risk of hydrocarbon release from a well is ALARP (As Low As Reasonably Practicable) Which means using: Best available equipment Current industry best practices To achieve this most OPCO s usually adopt: Double independent barrier pressure containment envelope In natural flow example shown: Primary barrier outlined in red Secondary barrier outlined in blue With Acceptance criteria defined for each element e.g: ISO 13679 procedures for testing tubing connections Leak criterion for gas: 9 cc/15 min Image used with the permission of J Bellarby
Key differences # 1 ( tubing integrity) With many gas lift valves Primary well containment barrier is compromised ISO 17078-2 Flow control devices for side-pocket mandrels These devices are designed and intended to prevent reverse flow through a flow control device. They are not designed nor intended to provide a tight shut-off pressure safety seal or to be a part of the safety system. Allowable leak rate 6883 ml/10 mins Compare this to acceptance criteria for packers ISO 14310-- Downhole equipment -- Packers and plugs Allowable leak rate 20cc /10 mins ISO 14310 Image used with the permission of J Bellarby
Key differences # 2 ( High pressure gas inventory) High pressure gas in tubing / production casing annulus Question: What precautions are taken at well sites re gas bottles: Store safely away from areas with:» High risk of dropped objects» Potential sources of radiant heat Carefully manage logistic and numbers Potential volume of gas in annulus of each well: Equivalent of > 1000 industrial gas bottles Even where DHASV s used typically >100 Lift gas lines / valves from HP header to annulus: Pass thru area with Relatively high risk of dropped objects Many potential sources of radiant heat The first gas bottle explodes Other risks associated with leakage from inner to outer annulus Are production casing threads gas tight? Image used with the permission of J Bellarby
Getting it wrong (1) Piper Alpha Disaster N Sea 1988: Gas lift was widely used, Wasn t the root cause but it exacerbated the situation SCSSSV s generally closed But Gas lift check valves didn t Gas lift lines parted between isolation valve and wellhead Due to radiant heat from nearby fires Wells flowed naturally via annulus NB It appears the wells structural integrity was relatively unaffected despite the severity of the incident Image used with the permission of J Bellarby
Getting it wrong (2) Outer Annulus Pressure build up Onshore gas lifted well shut in Lift gas leaked from the inner to the outer annulus Outer annulus pressure built up to lift gas pressure (1700-1950 psi) Well restarted and heated up by 76 F Trapped pressure increased to 7700psi Outer annulus casing ruptured Flying debris damaged the HP gas line Contents of inner annulus vented and ignited Question How easily could this happen on your wells? #1 Source of info: www.wellintegrity.net
Reducing the HSE risks (1) ( tubing integrity) Employ qualified well barrier gas lift valves Operating Valves Unloading Valves Tested to the same allowable leak rate as packers etc Erosion test the valves to ensure: They will remain well barrier valves for the life of well Not just to pass a factory acceptance test (FAT) Image used with the permission of J Bellarby
Reducing the HSE risk (High pressure gas inventory) Down-hole Annulus Safety Valves (DH ASVs) Introduced after Piper Alpha in some parts of world To reduce the volume of gas topsides is exposed to Still typically equivalent of >100 gas bottles!! Shallow set dual path packers Integral check valve or sliding sleeve Usually not designed to be gas tight Always requires a full workover to replace on failure DH ASV reliability issues Apparently many wells closed in due to failed DH ASVs Problems with packer technology in thermal cycling Integral check valve reliability challenges Reputedly often difficult to retrieve
Reducing the HSE risk (High pressure gas inventory) PTC s fresh approach to DH ASVs Dual Packer technology designed for thermal cycling 4 110 deg C Client supplied SCSSSV attached above ISO-14310-V1 equivalent leak rate on gas side Solid body compact packer design Up to 10 control lines pass-through Single trip retrieval using Sondex cutter
Reducing the HSE risk (HP lift gas inventory) Eliminate the potential for annulus venting Using Surface Annulus Safety (SAS) valve Set in the wellhead VR profile Employs PTC Safelift GLV check valve design No erosion across metal / metal seal faces Performance exceeds that delivered by DH ASV Valves tested to API 6A PSL 3G PR2 Fire tested to API 6FB and API 6FD Achieving V0 with gas as test medium Valves replacable without workover Image used with the permission of J Bellarby
Reducing the HSE risk (HP lift gas inventory) Actuator module holds check valve open throughout life Protecting seal faces from chattering Modular design facilitates actuator detachement In case of annulus line damage Leaving check valve intact in wellhead Image used with the permission of J Bellarby
Reducing the HSE risk (HP lift gas inventory) > 250 SAS valves installed In use in GOM and N Sea Gas lifted wells with failed DH-ASV s previously had to be closed in Awaiting workover Now permitted to remain on stream If SAS valves are installed And if well barrier accredited gas lift valves are used Increasingly recognised by OPCOs as: required for achieving ALARP risk in gas lifted wells Some OPCOs even using them in combination with DH ASVs Their interpretation of ALARP
Gas Lifted well integrity Mgt Reducing the HSE risk (trapped annulus) Automated annulus pressure management Unique VR Plug / sensors can be installed on all annuli Continual annulus P&T measurement» Wireless (HART protocol) / wired link to control room Wireless module detaches safely under impact Leaving VR plug / sensor in wellhead Annuli can be bled down automatically via M-SAS valves Before closing again to ensure well integrity
Gas Lifted well integrity mgt Reducing the HSE risk Automated annulus pressure bleed down PTC gas lift valve derivatives One way (outer to inner) valves Pre set opening pressures (MAASP) Installed in special casing pups below wellhead New wells only Not just for gas lifted wells Ideal for subsea wells Typically casings are not cemented into previous shoe track To provide option for pressure to bleed off into formation Deploying annulus bleed valves would reduce this HSE risk
Conclusions HSE risks in well completions are managed to be ALARP Gas lift introduces significant additional HSE risks cf any other lift method: GLV s can be primary well containment envelope weak link Enormous inventory of high pressure gas introduced to hazardous area Potential for lift gas leakage into outer annuli New technologies developed to address these concerns: Well barrier gas lift valves and unloading valves Wellhead VR profile actuated Surface Annulus Safety (SAS) valves ISO-14310-V1 equivalent leak rate DH ASVs Wellhead VR profile pressure temperature sensors Trapped annulus pressure relief valves
Final thought Lets do a little role playing exercise : You re sat in the office next month and your phone rings Its your CEO on the line He tells you he has been invited to a meeting with the government To discuss a recent safety incident involving a gas lifted well He asks you Can I confidently say our designs ensured the risks were ALARP What s your answer...
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