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'''Definition:''' As defined by NORSOK D-010<ref name="r1">D-010:2013. Well integrity in drilling and well operations. 2013. Lysaker, Norway: NORSOK. https://www.standard.no/en/sectors/energi-og-klima/petroleum/norsok-standard-categories/d-drilling/d-0104/</ref><ref name="r2">D-010. Well integrity in drilling and well operations. 2004. Lysaker, Norway: NORSOK. http://www.standard.no/en/sectors/energi-og-klima/petroleum/norsok-standard-categories/d-drilling/d-0102/</ref>: “Application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well.” There are various facets to well integrity, including accountability/responsibility, well operating processes, well service processes, tubing/annulus integrity, tree/wellhead integrity, and testing of safety systems.
There are different definitions of what it 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.”


;'''As defined by API RP 100 – Part 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.”
:The design and installation of all well equipment to a standard that ensures:
 
:*The protection and isolation of ground water aquifers
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.
:*The safe containment of hydraulic fracture treatment





Revision as of 17:02, 22 November 2015

There are different definitions of what it 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.”

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.


Well integrity management systems

A Well Integrity Management System (WIMS) is a meaningful solution to define the commitments, requirements and responsibilities of an organization to manage the risk of loss of well containment over the well lifecycle. The tasks necessary to deliver well integrity, and the roles accountable and responsible for delivery, are specified in a WIMS document. To operationalize the management system, software tools can be used. These have various forms from simple solutions managed with a spreadsheet to more complex systems managed using self-built or commercially available electronic management systems.

The objective of a WIMS is to specify requirements necessary for delivery of well integrity, including:

  • Well integrity refers to maintaining full control of fluids within a well at all times, in order to prevent unintended fluid movement or loss of containment to the environment.
  • Well integrity policy defines commitments and obligations to safeguard health, safety, environment, assets, and reputation.
  • WIMS is the system that assures that well integrity is maintained throughout the well life cycle by the application of a combination of technical, operational, and organizational processes.

Commercially available well integrity management systems software includes:

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Elements of the well integrity management system 

  • Wells ownership over the lifecycle for wells that are:
    • Developed
    • Acquired
    • Divested
    • Suspended
    • Closed in
    • Operated
    • Exploration
    • Abandoned by company.
  • Organizational structure with roles:
    • Responsibilities
    • Competencies
  • Risk assessment with risk register that:
    • Defines the risk
    • Mitigations for the hazards that are to be managed
  • Well types with:
    • Well barriers
    • Well barrier envelopes that control hazards
  • Performance standards that:
    • Defines the requirements to maintain the well barriers within its operating limits.
  • Well barrier verification, or assurance processes that:
    • Assures the mechanical status of the well is maintained on a defined risk
  • Underlying processes like:
    • Reporting
    • Documentation
    • Management of change
    • Continuous improvement
    • Auditing processes.

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Objective of the well integrity management system 

The overall objective is to give transparency on how risk is managed.  One way to achieve this transparency is to benchmark other operators to verifing how effective the well integrity management system performs. Another way is to compare the system to industry standards (e.g. The NACE's Petroleum and natural gas industries--Well integrity--Part 1, ISO 16530-1).[1]

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An effective well integrity management system 

An effective well integrity management system uses a risk based matrix that will demonstrate how to manage risk. This risk-based matrix is based on "as low as reasonably practical" or ALARP . Well operating limits is a combination of the criteria established to ensure that the well remains within its design limits in order to maintain well integrity throughout the well life cycle.  For each well type, it is normal when changes occur and the well operating limits should be checked.

