Subsea blowout preventer (BOP) soak testing is a long-standing part of pre-deployment programs. However, it remains one of the least consistently executed aspects of BOP control system evaluation. While teams perform the test routinely, they often overlook insight into stabilized pressure behavior.
Once a subsea BOP stack is deployed offshore, limited access significantly increases the cost of uncertainty. In 2023, IPT Global collaborated with Seadrill on an article published by Drilling Contractor examining the operational value of standardizing BOP soak testing and proposing a structured framework aligned with the American Petroleum Institute’s (API) Standard 53.
A subsea BOP soak test is a pressure stabilization procedure. Rigs perform it during pre-deployment testing to evaluate the integrity of the BOP control system under sustained pressure conditions. Unlike dynamic testing, soak testing allows pressures to stabilize and the system to settle into equilibrium.
During this stabilized period is when that behavior often emerges. Gradual pressure decay or inconsistent regulator response become apparent once transient effects dissipate. These conditions are not always obvious but can directly influence stack readiness and long-term system reliability.
Identifying these issues before deployment allows for investigation with limited operational impact. When teams do not identify these behaviors, they often surface during operations. At that stage, troubleshooting options are fewer and consequences are more costly.
Despite the importance of well control assurance, subsea BOP soak testing still varies across rigs, fleets, and regions. Common differences include test duration, applied pressure, acceptance criteria, and documentation practices.
In practice, this variability rarely reflects a lack of focus on safety. In IPT Global’s experience supporting pre-deployment testing, variability most often reflects legacy practices, differing OEM guidance, and misaligned acceptance thresholds. Over time, these inconsistencies make results difficult to compare and increase reliance on interpretation rather than data-driven evidence.
Standardizing subsea BOP soak testing does not mean removing operational judgment or imposing rigid procedures across all systems. Instead, it establishes a shared baseline that supports clearer execution and more consistent interpretation of results.
In the article, we discussed the operational value of more structured subsea BOP soak testing, aligned with API Standard 53. The intent was to reduce unnecessary variability while preserving flexibility across different BOP configurations.
Soak testing offers a rare opportunity to observe control system behavior once transient pressure effects have stabilized. When teams miss or inconsistently execute that opportunity, they overlook meaningful indicators of system health. API Standard 53 already serves as the foundation for subsea BOP equipment system requirements. Expanding guidance to clearly address soak testing would strengthen consistency while preserving flexibility across different system designs and operating environments.
Digital pressure data enables teams to review stabilization trends directly, revealing gradual decay, irregular stabilization, and repeatable anomalies across tests.
With IPT Global’s Equipment Health Monitoring HealthAnalytics software and Monitoring service, digital diagnostics capture high-resolution pressure behavior during soak testing, enabling objective, contextual evaluation of subtle trends. Engineers in IPT Global’s Real-Time Operations Center (RTOC) monitor test data in real time and support decision-making during pre-deployment activities.
Together, our HealthAnalytics and Monitoring modules strengthen engineering judgment rather than replace it. Objective data provides a common reference point, improves alignment between operators, drilling contractors, and OEMs, and supports more confident decisions related to deployment readiness and pre-deployment assurance.
Subsea BOP soak testing delivers value through how teams evaluate results and act on them. Programs that consistently derive data-driven insight approach soak testing as part of a broader assurance process.
As subsea systems continue to increase in complexity, the ability to reduce uncertainty before deployment becomes increasingly important. Subsea BOP soak testing remains one of the few opportunities to observe control system behavior under stabilized pressure conditions.
Through the SureTec® Equipment Health Monitoring solution, IPT Global applies a consistent, data-driven approach to subsea BOP soak testing during pre-deployment operations. By focusing on how control systems behave under stabilized pressure conditions, teams gain clearer insight into system performance before deployment decisions are made.
As subsea systems continue to grow in complexity, the way soak testing is executed and interpreted matters more than ever. Aligning practices with API Standard 53 provides a common framework for evaluating control system behavior, reducing unnecessary variability, and strengthening well control assurance across fleets. When teams pair that framework with objective pressure data and structured evaluation, soak testing becomes less about confirming pressure holds and more about understanding what the system is communicating before it goes offshore.
Looking ahead, IPT Global continues to advance digital software integrations that support consistent application of subsea BOP testing practices and ongoing improvement across the testing lifecycle.
For additional context, read the full article published in Drilling Contractor: Standardizing subsea BOP soak testing: overview of value and recommended best practices – Drilling Contractor by Patrick Hillard and Leonard Childers, IPT Global; and Ahmed Omar, Seadrill
Well integrity is fundamental to safe and efficient oil and gas operations. It refers to the ability of well barrier elements (WBEs) to prevent uncontrolled fluid flow from the reservoir to the environment. Maintaining the reliability of these barriers is essential for minimizing risk, avoiding costly incidents, and ensuring long-term sustainability.
Across the well lifecycle, from drilling and completion through production and intervention to plug and abandonment (P&A), each phase presents challenges that can compromise integrity. As wells age, equipment and materials degrade, operating conditions shift, and the potential for failure increases.
Ensuring integrity over decades requires centralized data management and full lifecycle visibility. Today, more than ever, Artificial Intelligence (AI)-driven analytics help detect, predict, and prevent issues before they escalate.
Historically, well integrity management has been fragmented across disciplines and vendors. Data from testing, inspection, and maintenance often resides in separate systems, limiting visibility and slowing response times. Inconsistent documentation and handovers between drilling, production, and abandonment teams create knowledge gaps that can lead to operational and safety risks.
Today’s operators face increasing regulatory scrutiny, growing environmental expectations, and ongoing cost pressures. Managing well integrity across the lifecycle is no longer just about compliance; it is about achieving continuous assurance and operational efficiency through intelligent, connected systems.
AI is transforming how the oil and gas industry approaches well integrity. As a result, modern well integrity software such as IPT Global’s SureTec® uses AI-driven analytics to convert large volumes of operational data, including pressure tests, sensor readings, maintenance logs, and inspection reports, into actionable results.
SureTec solutions incorporating AI models can:
With AI-enhanced reporting and visualization, IPT Global engineers can identify trends across hundreds of wells, verify barrier status in real time, and prioritize interventions that reduce risk and downtime.
The foundation of well integrity begins with precise barrier verification and documentation. During construction, digital wellbore diagrams, automated test planning, and AI-assisted validation ensure that well barrier elements (WBEs) meet design standards. In addition, AI tools evaluate pressure test data using trend analysis and rate-of-change modeling to objectively confirm test outcomes. IPT Global’s SureTec platform provides integrated tools to accomplish this, through the WellSchematic and BarrierManagement and PressureTesting solutions.
This phase benefits from centralized cloud storage and approval workflows, ensuring regulatory traceability and efficient collaboration between the operator, service companies, and regulators.
Meanwhile, during production, operators must balance maximizing output with sustaining barrier integrity. AI-driven well lifecycle management systems consolidate real-time data from sensors, inspections, and historical reports to continuously assess the status of well barriers and envelopes.
