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Well integrity sub sea

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There are different definitions of what is Well Integrity. The most widely accepted definition is given by NORSOK D-010: “Application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well.”[1]

Other accepted definition is given by ISO TS 16530-2 “Containment and the prevention of the escape of fluids (i.e. liquids or gases) to subterranean formations or surface.”

Well Integrity is a multidisciplinary approach. Therefore, well integrity engineers need to interact constantly with different disciplines to assess the status of well barriers and well barrier envelopes at all times.

Subsea wells

Subsea wells additional requirements from a well integrity management perspective, i.e.,

  • During the construction phase the wells are exposed to cyclic loading from the marine risers system.
  • The intermediate annulus pressure is trapped, thermal induced pressures need to be designed to prevent collapse.
  • The operating philosophy with long distance subsea flow lines, control systems and water depths cause retention times.
  • Risk assessments in event of failure are significantly different depending on water depth.
  • The water depth or ambient seabed pressure affects the operating envelope; or in event of failure, the consequences.

Typically subsea wells have vertical (conventional) and horizontal trees as per example below. The industry tends to go back to conventional trees due to the improvement in technologies around subsea well interventions without a subsea rig but from the back of a vessel.

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Wellhead fatigue

The well load history and exposure needs to be recorded over the life cycle entries of the well. The difference between the effects of deep water versus shallow water are illustrated below. The bending moment fatigue is driven by duration of the rig operations and weather conditions. Not understanding remaining fatigue life puts the well at risk.

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Trapped annular pressures

Trapped annular pressures cannot be monitored although some designs have a small sensing line. Others have rupture disc that connect the inner with the outer annulus. Normally subsea wells are designed with open casing shoe, i.e., no cement into the next casing. This allows the trapped annular pressure to bleed to the casing shoe in the event it exceeds this pressure. Shoe depths of intermediate casing is ideally placed at such a depth that the shoe strength is adequate to handle the well closed in tubing head pressure but this is not always the case.

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Bleed off

Issues that may prevent bleeding off to the shoe are accidental placement of cement over shoe and settling of mud solids over the shoe. Both may seal off the shoe. The well design should address this by establishing the anticipated thermal induced pressures and select appropriate casing material that can withstand this operating condition, but this may not always be possible.

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Reading and trending pressures

When reading subsea annular pressures and trending, you need to be aware that when you have trapped annular pressure and changing tubing head pressures, or annulus pressures, that these pressures are affected by the ballooning or collapse behavior of the intermediate trapped annular pressure especially on subsea injector wells where the well cools down and contracts while injecting and heats up or expands when shut in. There are technologies like strain gauges or acoustic subsea data loggers that can be retrofitted or designed in to read trapped annular pressure by transmitting signals using inductive couplings.

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Hydraulic fingerprints

Subsea well operating philosophy with long distance umbilical requires keeping track of hydraulic fingerprints that are taken when the well is completed or established later with confirmation of operating function. These hydraulic fingerprints are a key ingredient to assure yourself of the functionality of the subsea components like valves, chokes, and subsurface safety valves etc. See example below of such a fingerprint. It is key from a well integrity perspective to keep a good record of these over the well life cycle of the well

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Shutdown and opening

Shutdown and opening up of subsea wells have certain risks; i.e., each cycle is an exposure to failure due to metal parts rubbing over each other with differential pressures. The slightest form of solids may jeopardize integrity of the barrier element. Also formation of hydrates is a common known problem that has to be removed by methanol injection. With long flowline umbilicals and good enough pressure ratings, you do not always need to shut down the well. On demand of the emergency shutdown of the surface facilities, you may just shut the umbilical on boarding valve or production riser valve and allow the well to flow until the flowline is packed or reaches the maximum pressure and then shut down the well. This operating philosophy has been applied and known to reduce subsea tree cycling significantly, and resulted in more production up time and less subsea equalizing problems (a key ingredient to optimize well integrity from a lifecycle perspective).

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Subsea obstruction exposure

Risk assessment of subsea wells is much different. Offshore or on land the intervention risk to restore well integrity in the event of failure does not carry a large risk. On subsea the risk of dropping the riser system or blowout preventer carries a high risk. The deeper the water, the less the probability the dropped object will hit the subsea wellhead.

A subsea well at 60 meter water depth stands a fair chance of being hit by fishing nets or anchor chains. A subsea well at 1000 meter water depth will normally not be hit by such objects as these activities do not normally take place and has therefore a lower risk exposure.

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Ambient pressure

Subsea ambient pressures need to be taken into consideration for design of the subsurface safety valve as the hydraulic control line is exposed to this pressure when a failure occurs of the control line system. This subsea ambient pressure maybe sufficient in some cases to hold open the subsurface safety valve. This risk needs to be assessed and verified from a well integrity perspective.

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  1. D-010:2013. Well integrity in drilling and well operations. 2013. Lysaker, Norway: NORSOK.

Noteworthy papers in OnePetro

Dethlefs, J. and Chastain, B. 2012. Assessing Well-Integrity Risk: A Qualitative Model. SPE Drill & Compl 27 (02): 294-302. SPE-142854-PA.

King, G.E. and Valencia, R.L. 2014. Environmental Risk and Well Integrity of Plugged and Abandoned Wells. Presented at the SPE Annual Technical Conference and Exhibition, Amsterdam, 27-29 October. SPE-170949-MS.

Singh, S.K., Subekti, H., Al-Asmakh, M., et al. 2012. An Integrated Approach To Well Integrity Evaluation Via Reliability Assessment Of Well Integrity Tools And Methods: Results From Dukhan Field, Qatar. Presented at the SPE International Production and Operations Conference & Exhibition, Doha, Qatar, 14-16 May. SPE-156052-MS.

Vignes, B., and Aadnøy, B.S. 2010. Well-Integrity Issues Offshore Norway. SPE Prod & Oper 25 (2): 145-150. SPE-112535-PA.

SPE papers grouped by conferences:

Watson, V. 2010. A Quantitative Risk Assessment Approach. SPE International Conference on Health, Safety and Environment in Oil and Gas Exploration and Production, Rio de Janeiro, 12-14 April. SPE-127213-MS.

Wilson, V. A. 2014. HSE and Well Integrity: Friends or Foes? SPE International Conference on Health, Safety, and Environment, Long Beach, California, USA, 17-19 March. SPE-168407-MS.

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Online multimedia

Hopmans, Paul. 2013. Journey of Well Integrity.

Dethlefs, Jerry. Near Surface External Casing Corrosion; Cause, Remediation and Mitigation.

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External links

SPE. Well Integrity Technical Section.

See also

Well integrity

Well integrity lifecycle

Well integrity onshore

Well integrity offshore

Well integrity thermal

Page champions

Federico Juarez - Well Integrity Engineer

MJ Loveland - Well Integrity Supervisor ConocoPhillips