To assure well operating limits, some parameters could be monitored over the well life cycle when the well is constructed, operated, shut-in or suspended;

  • requirements for any threshold settings for the well limits;
  • actions that should be taken in the event a well parameter is approaching its defined threshold;
  • actions, notifications and investigations required if well limit thresholds are exceeded;
  • safety systems that are necessary to ensure parameters stay

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Well Integrity operating philosophy

The well integrity operating philosophy is an important element that one should carefully consider with respect to how to manage the risk of loss of containment and overexpose oneself with additional risk by frequent well visits and interventions that brings exposure to the people and environment by doing these activities. The overall process should fit together. It is of little use to define a meantime to repair for failed barrier components and not have supporting critical spares or competent resources in place to able to respond to such an event. The philosophy should be aligned with risk exposure and be clearly under scribed by the process owner.

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Personnel competency and training

There are a number of competency assurance processes available.  There are not many that are specific to well integrity, but the below example of a competence matrix (part 1&2) on how one may look, The assurance and training is similar to any other educational system in that there is a theoretical level and a practical level.  Both are equally important.  The verification process of the ability to perform a certain task is a must that one needs to consider and assure himself of.

The categories of people are subjective in example as each organization is different.  This in itself is not an issue as one can adapt the matrix and make it suitable.  The main issue is whatever task or activity is assigned in the well integrity process, one must assign the appropriate competencies for that task, assure that these competencies are in place, and that they are validated and maintained.

The above is applicable for operator staff or contractor staff.  There may be some regulated standards available like Opito that is used in the North Sea.

Further, there are websites on well integrity that are a maintained by others such as http://www.wellintegrity.net/.

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Risk assessment

A Risk Assessment is a procedure to determine the quantitative or qualitative value of a risk or threat to a specific situation. Risk can be defined as a combination of both the severity of the consequences of an event and the likelihood or probability that the event will occur. Risk increases with increasing severity and/or likelihood. Risk tolerance and risk rank category definitions can vary by company and location. However, it is an industry-accepted practice to require prevention or mitigation for significant and/or high risk category wells.

One very general but accepted definition for a high risk well is: “A well in which that last barrier is under threat of being compromised.” Each company should create their own specific definitions for well risk based on operating area, well stock, and risk tolerance. There are numerous risk assessment methods available to facilitate the determination of well risk and a few of those methods are summarized below.

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Quantitative risk assessment (QRA)

Quantitative Risk Assessment (QRA) is a method of risk assessment based on numerical probability using historical data and reliability models. This method is commonly used for hydrocarbon processing facilities and oil pipeline systems. The challenge for using a QRA for well integrity is the availability and applicability of well failure and reliability data for use in a risk model. Even with a perfect model, initial conditions and boundary conditions must be correct or the prediction will be flawed.

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Qualitative risk assessment

A Qualitative Risk Asssessment is a more conventional method for well integrity. It is primarily based on experience and the application of good engineering judgment. Qualitative Risk Assessments are easier to execute but are limited by the experience and knowledge of the people completing the assessment.

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QRA/Qualitative hybrid

Due to a lack of well integrity reliability data for QRAs, many well integrity risk assessments are QRA/Qualitative hybrids based on known failure data, rules, procedures, and risk matrices rather than using straight qualitative or QRA analyses. One such hybrid method documented in 142854-PA SPE Journal Paper – 2012 [2] is a hybrid risk assessment method that uses a qualitative, team-based brainstorming format following the “what if” methodology to identify hazards associated with known or predetermined well-barrier failure modes and likelihoods from a known well stock. This method uses a risk matrix with customized likelihood and consequences as shown in the sample below.

Components that contribute to the risk profile of a well or number off wells that determine how the risk needs to be managed could be:

  • Outflow potential to surface or subsurface environments
  • Fluid types and composition, H2s, Co2, gas, oil, dehydration water etcetra’s
  • Location, subsea, offshore, swamp, land, urban, natural reserve etcetra’s
  • Earth model, subsidence, earth quakes, permafrost
  • Collision from vessels, fishing, trucks, landslides, intervention activities

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Well design, well construction, and barrier requirements

During well design and construction, the barrier requirements are driven by the input of the basis of design and the identified hazards.  These hazards can change over the life cycle of the well or may actually be introduced during the construction of the well. The design and construction process is the main element that drives how the well needs to be operated, maintained, or abandoned.  There is with each field or well development plan the element of economics, the time line to deliver, or earth model hazards that are encountered that may result in decisions that affect well integrity or well operating limits. From a well integrity management perspective, the relevancy is to understand the risk associated with exposure to certain hazards and that these are clearly defined in the well operating limits at well handover so that mitigating controls can be applied over the wells life.