By combining analytics and predictive modeling, production teams can detect corrosion, erosion, or equipment wear before they compromise safety. This intelligence supports decisions on workovers, interventions, or decommissioning, reducing unplanned shutdowns and ensuring regulatory compliance across operations. IPT Global’s SureTec platform provides integrated tools to accomplish this, through the WellSchematic and BarrierManagement and PressureTesting solutions.
Workovers and interventions introduce added complexity with multiple crews, shorter timelines, and simultaneous testing. AI-enabled multi-test monitoring allows teams to track test results in real time and automatically flag deviations.
This approach improves the efficiency of barrier verification while maintaining full traceability. With consistent data flow from intervention to production, teams gain visibility into all well integrity tests, ensuring operational continuity and regulatory compliance. IPT Global’s SureTec platform provides integrated tools to accomplish this, through the WellSchematic, PressureTesting, and Equipment Health Monitoring solutions.
In the final stage of the well lifecycle, the goal shifts from production optimization to environmental safety and regulatory compliance. Regulations vary globally, but all require thorough documentation of barrier verification and abandonment procedures.
AI-powered well integrity software aggregates historical WBE data, providing a complete picture of each barrier’s condition before, during, and after abandonment. Predictive analytics can detect defective cement, corrosion pathways, and equipment weaknesses before P&A operations begin. IPT Global’s SureTec platform provides integrated tools to accomplish this, through the WellSchematic and BarrierManagement, PressureTesting, and Equipment Health Monitoring solutions.
This data-driven approach supports a safe, verifiable, and auditable abandonment process, reducing risk and ensuring long-term environmental protection.
Across every phase, data is the foundation of well integrity management. Modern platforms integrate real-time testing data, historical maintenance records, and regulatory reports into a single unified view.
IPT Global’s advanced reporting and analytics capabilities, powered by AI, allow teams to:
By connecting data from drilling and production through abandonment, operators gain insight into well health across the full lifecycle, empowering proactive decision-making and improving safety performance.
Managing well integrity across the full lifecycle of a well is complex, but AI and data-driven insights are making it more predictable, transparent, and efficient than ever before.
By integrating AI-driven analytics, centralized data management, and intelligent reporting, operators can sustain well integrity, reduce non-productive time (NPT), and ensure environmental and regulatory compliance from drilling to abandonment. The future of well integrity lies in connected intelligence, where data, technology, and expertise converge to protect assets, people, and the planet.
As operators continue to evolve their approach to well integrity management, integrating new technologies like AI-driven analytics is key to sustaining well integrity over time. Yet, the fundamentals of sound barrier design, verification, and maintenance remain just as critical.
For a further look at how these well integrity principles apply across drilling, production, intervention, and abandonment, read our article Managing Well Integrity Over the Entire Well Lifecycle.
At the International Association of Drilling Contractors (IADC) Advanced Rig Technology (ART) Conference, IPT Global Chief Technology Officer Cody MacDonald explored the future of drilling automation in oil and gas, emphasizing how data integration between service providers is becoming essential to safer, more efficient rig operations and well integrity management.
As a leader in well assurance intelligence, IPT Global helps operators and drilling contractors strengthen well integrity, improve visibility, and make more confident decisions to achieve greater efficiency from spud to completion.
One of the most significant barriers to effective automation is siloed operational data systems. Many rigs rely on multiple third-party service vendors, each with independent automation tools that rarely exchange data reliably or communicate in real time. This challenge is common across automation in oil and gas, where interoperability underpins digital efficiency.
Through IPT Global’s collaboration with a global super major, Cody showed how the SureTec platform connects service providers through integrated systems, enabling the secure transfer of well integrity data. This unified data approach is essential for optimizing performance in drilling automation and achieving true rig data interoperability across the entire well lifecycle.
Automation in drilling isn’t only a software problem — it’s also about hardware readiness. Certain tasks, like digital pressure testing, can’t be fully automated unless rigs are equipped with actuated sensors positioned correctly on choke manifold valves.
Ultimately, successful rig automation depends on synchronization between physical infrastructure and intelligent digital systems. Software alone can’t deliver consistent, safe results without the right instrumentation in place.
Moreover, Cody cautioned that automation implemented without strong data governance and quality assurance control can have the opposite of its intended effect. In such cases, poorly designed systems or fragmented drilling data management practices may amplify errors instead of reducing them.
To prevent this, operators should:
Operator data ownership remains one of the industry’s most critical challenges. From spud to abandonment, drilling data passes through multiple systems and stakeholders. Key questions include:
Cody proposed a data custodian model: an operator-driven framework that defines, governs, and enforces data standards for all service parties. This model ensures data remains accurate, accessible, and under operator control throughout the well lifecycle.
Cody concluded that the future of drilling automation depends on collaboration, data transparency, and standardization. At IPT Global, our SureTec platform helps operators connect systems, partners, and workflows to enable safer, smarter, and more efficient well delivery.
As the energy industry continues its digital transformation, data integrity and rig automation integration, and the adoption of standardized data, custodian models will form the foundation of the next generation of automated well delivery systems and well assurance intelligence.
Ensuring well integrity throughout a well’s lifecycle is essential for maintaining safe and efficient operations in the oil and gas industry. Effective annular casing pressure (ACP) management is key to preventing problems with well barrier elements (WBEs) such as casing leaks, sustained casing pressure (SCP), and subsea safety valve (SSV) malfunctions. Implementing a structured ACP monitoring and reporting system ensures transparency during operational handovers and provides an auditable record for forensic analysis if required. Without effective integrity management, operators risk unnecessary well shut-ins and costly interventions.
The illustration below shows the standard designations for the “A”, “B”, and “C” annuli in a subsea well. The “A” annulus is the void between the production tubing and the smallest casing string while the “B” and “C” annuli are the voids between the successive outer casing strings.
The sealed annuli contain trapped fluids that later become heated by the high flow rate of formation fluids during production. The hotter fluids expand, causing an increase in the annulus pressure on the well. Eliminating any pressure fluctuations due to thermal effects, a pressure change in the “A” annulus is an indication of a leak. The pressure measured at the wellhead in the “A” annulus, or in the other annuli that terminate at the wellhead, is called the annular casing pressure (ACP).
Annular casing pressure (ACP) is a primary indicator to detect leaks within the barrier envelope. Deviations in pressure within the “A” annulus may indicate leaks in one of the barrier elements, excluding the Downhole Safety Valve (DHSV). Troubleshooting involves adjusting pressure in the adjacent “B” annulus and the production tubing to identify the failing barrier element. The rate of pressure change can help assess well integrity risk levels.
A production packer anchors the tubing string and isolates the “A” annulus from both the formation and the tubing’s interior. Leaks in these seals or any connections can lead to SCP within the “A” annulus. For subsea wells, only the pressure in the “A” annulus can be monitored and bled down, while surface and land wells allow monitoring and bleeding at the wellhead.
API Recommended Practice (RP) 90-1 identifies three sources of annular casing pressure:
Of the three pressure sources, SCP is the only one that will rebuild once bled off. SCP may result from communication with a pressurized formation or from a barrier that inadvertently creates a flow path. The following potential communication paths can affect the “A” annulus and the “B” and “C” annuli.
The occurrence of SCP tends to increase throughout a well’s lifecycle, from drilling to abandonment. Continuous monitoring of ACP is therefore considered best practice.
API RP 90-1 Section 9 outlines recommended procedures for ACP in offshore wells. It highlights the importance of equipping all accessible annuli with the ability to monitor pressure, perform bleed-offs, and inject fluids when necessary. Initial pressure testing should be conducted to establish baseline values and identify any existing ACP resulting from operational conditions.
IPT Global’s SureTec® PressureTesting solution, including the TestEngine module, supports this process by helping operators establish and track baseline pressure values consistently across wells.
Regular monitoring is essential, with operators responsible for setting a minimum frequency to ensure pressure remains within diagnostic limits. The section distinguishes between operator-imposed and thermally induced pressures and emphasizes the need for close observation following any operational changes.
When SCP is detected outside of acceptable thresholds, the frequency of monitoring should be increased. For inaccessible annuli, a formal risk assessment is required to determine the feasibility of restoring monitoring capabilities and to assess the implications of any pressure sources.
Overall, this section offers a comprehensive framework to support safe and effective ACP management and ensure long-term well integrity.
Annular casing pressure management is a critical component of well integrity management. By understanding the causes of ACP fluctuations, implementing best practices, and leveraging solutions like SureTec PressureTesting, operators can proactively prevent integrity failures, minimize costly interventions, and enhance operational safety. Standardized reporting, automated data collection, and routine diagnostics ensure regulatory compliance and long-term sustainability. Investing in a structured ACP management strategy ultimately protects assets, personnel, and the environment. For more information on how like SureTec PressureTesting can enhance your well integrity management, contact IPT Global today.
Coiled tubing (CT) is a long, flexible, metal or composite pipe with no joints that is used in the oil and gas industry for a variety of purposes:
Coiled tubing has several advantages, including increased efficiency, cost effectiveness, and safer operations. Some of its disadvantages include limited depth and borehole size, high maintenance costs, and reduced accuracy. This article describes the operation and applications for coiled tubing units (CTUs), and it specifically covers the well control stack and industry recommended practices for pressure testing coiled tubing.
Coiled tubing units (CTUs) include the following components:
Coiled tubing can be used for drilling operations without the use of drill pipe and a rotary table, which speeds up the process. A bottom hole assembly (BHA) with a drill bit is connected to the coil tubing and inserted in the well. The injector head pushes the tubing into the well and the BHA uses a motor or rotary steerable system that rotates the drill bit. The BHA is essential for directional drilling and wellbore navigation.
A downhole mud motor may also be used in coiled tubing drilling operations to convert the hydraulic energy of the drilling fluid into mechanical energy to rotate the drill bit independently of the coiled tubing string.
Coiled tubing is a beneficial tool for circulation in well interventions due to its continuous length’s ability to navigate complex wellbores. Most often, the operation will involve pumping nitrogen or various fluids to free the well of light debris (sand) and removing water or condensates built up during production.
Coiled tubing allows the deployment of logging tools into the wellbore to collect data about the formation and well conditions, such as formation pressure, fluid composition, temperature and formation properties. This is especially useful in highly deviated or horizontal wells where traditional wireline logging might be challenging.
Subsea lubricators dictate the length of perforating guns that can be run when using conventional drill pipe. Coiled tubing simplifies perforating operations by allowing the use of long bottom hole assemblies (BHA) while maintaining dual well control barriers. This enhances safety and operational efficiency.
Coiled tubing can be connected to pumping units and inserted in a well to pump fluids for various treatments, including well stimulation, hydraulic fracturing, acidizing and cementing. The ability to pump the fluid without interruption while continuously inserting the coiled tubing allows a steady and controlled flow rate.
Coiled tubing can be used for various production enhancement techniques, such as gas lift or artificial lift systems, contributing significantly to improved efficiency and reduced downtime. In gas lift installations, CT enables more efficient and precise placement of gas lift valves along the tubing string, especially in deep or deviated wells. In artificial lift systems, CT significantly reduces installation time for electric submersible pump systems in shallow gas wells to address liquid loading issues.
CT is valued for its flexibility, efficiency, and ability to perform a wide range of tasks without the need for a rig, making it an essential tool in offshore well interventions.
The CT operator in the control cabin manages the entire process of deploying and retrieving the tubing during CT operations. Coiled tubing is spooled off the reel and passes through a tubing counter that measures the length of the tubing being deployed and retrieved. The tubing is then guided through a gooseneck and directed downward to the hydraulically driven injector head, which the CT operator uses to control the movement and depth of the CT string. The tubing becomes straight before it enters the well control surface stack.
Beneath the injector head, the stripper assembly on top of the well control stack provides a dynamic seal around the tubing string, which is crucial for running the CT in and out of live wells.
During intervention operations, CT can be used to circulate acid, nitrogen or cement. Devices may also be conveyed down the tubing for purposes such as sealing, cleaning, or initiating other downhole operations. For example, balls may be pumped down the tubing to isolate sections of the well, or darts may be used to trigger tools and other chemical treatments. The CTU uses hydraulic pressure to push these devices down the tubing and through a dual-flapper check valve. The flow of hydraulic fluid is carefully controlled to ensure the devices travel to reach their target accurately. Coil tubing also allows logging tools to be deployed down the wellbore to collect data about the formation and well conditions. The CT Operator monitors the movement of devices in real time using sensors and telemetry systems.
At the end of the operation, the tubing is pulled out of the well and spooled back onto the reel. A high-pressure swivel joint on the reel hub allows fluid to be pumped while the reel rotates.
Coiled Tubing operations are governed by regulatory standards and recommended practices to ensure safety and efficiency. Key standards and recommended practices are 30 CFR Part 250 Subpart G and API RP 16ST, respectively. 30 CFR Part 250 Subpart G is a mandatory federal regulation for outer continental shelf operations, whereas API RP 16ST is a voluntary industry standard. The recommended practices in API RP 16ST offer detailed guidance to support and enhance compliance with the regulations set forth in 30 CFR part 250 sub part G.
API RP 16ST (Recommended Practice for Coiled Tubing Well Control Equipment Systems) is a crucial standard governing coiled tubing operations. The second edition, along with its Addendum 1 from February 2022, provides updated guidelines for well control equipment systems used in coiled tubing operations to ensure enhanced safety and operational efficiency. A summary of some of the key sections of the recommended practice are listed below.
A coiled tubing (CT) well control barrier is defined as a tested mechanical device, or a combination of devices, designed to prevent the uncontrolled release of wellbore fluids.
Key components include:
This section outlines the recommended order of components in the well control stack from the top down:
1. Stripper Well Control Component
2. Blind Ram Component
3. Shear Ram Component
4. Kill Line Inlet
5. Slip Ram Component
6. Pipe Ram Component
7. Dedicated SBR Component
All well control equipment must undergo pressure testing.
The well control stack plays a critical role in flow control and well control in CTUs by sealing off the wellbore to contain unexpected flow and high pressures during drilling, production, and intervention operations. A typical well control stack used for CT operations is shown below. Actual stack configurations may vary based on the operator and the conditions encountered during coiled tubing operations.