Depending on the environment where the well is placed in and outflow potential of the well, with likelihood of failure and consequence of loss of containment, the well barrier requirements are defined. This is usually done in the field development stage by use of quantitative risk assessment.  See below examples of various barrier designs whereby in a hydro static well, the liquid level is the primary barrier.

Some examples of elements that may have to be managed during the design construct of well barriers to assure them over the well lifecycle are:

  • Internal oxygen-related corrosion
    • CO2 corrosion
    • H2S corrosion
    • chloride stress cracking
    • stress cracking caused by bromide mud and thread compound
    • microbial-induced corrosion (MIC)
    • other chemical corrosion
    • acid corrosion (e.g. from stimulation fluids)
  • External corrosion as result of
    • aquifers
    • surface water
    • swamp or sea environments.
  • Sand/solids production
    • scale deposition
    • erosional velocities
    • formation of emulsion
    • scale
    • wax and hydrate deposits.
  • Compatibility between components, electrolytic corrosion.
  • Load cases as result of
    • thermal
    • fatigue
    • subsidence
    • stimulation
    • well kill
    • injection
    • production
    • evacuation
    • trapped pressures
    • casing wear.
  • Earth model fractures
    • pore pressures
    • permafrost movement
    • squeezing chalks
    • salts
    • earthquake
    • subsidence.
  • Zonal isolation placement and verification of isolation methods.

Typically well head valves and Xmas trees are single barrier elements as they use floating gates and seats that hold in one direction that results in valve bonnet , grease nipple, and stem packing to be under pressure at all times.  See example of a typical gate valve below.  When designing the well and its barriers, this needs to be taken into consideration.

The well barrier design and construction process objective should address the issues such that the barriers over the well life cycle assure containment that can effectively be managed and verified. This statement is a challenge in itself as many wells have issues over the life cycle as things were not clear from beginning or changes occurred or well was not designed and constructed as intended.  The process of well integrity management is to understand the risks and address these by managing the well barriers within its operating limits to prevent loss of containment.

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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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Offshore wells

Offshore wells are considered dry tree wells that have much similarity to onshore wells, apart from the fact the consequence of loss of containment is extremely large in respect to environment and people.  This environment is therefore much more stringent regulated by industry standards like API14 and country regulating authorities like BSEE and European offshore directives.
These require more complex shutdown systems and subsurface safety valves with minimum requirements and performance criteria. The country regulators often demand a higher level of conformance to these performance standards with regular reporting and inspections.

There is also more focus on standards for this category of wells and records or data base analysis that provide information on barrier element performance like Sintef, these have led to the next generation subsurface safety valves to be developed with separate hydraulic pistons and stronger flapper and flow tube configurations.  A good reference is the Barosa Santa Barbara SSSVstudy by RPSEA for Design Investigation of Subsurface Safety Valves for XHPHT Document: 07121-1603.FINAL, 3 (PDF).

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Eddy current sensors

The additional risk of offshore wells is in the external corrosion area.  The space between outer load bearing casing and surface conductor is often filled with seawater this often causes corrosion at the interface between the seawater level and air contact that can lead to complete failure of the well and result in extensive repairs. The risk of this can be managed by applying an interface on top of the seawater level with for example rapeseed oil and biocide.  This however has to be topped up and maintained on a regular basis and its effectiveness confirmed with corrosion logging by inserting eddy current sensors inside the conductor, a technology that is available from Sonovation Rheinland called PEC (Pulsed Eddy Current).

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Eddy current logging

Alternative is the use of Eddy current logging.  This is a method whereby multiple casing are read from inside the well to the outside. This method is successfully applied by Vanguard EDMS; they have a number of history cases.  The results are however not as accurate as the PEC method but is a good alternative.  Other logging tools are on the market and in development that are becoming competitive to this technology. 

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Rapseed

The rapeseed solution does not work under elevated temperatures as bacteria will degrade the rapeseed oil or any natural product very fast.  An alternative is use of polymers and glass beads but that would restrict access to verify if you have corrosion from the outside.. With elevated temperatures the corrosion rates double between North Sea and Far East water temperatures.  In the Persian Gulf a history case was recorded that had 70 degrees Celsius measured inside the space between conductor and casing. This well corroded the entire casing in a couple of years. The NACE Babonian corrosion handbook for seawater[3] is a good reference for establishing corrosion rates. 

In addition you have metocean movement or sea swell effect that moves the platform jacket and its conductors.  Inside the conductors the wells that may affect the rate of corrosion due to fatigue issues.  This is a subject not clearly understood as some wells on the same jacket will corrode faster than others with no obvious reason.

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Grouting

In the event the casing is corroded, grouting of the space between conductor and casing with a top fill job using cement is a solution applied, but often losses through conductor shoe will prevent this unless a floating spacer is placed or a light weight cement. The risk of grouting is that you glue the well and conductor together.  This means with every thermal cycle the well normally moves up and down a little and over time he conductor may start to hang on to the casing. This is the case when the conductor has insufficient spare load capacity based on soil strength stick.  Then the conductor will start to transfer its load to the well outer load bearing casing and may induce collapse of the casing below the conductor shoe of the casing. Before embarking on grouting wells inside conductor, one should do a proper engineering assessment of the load capacities.

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Casing clamps and shims

In case of reduced load capacity due to corrosion the well load may be transferred to the conductor by using a casing clamp and shims that rest on the conductor.  Again an engineered calculation should be conducted.  If all fails, i.e. conductor cannot handle load and well casing is nearing collapse, load transition is possible by supporting it from the platform structure.  This again needs to be supported by an engineered load case assessment.

External corrosion of conductor occurs only in cases where there is no coating applied or conductor is not protected by the cathodic anodes of the platform jacket.

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Land wells

Well integrity on land wells is less stringently regulated, although standards and regulators are continually being updated. The main integrity risk with land wells is around loss off containment in urban areas or facility, or to fresh potable aquifers as both may have huge consequences.  These risks need to be managed effectively from a well integrity perspective.  In addition, shutdown systems that have the function to protect the specification break between well and process, i.e. flowline protection are fitted on the well and are part of the overall operating envelope and need to have assurance task to confirm their function and reliability. These functions include emergency shutdown valves, high pressure/low pressure, pump shutdown, gas lift shut, relief valves down or other means to protect the spec break and stop undesired flow. 

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Barriers

Collision risk of trucks or cranes or nearby movement of concurrent operations has additional risk, as many onshore wells are completed without a subsurface safety valve.  These activities may have to be managed.  Use of additional external barriers like Jersey barriers that would prevent collision may be a suitable control or wells should be made safe during critical activities.

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Thermal

Well lifecycle or sustaining Integrity in aging wells

Well lifecycles have three primary areas of focus or stages; design and construction, well operation and intervention, and abandonment. ISO 16530 delineates the lifecycles stages into six lifecycle phases, Basis of design, design, construction, operational, intervention, and abandonment.

The ability to sustain well integrity is fundamentally dependent on both the design and the operational stages. Before construction, an appropriate well design including a well barrier envelope evaluation will facilitate long term well integrity sustainability. Additionally, a suitable well integrity management system (WIMS) should assure well integrity is maintained throughout the entire well lifecycle.

Maintaining well integrity during the well operational phase also requires the practice of proactive pressure monitoring programs, barrier verification and maintenance programs. Program performance standards and test acceptance criteria are defined during the well design phase and in conjunction with any applicable regulations.