As stated in the API RP 16ST, all well control equipment components should be pressure tested every seven days. The pressure test sequence for each component consists of a low-pressure test, followed by a high-pressure test. A component passes the LP test (from 250 psi to 350 psi) if the pressure stabilizes with no visible leakage for at least five minutes. The component then passes the HP test (MASP plus 500 psig) if the pressure stabilizes with no visual leakage for a minimum of 10 minutes and does not decrease below the intended test pressure. It can take several pressure test attempts to test all of the well control components. The figure below shows the stripper being pressure tested.
It’s common to pressure test multiple tools during a single well control stack test to improve testing efficiency. This is done by testing one tool, disconnecting the assembly, installing a second tool and then reconnecting the assembly. Typically, the test plan will need to include steps after this process that verify the connection point. Similarly, tools that are meant to stop pressure from coming up the coil (dual flapper check valves, wash heads, etc.) will usually need to be verified during the pressure test.
CTUs play a critical role in oilfield operations, providing a range of applications from drilling to interventions. Coiled tubing’s flexibility and efficiency make it a valuable tool for optimizing well performance and maintaining well integrity. For details on IPT’s well integrity solutions, contact us.
The formation integrity test (FIT) is one of three types of formation strength tests, and it is used to evaluate the strength and integrity of a newly drilled section of well formation. After setting a section of casing and drilling out the casing shoe, several feet of new formation is drilled and the formation is gradually pressurized to a pre-determined pressure and then held during a subsequent shut-in stage. The FIT data is analyzed to verify the bonding strength of the cement around the casing shoe and to determine the maximum mud weight that can be used to drill the next well section. This test is essential to ensure that the formation can withstand the pressures it will encounter during drilling and production operations and to avoid loss of well control.
The integrity of a wellbore changes with every drilled foot of depth, and mud weight is the sole pressure mechanism keeping the borehole stable. Formation Integrity Testing is vital for maintaining well integrity as it helps to prevent well control issues, such as blowouts and other hazardous events. In addition to verifying the maximum mud weight needed to drill the next well section, a FIT is used to compute the minimum mud weight required to prevent hole collapse and to evaluate the quality of the cement bond around the casing shoe. By verifying the formation’s ability to hold pressure, avoiding hole collapse, and assuring cement integrity, operators can substantially improve the safety and efficiency of drilling operations.
Essential safety measures during FIT include:
After the casing or liner is cemented and before drilling out the cement at the shoe, a casing integrity test (CIT) is typically run to ensure the integrity of the casing or liner. During the CIT, drilling fluid is pumped into the casing or liner. The shut-in valve is closed when the target pressure is reached (below the maximum allowable pressure). If the pressure analysis passes specific criteria, the CIT is successful.
FIT guidelines are established to ensure that a valid test is conducted. The following guidelines below are used for reference during the test and subsequent FIT analysis.
The standard FIT, the Leak-Off Test, and Extended Leak-Off Test are commonly known as formation strength tests. The different uses and procedures for these tests are described below.
A standard formation integrity test involves gradually increasing the bottom hole pressure to a predetermined level to check the formation’s ability to withstand the pressure without leaking off drilling mud. Following a successful casing integrity test, FITs are generally performed using the following steps:
A Leak-Off Test (LOT) is performed to determine the exact pressure at which the formation begins to fracture. It is often conducted at various depths during the drilling process to assess the formation’s pressure containment capacity. The key difference between the LOT and standard FIT is that the LOT involves a controlled increase in pressure until a small amount of fluid leaks into the formation, indicating the fracture point. This information is valuable for more accurately estimating formation stresses, which can be used to optimize the number of casing strings required.
For a typical LOT, pressurization is continued past the LP until the wellbore pressure induces a stable fracture in the formation (fracture Initiation pressure). When the crack opens, fluid is lost to the formation across the permeable faces of the fracture. These fluid losses lead to smaller increases in pressure as additional fluid is pumped, which is indicated by the change in slope of the plot at a point called the fracture initiation pressure (FIP). The rising pump pressure at the surface up to the pump stop pressure (PSP) indicates stable fracture growth, as fluid is lost along the length of the fracture. After PSP, the fracture becomes unstable at a point called the unstable fracture pressure (UFP) because the fracture is extended away from the wellbore. When the pressure begins to asymptotically level off at the fracture propagation pressure (FPP), the test is concluded. Drilling operations then typically resume if the tests results permit the use of a suitable mud weight and if no cement channels are detected.
The XLOT is a series of LOTs that may be run to obtain horizontal stress data for predicting wellbore stability. The XLOT is a longer and more comprehensive test in which the mud continues to be pumped after the FIP is reached to determine the fracture closure pressure. Chronologically, the XLOT process consists of the following stages:
This process can be repeated multiple times to open and propagate the fracture to gather more data. The figure below shows an XLOT with a repeating cycle.
The results of a FIT are typically analyzed by visually interpreting pressure vs. time and pressure vs. volume plots or comparing them with theoretical models of formation behavior under stress. Key indicators of well integrity from FIT results include:
To accurately analyze LOTs and XLOTs, multiple factors should be considered, such as formation permeability, fluid compressibility, stresses around the wellbore, and mud type.
The following factors can distort FIT, LOT, and XLOT results and lead to interpretation difficulties.
Although the LOP is defined as the point where the trend of the pressure increase deviates from linearity, the pressure-volume trend prior to initiating a fracture can sometimes be non-linear. Factors such as air in the system or seepage caused by permeability in the formation can produce a non-linear pressurization response.
Incorrect identification of FIP, also known as the leak-off pressure (LOP), can lead to a variety of problems and/or unnecessary expenses for a well. For example, if a lower than expected LOP is interpreted as a cement channel, the operator may conduct a squeeze job in an attempt to increase the LOP. However, if the low LOP is caused by a lower-than-expected fracture gradient, the operator will have wasted time and money on the squeeze job. Conversely, if a lower than expected LOP is interpreted as a low fracture gradient, when it is really caused by a cement channel, the operator may use an incorrect low value as an upper limit for mud weights. This could lead to prematurely setting the next string of casing or to choosing a dangerously low mud weight, which may not be able to control the well. Finally, if a LOP is misinterpreted to be higher than the actual LOP, an operator may use an excessive mud weight, which could lead to lost circulation problems.
The effect of drilling fluid properties can induce inaccuracies in the interpretation of surface-collected data, resulting in a higher pressure than the correct value.
FIT analysis is often performed by “eyeballing” the pressure curve to determine whether the test is successful. Subjective analysis introduces human error and inconsistent interpretation of test results.
Higher pump rates result in higher values for FIP and FPP. Since these pressures are recorded from gauges at the surface, higher pump rates result in higher pump friction which causes higher observed FIP and FPP values. These higher pressures are not an indication of formation strength. Therefore, it is suggested that LOTs be performed at the lowest possible pump rate.
Deepwater HPHT wells have a lot of uncertainty regarding the integrity of the wellbore. These wells often experience significant deviations from the planned conditions. They can encounter very high levels of overpressure, intense heat, and formation pressures that are close to the point where formations can fracture.