In many cases the end of well life may extend a well past the original design life so it is important to recognize that performance standards, acceptance criteria and required barrier testing and maintenance can change during the well life cycle. When pressures, performance, or barrier compliance acceptance criteria do not meet the pre-defined standards additional diagnostic tests, well intervention, repairs, and other mitigations may be required.

With aging wells and changing failure mechanisms, the challenge is to understand failure and consequences to a level that the process of managing well integrity is well understood and managed in a sustainable way.

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Corrosion management

Corrosion, erosion, or fatigue of the well barrier elements is one of the main well life cycle risks that causes loss of containment and needs to be effectively managed.  Some of the following issues contribute to this process.

  • Casing wear during initial drilling of the well that leads to wall loss of main load bearing well barrier element.
  • Fatigue on subsea wells from well construction or intervention activities that reduces the overall lifecycle strength of the wellhead and its components that may lead to early failure of the well.
  • Corrosion / erosion can be caused by:
    • Seawater inside conductor (offshore) that corrodes the load bearing casing externally inside the conductor .
    • Aquifers on shore that are not isolated and corrode the exposed casing externally.
    • Mismatch of materials electrolytic corrosion 
    • Corrosive produced or injected fluids that cause internal corrosion 
    • Erosional velocities combined with sand or other solids that create material loss
    • Eddy current as result of running short phased electric submersible pumps
    • Sulphide reduced bacteria (SRB)

To manage corrosion you have the following options:

  • Identify the risk and design
    • Restore the well such that the risk is mitigated and controlled by selecting the right material or isolating the source 
  • Design or restore the well with a protection system like cathodic protection[4], inhibitor treatment, or coatings.
    • Combine with a surveillance program that demonstrates the effectiveness of such a system.
  • Produce to fail philosophy, i.e. use the well and inspect the well on a routine basis to assess the failure mode and risk.
    • Conduct an estimate when the well will fail and build mitigation plans around this to prevent loss of containment by timely restoring barrier elements.  

Well logging and surveillance techniques may be applied.  They come in various forms i.e. Caliper logs that measure actual wall loss inside the well.  These have the risk that the trailing caliper fingers disrupt the protective coating on tubing or casing wall and cause more corrosion.

Acoustic logs that give you an indication of material in place is dependent of having fluids in the hole and good transmission of signal.

  • Pulsed eddy current logs that give you an average material wall loss picture of each tubing, casing string in the hole, effectiveness is dependent on tool, and signal interpretation capability.
  • Visual inspection using video surveillance, inspection of recovered material during workover, or use of corrosion coupons inside the well stream that are inspected on routine.
  • Well elevation monitoring that will indicate subsidence of the well as result of corrosion causing casing collapse and subsidence. 

These logging and surveillance techniques may be part of a pre-planned surveillance programme, or may be initiated in response to an event or an observed anomaly. Surveillance results from sample wells may be used as an input across wells of the same type in a field to predict failure rates and mitigation plans to avoid loss of containment. The surveillance experience of offset wells or fields is a very useful resource for other field developments.  There are many publications on this subject that can easily explored on the internet. 


With structural integrity, it is not always possible to directly measure the effects of cumulative fatigue such as the appearance of cracks. A tracking and recording system may assist with the assessment of the predicted consumed life of the components,. Some of failure of the failure modes for structural components can be:

  • metal loss as result of wear, corrosion or erosion
  • metal fatigue due to cyclic loads;
  • degradation of soil strength due to cyclic, climatic and/or thermal loads;
  • lateral loading due to squeezing formations, salt, permafrost or earthquake.
  • Subsea and offshore structural components can be subject to additional loads arising from temporary equipment attached to the well, such as drilling or intervention risers.

Unexpected changes in well elevations can be an indication of the degradation of structural support of the well and can escalate to a level that impacts the well integrity. When monitoring for subsidence or elevation of the well and its surroundings, the datum reference should be periodically verified and recorded.

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Managing abnormal casing pressure and sustained casing pressure

Barrier Verification/ Barrier Diagnostics

At various phases of a well’s life cycle, the integrity of the well barriers and/or well barrier elements should be verified. The verification may involve pressure measurement, tagging, pressure testing, leak testing, leak off testing, well logging or flow rate measurement. If anomalous behavior is observed then a diagnostic process is initiated, usually to determine the location and magnitude of the leak.

Typical key barrier verification steps and techniques during various well life cycle phases are as follows:

Life Cycle Phase

Well Barrier Element(s)

Barrier Verification Examples

Well Construction or Workover

 

 

 

Fluid column

Fluid density, fluid loss rate, fluid level

 

BOP

Pressure test, function test

 

FOSV or IBOP

Pressure test, function test

 

Casing and liner

Pressure test

Well logging - ultrasonic

 

Wellhead / casing hanger

Pressure test

 

Geological formation

Leak off test or formation integrity test

Well logging – ultrasonic or electromagnetic wall thickness, mechanical caliper

 

Liner hanger / liner

Pressure test

Negative (inflow) test

 

Annular Cement

Pressure measurements – calculated cement column height

Well logging – acoustic and ultrasonic tools

 

Tubing

Pressure test - internal or external

 

Production packer

Pressure test – from above or below packer element

 

Subsurface safety valve

Leak test, function test

 

Xmas tree

Pressure test, leak test, function test

 

 

 

Well Operations

 

 

 

Casing and liner

Annulus pressure monitoring

Annulus bleed down test

Annulus pressure test

 

Completion string

Annulus pressure monitoring

Pressure test – tubing or annulus

Leak off test (annulus bleed down)

Acoustic fluid level survey

 

Subsurface safety valve

Leak test, function test

Control line pressure test

 

Gas lift valve

Leak off test (annulus bleed down)

Acoustic fluid level survey

 

Wellhead / casing hanger

Pressure test, leak test, function test, visual inspection

Infrared thermal imaging, casing vent monitoring

 

Xmas tree

Pressure test, leak test, function test, visual inspection, ultrasonic wall thickness measurement

Infrared thermal imaging

 

 

 

Well Intervention (Rigless)

 

 

 

BOP

Pressure test, function test

 

Pressure control equipment

Pressure test

 

Completion string (including casing and liner below tubing tailpipe)

Well logging – mechanical caliper, ultrasonic and electromagnetic wall thickness, ultrasonic leak detection, pulsed neutron log, magnetic flux leakage, temperature, production log, video or acoustic tools, fiber optic distributed acoustic and temperature log

Pressure test - against downhole plug or straddle tool

 

 

 

Well Abandonment

 

 

 

Casing and liner

Pressure test

Well logging – mechanical caliper, ultrasonic and electromagnetic wall thickness

 

Annular Cement

Pressure measurements – calculated cement column height

Well logging – acoustic and ultrasonic tools

 

Cement plug

Tag top of cement

 

 

Pressure test

 

 

Negative (inflow) test

To determine whether the well barrier has an acceptable level of integrity, the barrier verification results are compared with the performance standards (or acceptance criteria) that apply to that well. Some oil and gas companies have their own in-house standards and some jurisdictions have regulatory regimes that prescribe the minimum verification requirements for certain well barrier elements, for example the length or height of cement plugs. Companies commonly adopt performance standards based on the following publically available reference documents. 

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Since these documents are not consistent in all aspects, it is important for a company’s well engineering management system and/or well integrity management system to explicitly define the well barrier elements (and/or safety critical elements) and the performance standards that shall apply.

The performance standards need not be uniform across all wells operated by a company or within a region, and can vary after considerably based on the risk profiles for different well types and the specific regulatory regimes that apply. An example performance standard for well safety critical elements provided in ISO / TS 16530-2 [6] for the operational phase is reproduced below. 