To minimize measurement distortions and improve the accuracy of FITs, LOTs and XLOTs, several best practices should be followed:
Recent advancements in FIT technology include the development of more accurate and reliable pressure measurement devices, real-time data monitoring systems, and improved software tools for pre-test planning, test execution and analysis.
Recent advances in measurement devices for LOTs and XLOTs have improved their accuracy and reliability significantly. These advancements include:
Conventional formation integrity tests (FITs) for wells require closing the BOP and using the rig’s mud pumps, which can cause non-productive time (NPT). Alternatively, dynamic FITs can be performed using managed pressure drilling (MPD) without closing the BOP or incurring NPT. MPD methods use a closed-loop fluid system to accurately measure fluid flow in and out of the wellbore. These dynamic FITs can be conducted more frequently to verify that the wellbore can withstand the pressures associated with drilling fluids and well construction.
More software tools are available to aid in conducting FIT, including advanced data analysis programs that simulate well conditions to optimize test parameters and improve accuracy. Some software tools offer live monitoring and analysis for LOT and FIT for real time integrity assessment. More advanced software tools can be used for comprehensive well integrity and formation strength analysis.
Formation strength tests are critical processes in the oil and gas industry for ensuring well integrity and safety. Using advanced technology and adhering to the best practices will enhance the accuracy and reliability of these tests, contributing to safer and more efficient drilling operations. Contact us for information about IPT Global’s well integrity management solutions.
A widely accepted definition of well integrity is “the application of technical, operational, and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the lifecycle of a well”. Technical solutions refers to the physical well barriers that contain pressure and hydrocarbons. The failure of a well barrier compromises well integrity, resulting in loss of production and harm to personnel, environment, assets, and the operator’s reputation. Operational and organizational solutions include the planning, design, guidelines, and procedures that help achieve and maintain well integrity.
A well barrier is often referred to as an envelope consisting of one or more well barrier elements (WBEs). Examples of WBEs include drilling fluid, BOPs, the wellhead, casing, cement, packers, and other well components. The failure of a single WBE can cause the well barrier envelope to fail. For wells that are capable of sustained flow to the wellhead, the O&G industry uses two barrier envelopes—primary and secondary—for a high level of reliability.
The primary barrier envelope consists of WBEs that are, or might be, in direct contact with well pressure to prevent unintentional flow of reservoir fluid to surface or another zone. The secondary barrier envelope consists of barrier elements that are, or might be, exposed to contact with well pressure should any primary barrier element fail.
Think of the primary barrier envelope as being inside the secondary barrier envelope. If an element that is part of the primary barrier envelope fails, the elements in the secondary envelope must prevent the release of reservoir fluid to the surface or to another zone.
The primary and secondary barrier envelopes change as wells progress through lifecycle phases, as shown in the table below. For example, the primary barrier envelope during drilling operations is the overbalance hydrostatic pressure from the drilling fluid, but during production the primary barrier envelope includes the casing, cement, production tubing, packers, and downhole safety valves. This is why it’s important for operators to have clear and accurate well barrier diagrams to help all stakeholders visualize changes to well barriers and assess risk over the life of a well.
| WELL LIFECYCLE | PRIMARY BARRIER ENVELOPE | SECONDARY BARRIER ENVELOPE |
|---|---|---|
| Drilling | • Drilling fluids • Completion fluids |
• Casing cement • Casing • Wellhead • BOP |
| Production | • Casing cement • Casing • Packer • Tubing • Downhole Safety Valve |
• Casing cement • Casing • Wellhead • Tubing hanger • Christmas tree |
| Intervention | • Casing cement • Casing • Deep-set plug • Overbalanced mud |
• Casing cement • Casing • Wellhead • BOP |
| Plug & Abandonment | • Casing cement • Casing • Cement plug |
• Casing cement • Casing • Cement plug |
With every well, there are challenges to assessing risks to well integrity. Well conditions change and there are multiple ways that well barriers can fail.
Wells are initially designed and constructed based on certain criteria. However, a well’s operating conditions or utilization may change during its lifecycle, adversely affecting the integrity of critical WBEs. For example, during the life of a well:
Any one or a combination of the above events can diminish the integrity of individual WBEs. Therefore, an effective well integrity management program is needed to validate the integrity of the WBEs to operating conditions that may be different from the original assumptions when the well was drilled.
Well barrier elements can experience leak paths due to mechanical stresses, temperature changes, and exposure to corrosive substances. The figure below shows some of the potential leak paths in WBEs.
Here are some strategies for mitigating risks to well barrier integrity:
International industry associations and standardization organizations have issued the following standards, guidelines and recommended practices related to well integrity.
“Blowout Prevention Equipment System for Drilling” is a standard that provides requirements for the installation and testing of blowout prevention equipment (BOP) systems on land and marine drilling rigs.
“Deepwater Well Design and Construction” is a recommended practice (RP) that aims to improve safety and reduce the chance of losing well control or damaging the environment. It includes considerations for barrier and load cases. This RP is based on the complexity of deepwater operations, which requires a thorough understanding of well design criteria and the equipment associated with them.
“Guidelines for Well Integrity in Drilling Well Operations” is the Norwegian O&G industry standard that defines the minimum functional and performance requirements for well barriers throughout a well’s life cycle. The standard focuses on how to conduct operations and what equipment should be used and is concerned with drilling, completion, and abandonment activities.
“Well Integrity – Life cycle governance” offers guidance to well operators on managing well integrity throughout the well’s life cycle. It is intended for use in the petroleum and natural gas industries worldwide and applies to all wells regardless of their age, location, or type. This part of ISO 16530 addresses the minimum compliance requirements for well operators to claim conformity with this part of ISO 16530. The document addresses each stage of the well life cycle, as defined by six phases: the basis of design, design, construction, operation, intervention, and abandonment.
Well schematics and well barrier diagrams are two distinct methods of illustrating WBEs and their role in integrity management. Each method has its specific applications, contributing to a comprehensive understanding of well integrity management strategies.
A well schematic is an illustration that shows the arrangement of the main WBEs within the well system. The schematic typically includes well and location information, annotations that describe the lithology, depths of the casing and cement sections, descriptions of the major WBEs, mud weights, and formation temperatures.
For years, engineers have used various applications to create well schematics including spreadsheets, word processors, CAD programs, and other planning tools. This has resulted in duplicate data entry with increased potential for errors, change management challenges, and communication and workflow issues during handovers between well phases. Digital well schematic software allows engineers to build well barrier plans in a centralized cloud-based repository that tracks the location and information about each WBE in every well.
Digital well schematics provide several benefits:
For seamless well diagramming, reach out to IPT and discover our user-friendly tool! Contact us now to explore how our easy well diagramming tool can revolutionize your workflow.
Well barrier diagrams display color-coded primary and secondary barrier envelopes and may illustrate all potential leak paths from the reservoir to the surrounding environment. These diagrams describe the status of barrier elements and are valuable for evaluating the consequences and likelihood of specific scenarios. Well barrier diagrams quantify the likelihood of consequences depicted in the diagram, making them useful for risk assessment and decision-making.
Digital well barrier diagrams provide some of the same benefits as well schematics, plus:
The development of well integrity software applications and associated technologies has accelerated since 2010 with the increased digitization of the O&G industry after several catastrophic incidents.
Well integrity software applications define the commitments, requirements, and responsibilities of an organization to ensure the integrity and safety of oil and gas wells throughout their lifecycle. The primary aim is to mitigate the risks associated with uncontrolled releases of formation fluids, which can lead to environmental harm, injuries, and financial losses. This is achieved by identifying potential integrity threats, implementing preventive measures, and regularly monitoring well conditions to prevent leaks or failures. IPT offers rigorous well integrity software and expert advisory services for advanced well integrity management at every stage of the well lifecycle. The software encompasses tools for constructing detailed wellbore schematics, which serve as the foundation for developing barrier schematics and plans essential for test planning and generating comprehensive test plan reports with complete documentation of surface and subsea WBEs to be tested. IPT’s integrity tests leverage proprietary algorithms that significantly reduce pressurized time for testing WBEs and remove validation subjectivity, saving rig time and reducing risk. Additionally, IPT’s well integrity management solutions allow collaboration and handover among teams, while tracking all changes and maintaining versions over the complete lifecycle of wells. IPT’s expert advisors are available to support the process wherever required, whether onsite or remotely. With decades of experience, they excel in generating and optimizing integrity test plans, offering expert assistance before, during, and after testing operations, regardless of location worldwide.
Ready to enhance your well integrity management? Contact us today to learn more about our advanced software solutions and expert advisory services. Don’t wait—reach out today to ensure the safety and reliability of your oil and gas wells.
A wellbore diagram or well schematic, provides a visual representation of the well and its components at any phase of the well life-cycle. It can also serve as a valuable tool to aid in the planning and execution of well operations, from drilling and, completions to interventions, and abandonment.
The detailed graphical information in wellbore schematics display the size (diameter) and length of major components and the depth at which the components are located.
Wellbore diagrams are a critical communication tool for all stakeholders and decision makers. Wellbore diagram programs should have key features like version control and collaboration capabilities to effectively handle risk management and change control. Wellbore schematics also need to be dynamic to track changes over the lifecycle of the well so that data is up-to-date and available on demand. IPT Global’s SureTec® WellSchematic solution is built around these needs, keeping schematics current and accessible across global operations teams.
The importance of wellbore diagrams cannot be overstated. Over the lifecycle of a well, wellbore diagrams are used for:
In the planning phase, operators and engineers utilize wellbore schematics to visualize design alternatives for the intended well. This aids in the safe and efficient delivery of both the well and the associated business objectives.
When integrated with drilling data acquisition software, wellbore diagrams can be used to communicate operational progress against the plan.
A wellbore diagram assists engineers in overseeing well barriers and assessing risks, as well as making informed decisions regarding the final positioning of casing strings, production tubing, and other completions equipment. It also influences decisions about future completions opportunities.
Coupled with actual well performance and production rate data, wellbore diagrams can help to identify potential production challenges and risks associated with well integrity issues.
Frequently updated wellbore diagrams streamline the decision-making process for well interventions and maintenance, serving as a valuable risk management tool to effectively handle well barrier management for interventions.
As a well reaches the end of its lifecycle, wellbore diagrams play a pivotal role in guiding the placement of cement plugs and other well barriers, ensuring the effective prevention of leaks and environmental contamination. This compliance with policy and regulatory requirements is essential, especially during the well abandonment or plug and abandonment process.
Wellbore diagrams differ in appearance but typically contain these components and symbols.
| Component | Description / Symbol |
|---|---|
| General information | Operator, lease name, well number, rig name, legal location, API number, latitude and longitude, date updated |
| Symbol: Displayed at top of schematic | |
| Elevation | Rotary Kelly Bushing (RKB), Mudline (ML), water depth |
| Symbol: Elevation value located at top of the schematic | |
| TD & PBTD | Total Depth of hole and Plugged Back Total Depth |
| Symbol: Values displayed at bottom of schematic | |
| Hole sections | Diameter, top of measured depth, and measured depth |
| Symbol: Vertical or horizontal dashed lines | |
| Casing | Size, weight, top measured depth(TMD), bottom measured depth (BMD), top of cement (TOC) |
| Symbol: Vertical lines representing different casing strings in the wellbore | |
| Cement | Top and bottom of cement, type of cement, yield and slurry weight |
| Symbol: A shaded area around the casing strings indicating the extent of cement placement | |
| Wellbore components | Packers, plugs, valves, tubing and gas mandrels |
| Symbol: A rectangle across the wellbore placed at a specific depth | |
| Completion components | Tubing hangers, gauges, production tubing, downhole safety valve, side pocket mandrel, slotted liner, landing nipple, etc. |
| Perforation depth | The location of perforations as defined by top measured depth (TMD) and bottom measured depth (BMD) |
| Symbol: Small, vertically aligned dots or short lines along the casing or tubing | |
| Liner | Size, weight, top measured depth (TMD), bottom measured depth (BMD), top of cement (TOC) |
| Symbol: Vertical lines inside the casing but not extending to the surface | |
| Lithology column | Vertical representation of formations encountered as the well is drilled |
| Symbol: Shading or patterns that distinguish one formation from another | |
| Formation tops | The upper boundary of geological formations |
| Symbol: A horizontal line with the name of the formation indicates the top boundary of a specific geological layer | |
| Geological symbols | Marks that represent geological features such as faults, unconformities, anticlines, and synclines |
| Symbol: A jagged or wavy line intersecting the wellbore trajectory | |
| Drilling fluid | Mud density, viscosity, formation pressures, temperature, etc. |
| Perforations | Top, bottom, shots per foot, and phasing angle |
| Symbol: open(green) and squeezed(red) | |
| Wellbore trajectory | Wellbore path from surface to target depth expressed in terms of measured depth, inclination and azimuth angles |
| Symbol: An arrow or curve along the wellbore trajectory shows the direction and angle of deviation during directional drilling |
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Casing provides structural support to the well and acts as a physical barrier to prevent fluid migration. The casing string consists of casing sections that decrease in diameter with depth. Casing setting points are adjusted to specific depths, for a particular hole diameter. The casing string is run into the wellbore and cemented into place to ensure proper zonal isolation and guarantee impermeable barrier between different formation zones. Casing is often represented in wellbore diagrams using vertical lines to denote different casing sections from the wellhead to the casing shoe. Liners are casing strings that normally run and set within the wellbore and typically do not extend all the way to the wellhead.
Cement is used to create a barrier between the wellbore and the surrounding rock formations. During well construction, the annular space between the casing and the formation is filled w
ith cement. The cement sheath forms a mechanical and hydraulic barrier, preventing fluid migration along the outside of the casing. Cement is depicted in wellbore diagrams by shaded areas that correspond to the depth range where the cement is placed.
A production tieback is typically connected to the top of the production liner or casing string that runs across the production reservoir interval. The primary purpose of a production tieback is to provide a conduit for the flow of hydrocarbons from the reservoir to the surface.
An intermediate tieback is used to isolate a casing string that cannot withstand possible pressure loads during drilling, usually because of excessive wear or higher higher-than than-anticipated pressures. In some cases, intermediate tiebacks may not connect directly to the top of a liner. Instead, they are typically set at a shallower depth and cemented separately from the production liner.