Description

Performance monitoring requirement

Units of Measure

Acceptance criteria example

Well Head/Tree Visual Inspection: There shall be no leaks/weeps of the well head/tree, valve and instrument connections. (Visual Inspection)

Acceptable visual inspection

No leaks

Zero

Wellhead/Tree valve operability: All wellhead/tree valves shall be operable in accordance with manufacturer defined specifications (number of turns).

Acceptable test / operate on demand as per   manufacturer specification

Number of turns

18 3/4 turns

Wellhead/Tree valve Actuation :  Actuated wellhead/tree valves shall close within the required time as defined by operator in the well hook up cause and effect requirements for shutdown based on API 14 B.

Acceptable response test

Time

30 seconds

Wellhead/Tree valve Leakage Rate: The valve leakage rate is not greater than the corresponding allowable leakage rate as specified by operator based on API 14 B

Acceptable test / leak rate

Ambient volume/ time

0,425M3/min

Annular Safety Valve integrity: The ASV performs within the parameters specified by the operator based on API 14 B

Acceptable test
Operates on demand  records available

Pressure limit

xx MPa

Annulus Integrity Management (1): The annulus pressures are to be within specified values for Maximum Allowable Annulus Surface Pressure (MAASP)/Trigger and Minimum Values


Operates within MAASP records available

Pressure limit

xx MPa

 Annulus Integrity Management (2): The annulus pressure monitoring equipment is calibrated correctly and alarms (where fitted) operate at the required set points or pressures are recorded manually on regular intervals.

Acceptable test
Operates on demand  records available

Accuracy

Percentage

Annulus Integrity Management (3): The annulus pressures test is to be within the wells operating envelop as defined by Operator.

Acceptable test Operates on demand  records available

Pressure test

xx MPa

Sub Surface Safety Valves (SSSVs) Integrity: The SSSV performs within the parameters specified by Operator.

Acceptable test
Operates on demand

Leak test

0,425M3/min

Well Plug(s) Integrity Test : The well plugs perform within the parameters specified by Operator.

Acceptable test
Operates on demand

Leak test

0,425M3/min

Gas Lift Valve (GLV) / Tubing Integrity Test : The GLVs and tubing perform within the parameters specified by Operator.

GLV Tubing to annulus test acceptable

Inflow test

0,425M3/min

Hanger neck seal, control line feed through, electrical feed through and DASF / adaptor spool seal area’s : The component pressures test is to be within the wells operating envelop as specified by Operator. 

Acceptable test
Operates on demand

Pressure test

xx MPa

Shutdowns of artificial lift Pumps Electrical submersible pumps (ESP’s) / Beam pumps / Electrical Submersible Positive Cavity Pumps (ESPCP’s) / Positive Cavity Pumps (PCPS) /Jet pumps gas lift systems.

Artificial lift systems that have capability to overpressure flow line / wellheads or other well components, shutdown test is to be within defined cause and effect diagram parameters.   

Acceptable test
Operates on demand

shutdown test

30 seconds

Location safety valve or production wing valve: Operates as defined in cause and effect s diagram as defined by well operator.

Acceptable test
Operates on demand

shutdown test

30 seconds

Operating envelop of Injection wells:  Maximum allowable injecting pressure as defined by Operator.

Operating limit of pressure of injection pressure based on MAASP of well bore

Pressure limit

xx MPa

Steam wells
Maximum allowable pressure / temperature as defined by Operator.

Operating limit of pressure of injection pressure / temperature based on Maasp & temperature limitations of well bore

Pressure + Temperature limit

xx MPa  / deg Celsius

Other useful reference documents include:    

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Intervention

Hydraulic fracturing impacts on integrity

Plug and abandonment

When there is no future economic use of a well (e.g. a non repairable well integrity issue, as necessary by regulations, or other reasons) the well's last stage within the lifecycle is plug and abandonment (P&A).

P&A is process of permanently securing the well with cement plugs or other mechanical barriers in such a manner that ensures all fluids, hydrocarbons and water, are confined to their original indigenous strata.