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Subsurface formation boundaries and geological features can be accurately represented in wellbore diagrams to clearly indicate the geological formations encountered at various depths or hole sections. This helps drilling teams understand the lithology and potential reservoir characteristics.
Formations are separated by upper and lower boundaries where the rock lithology changes. Subsurface formation data, such as seismic surveys, core samples, and well logs help geologists, drilling engineers, and reservoir engineers accurately place the wellbore in the most favorable locations to optimize drilling efficiency, minimize drilling risks, and optimize future production.
Formation tops represent the upper boundaries of specific geological formation classifications, such as chalk, limestone, shale, and sandstone. They are typically marked with horizontal lines or notches
on the lithology column. Formation tops are labeled with the names of the formations they represent and provide valuable information about the depth at which the different formations are encountered.
Annotations and labels provide additional information about the formations, features, and wellbore components. They can explain lithology and provide context for significant geological events, seismic characteristics, and more details about wellbore components.
A completions wellbore diagram is a visual representation of the components and configuration of the completions equipment within an oil or gas well. It provides a clear and comprehensive overview of how the well is equipped for production, including the arrangement of tubing, casing, packers, and other wellbore elements. It also serves as a detailed record of the completions design and completions equipment(jewelries) configuration for future reference, maintenance, and regulatory compliance. The completions diagram is typically accompanied by detailed annotations, specifications, and a legend to explain the symbols and components used. It serves as a critical reference document for well operators, production engineers, and maintenance teams throughout the well’s life cycle.
IPT Global’s WellSchematic solution and other software used to create wellbore schematics typically contain a range of features and functionalities designed to provide a comprehensive and detailed representation of the wellbore.
| Feature | Description |
|---|---|
| Wellbore visualization | Visual display of the wellbore |
| Casing and tubing strings | Generate casing and tubing sections or different sizes (diameter and thickness), depth, and cement sections |
| Deviations and doglegs | Ability to show any deviations or changes in trajectory during drilling |
| Formation tops | Geological data that indicate the depths of different formation tops encountered during drilling |
| Data integration | Integrates real time data from drilling operations such as weight on bit (WOB), rate of penetration (ROP), and rotary speed |
| Completion equipment | Production tubing, packers, plugs, and downhole valves |
| Easy editing | Allows users to modify the wellbore path and components |
| Scale and measurements | Tools to measure and modify distances in angles on the wellbore diagram |
| Survey data | Measure depth, inclination, azimuth, vertical section, northing, easting and readings at various depths |
| Exporting and reporting | Exporting the wellbore diagram in various formats for sharing with colleagues, regulatory authorities, or reports |
| Historical equipment tracking | Records changes to the well’s completion equipment over time |
| Version control | Documenting modifications to the wellbore as it progresses from drilling, completion and production to intervention, and abandonment |
| Geothermal information | Captures Surface Ambient Temperature, Seabed/Mudline Temperature and Formation Temperatures |
| Formation Input / Information | Comprises pore pressure data, fracture gradient data |
When using wellbore schematics software, accurate data entry, validation, and quality control are crucial to various aspects of safety, compliance, and overall well integrity. Inaccurate data entry can result in errors in well control decision-making, which increases safety risks to personnel, assets, and the environment. Erroneous data entries might result in redesigns, corrosion, collapses, or obstructions in the wellbore. For well operations that are subject to regulatory oversight, inaccurate wellbore schematics can lead to non-compliance, resulting in fines or other legal consequences. Inaccuracies could also lead to improper placement of critical wellbore elements, compromising the well’s structural integrity and potentially causing leaks or other problems of over the life of the well. Using wellbore management diagram software with built-in validation checks and data consistency features can help reduce the risk of errors and assist in diagnostics if integrity or production issues arise.
As a well progresses from planning to drilling, completion, production, and abandonment, various wellbore modifications occur. It’s important to keep the wellbore diagram schematic up to date to reflect the specific state and configuration of the well at a given point in time, as well as store all changes that have taken place. Version control is fundamental to change-management processes.
Version control, or versioning, is the practice of documenting changes to wellbore diagrams over a well’s lifecycle to accurately reflect modifications during drilling, completion, workovers, interventions, and abandonment. Each version of the wellbore diagram reflects the specific state and configuration of the well at a given point in time, carrying significant implications for decision-making, regulatory adherence, troubleshooting, and collaboration. This becomes particularly crucial as the responsibility for the well transitions from one department to another throughout its lifespan. Incorporating well-defined approval signatories and technical authorities into the process is an essential requirement for ensuring well integrity.
Wellbore diagram applications have different forms of version control with the goal of a single source of truth. Some applications have project management features that enable users to track versions of wellbore diagrams while other applications may simply record edits and modifications made to a wellbore diagram. Other applications not only store previous wellbore diagram versions but also alert all relevant users when changes are made to a wellbore diagram so they can update it in their local repository.
Wellbore diagrams are indispensable tools in the oil and gas industry, contributing to the efficient and safe operation of wells. Their role in visualizing, documenting, and communicating wellbore information underscores their importance in every aspect of well management. To ensure successful well operations, it is crucial to adopt wellbore diagram software that makes creating wellbore diagrams easy and maintains data accuracy and version control. Contact us for information about IPT Global’s Wellbore Schematic Tool.
To learn how IPT Global’s WellSchematic solution—with barrier diagrams—can support your wellbore schematic needs, contact us today.
Well integrity is crucial to the safety and success of plug and abandonment (P&A) operations, including well decommissioning. P&A operations involve the installation of barriers to seal the wellbore and prevent migration and leakage of formation fluids in perpetuity. Well barrier failure during the decommissioning process could lead to environmental damage, harm to local communities, and significant legal and financial consequences for the operator. The purpose of this article is to describe the importance of well integrity in offshore P&A operations and how to assure well integrity through testing and verification of complete barrier systems.
Operators plug and abandon a well when it is no longer profitable to produce or useful, as with an injection well. The primary objective of the P&A process is to ensure the well’s integrity by creating a permanent barrier system that isolates the wellbore from the formation and prevents fluid migration into groundwater zones or to the surface.
The P&A process begins with assessing the history and condition of the existing well barrier elements and developing a plan to install and verify additional barriers that are required. The operator confirms that the plan meets regulatory requirements and industry guidelines and selects a P&A service provider to perform the P&A operations. Once on site, the service provider removes any wellbore debris or obstructions from the wellbore before logging the well to assess its condition and identify any potential subsurface leaks or hazards.
The service provider places cement and mechanical barriers, such as bridge plugs and cement retainers, at predetermined intervals to isolate zones and prevent fluid migration from the formation. A common well abandonment technique is to place cement plugs on top of mechanical plugs. Cement barriers also provide structural support for the casing, prevent corrosion, and structurally reinforce the wellbore. Cement plugs are used in open hole applications and across liner tops. Physical depth tagging may be performed to confirm plug location.