Abandonment plugs should extend across all strings of tubing and casing annuli to seal horizontally as well as vertically through the full cross section of the wellbore. The purpose of the plugs is prevent any cross flow of fluids between fluid baring strata; as well as, prevent any fluid breaches at surface. The plugs in a well must also effectively segregate uncased and cased portions of the wellbore to prevent vertical movement of fluid within the wellbore. Some operating areas require removal of the tubing and portions of the casing prior to setting mechanical plugs or pumping cement plugs. The number, location, and length of the cement or mechanical plugs and the subsequent barrier verification tests required to P&A a well will vary by operating area regulations. After downhole and surface plugs are set the well head equipment and casing will be removed to a specified depth below ground level or mud line. After which an abandonment marker plate will be installed as specified by area requirements.

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Well suspension

Well suspension is synonymous to temporary abandonment in many operating areas and is used to temporarily secure a well with cement plugs or other mechanical barriers in such a manner that ensures all fluids, hydrocarbons and water, are confined to their original indigenous strata for a temporary amount of time. The purpose of suspending a well is to reserve a wellbore and production equipment for future use. A suspended well must have appropriately placed and tested cement or mechanical plug barriers per local regulations that require periodic barrier inspections. Depending on local regulations there is a finite amount of time a well can be suspended before it must be plugged and abandoned.

Standards and governances

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References

  1. ISO/DIS 16530-1. Petroleum and natural gas industries--Well integrity--Part 1: Life cycle governance Well Integrity Lifecycle. Houston: NACE. http://www.iso.org/iso/catalogue_detail.htm?csnumber=63192
  2. Dethlefs, J., & Chastain, B. (2012, June 1). Assessing Well-Integrity Risk: A Qualitative Model. Society of Petroleum Engineers. http://dx.doi.org/10.2118/142854-PA
  3. Corrosion Handbook 5, 5. Weinheim: Wiley-VCH, 2005.http://www.worldcat.org/oclc/314669887
  4. Little, Brenda J., Patricia A. Wagner, and Florian Mansfeld. Microbiologically Influenced Corrosion. Houston, TX: NACE International, 1997. NACE. Web. http://www.nace.org/uploadedFiles/Corrosion_Central/Industries/SP016913%20for%20State%20of%20New%20York.pdf
  5. D-010:2013. Well integrity in drilling and well operations. 2013. Lysaker, Norway: NORSOK. https://www.standard.no/en/sectors/energi-og-klima/petroleum/norsok-standard-categories/d-drilling/d-0104/
  6. "ISO/TS 16530-2:2014 Well Integrity -- Part 2: Well Integrity for the Operational Phase." ISO. Web. http://www.iso.org/iso/catalogue_detail.htm?csnumber=57056.

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. http://dx.doi.org/10.2118/142854-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. http://dx.doi.org/10.2118/170949-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. http://dx.doi.org/10.2118/156052-MS.

Vignes, B., and Aadnøy, B.S. 2010. Well-Integrity Issues Offshore Norway. SPE Prod & Oper 25 (2): 145-150. SPE-112535-PA. http://dx.doi.org/10.2118/112535-PA.

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. http://dx.doi.org/10.2118/127213-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. http://dx.doi.org/10.2118/168407-MS.

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Online multimedia

Hopmans, Paul. 2013. Journey of Well Integrity. http://eo2.commpartners.com/users/spe/session.php?id=10246

King, George E. 2013. Well Integrity: Hydraulic Fracturing and Well Construction – What Are the Factual Risks?. http://eo2.commpartners.com/users/spe/session.php?id=11601

Dethlefs, Jerry. Near Surface External Casing Corrosion; Cause, Remediation and Mitigation. http://www.spe.org/dl/docs/2011/Dethlefs.pdf

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External links

SPE. Well Integrity Technical Section. http://connect.spe.org/WellIntegrity/home.

See also

Use this section for links to related pages within PetroWiki, including a link to the original PEH text where appropriate

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