Next, the service provider verifies the integrity of the barriers using pressure testing and cement bond logging. The contractor may also use diagnostic tools, such as temperature surveys and noise logging, to detect any potential channels or leaks in the cement barriers. After verifying barrier integrity, the contractor cuts and removes the wellhead and any remaining wellbore components, such as production tubing and casing, in accordance with company policy and local regulations. The contractor also retrieves any equipment from the seabed, such as production trees and control systems, and clears the site. Finally, the service provider compiles all documentation of P&A activities into a report for handover to the operator.
Well integrity is critical to P&A operations regarding regulatory compliance, safety, and environmental considerations. Operators must adhere to regulatory requirements and industry standards to ensure well integrity, and they must use responsible practices to mitigate potential hazards that threaten health, safety and the environment.
All regulatory agencies require integrity testing of well barrier components. For example, in the United States, the Bureau of Safety and Environmental Enforcement (BSEE) and the Environmental Protection Agency (EPA) provide regulations and guidelines for P&A operations. In the Norwegian petroleum industry, the NORSOK D-010 standard defines the minimal functional requirements for well design, planning and execution with the aim of maintaining well integrity throughout the life cycle of the well. In the UK, the North Sea Transition Authority (NSTA) and Health and Safety Executive (HSE) regulate these activities.
Meeting regulatory requirements and obtaining the necessary permits for P&A activities can be challenging, as regulations may differ across jurisdictions and evolve over time. Operators must obtain necessary permits and engage with regulatory authorities throughout the P&A process. This will ensure compliance, reduce risks, and manage changes to approved programs that may be necessary during operations.
Plugged and abandoned wells with compromised well integrity can expose the environment to a variety of air and water pollutants. The release of gases, volatile organic compounds (VOCs), or hazardous air pollutants can occur if proper controls are not implemented during and after P&A operations. The migration of formation fluids into groundwater, surface water bodies, or marine environments may impact water quality and disrupt terrestrial and marine ecosystems. Fluid migration across ineffective barriers may create future operational challenges by creating shallow gas or over-pressured zones at unexpected depths.
Well integrity ensures that the paths between different subsurface formations are sealed so that fluids and gases remain confined within their original formation zones. This prevents the risk of uncontrolled fluid migration that could contaminate soil, groundwater, surface water, or marine environments. A quality program and supporting integrity documentation can demonstrate the effective plug and abandonment of assets and may be useful in any investigation or troubleshooting later.
The following is a summary of best practices for ensuring well integrity during and after P&A operations.
Planning P&A activities during the well design phase identifies cost-effective solutions based on well complexity and facilitates smoother execution with a pre-defined plan for abandonment. Early planning also enables knowledge transfer and the handover of critical documentation.
Assess the condition of the well and thoroughly clean the wellbore to remove any obstructions that can interfere with the cement bond integrity and other plugging operations.
Adhere to applicable regulations and guidelines, obtain necessary permits, and engage with regulatory authorities throughout the P&A process to ensure compliance and reduce risks.
Developing well abandonment plans that consider the specific characteristics of the well, reservoir, and surrounding formations is crucial for selecting appropriate techniques and materials to achieve long-term well integrity.
Additional mechanical barriers, such as bridge plugs or cement squeeze operations, may be installed above or below the primary cement barrier to enhance well integrity. All plug depths should be set for the purpose of isolating a zone or protecting a zone based on well conditions and geometry.
Implement rigorous quality control measures, including cement bond logs and pressure testing to independently test and verify barrier integrity (described in the following section).
Compile reports of all activities, including well logs, pressure test results, cement bond logs, and other relevant data.
Regularly monitor and observe abandoned wells to detect any signs of potential leakage or integrity failure to enable timely remediation actions.
The consequences of a barrier integrity failure are considerable, impacting public health, safety, and the environment, and it can lead to legal and financial penalties and damage to reputation. The integrity of a barrier is not assured until it has been tested and verified using the technologies described below.
Well integrity is not established by individual barrier components but on the collective performance of all components in the wellbore. The operator may use data collected during well construction or run a new cement bond log using a sonic tool that measures the bond quality of the cement to the casing and to the formation. This provides insights into channels or voids in the cement sheath that can act as potential pathways for fluid migration. This information is vital in targeting specific zones for placement of cement plugs and mechanical barriers. A common abandonment technique is to place a cement plug on top of a mechanical plug at multiple zones in the wellbore. Cement plugs are also used in open hole applications and across liner tops.
All local regulations require cement barriers to extend across the full cross section of the wellbore. The best methods to validate a cement plug placement are the drill pipe weight test and pressure testing. The main advantage of the drill pipe weight test is that it is used to tag the top of the cement in wells with high angles or poor hole conditions to confirm that the plug is at the required depth. However, the weight test is less stringent than pressure testing when measuring the cement plug seal effectiveness.
Pressure testing is the most effective method of barrier verification. It is used to verify the integrity and effectiveness of the collective barrier system based on specific criteria specified by the operator. Pressure testing is also typically performed on a cement plug set above a plug that was tagged. A predetermined pressure is applied that exceeds the anticipated pressure differentials that the barriers are expected to encounter. Positive or negative (inflow) tests are used based on the direction of expected flow. The pressure is analyzed for a specific duration against the operator’s criteria to objectively determine if the barrier system passes or fails.
IPT provides a comprehensive digital solution for planning, testing, and reporting integrity tests on well barrier systems during P&A operations. Digital pressure testing allows more efficient and accurate integrity assurance because it uses objective criteria to determine whether a pressure test passes or fails.
Qualified professionals should be engaged to carry out monitoring and inspections to properly assess the condition of P&A wells. These professionals should have experience in well integrity management, regulatory requirements, and be able to interpret inspection results accurately.
IPT’s team of subject matter experts provides barrier integrity verification, tracking, and consultation services to support your well integrity program.
The specific steps and techniques to maintain well integrity vary but the means to assure the integrity of the well are constant. IPT’s products and services test and verify the integrity of the entire well barrier system during all phases in the life cycle of a well including plug and abandonment. Contact us to learn more about how IPT’s products and services can ensure the success of your P&A operations.
Well integrity is determined by the reliability of well barrier elements (WBEs) to prevent the uncontrolled release of fluids from an oil and gas well into the environment. The consequences of the loss of well barrier integrity can be severe, ranging from environmental damage to fatalities. Sustaining well integrity throughout a well life cycle is critical in minimizing risk due to failed WBEs. However, a well’s operating conditions or utilization may change as the well ages, adversely affecting the integrity of critical WBEs. It’s difficult to maintain consistency in well integrity over the years through knowledge transfer and documentation handover among teams. IPT provides a centralized cloud-based platform that manages well integrity data and regulatory compliance through each phase of a well’s life, including drilling, completion, production, workover, intervention, and plug and abandonment.
During drilling and completion, improve well integrity management by designing, planning, testing, and reporting barrier verification test results in one integrated well integrity life cycle management platform for total assurance.
Operators use a cloud-based application to build schematics, wellbore diagrams, and test plans for drilling and completion. The application generates a standardized, detailed test plan report including schematics, criteria, and complete documentation of surface and subsea components to be tested for each well integrity test. The tests plans can be digitally routed for approval and securely stored in the cloud using the Assurance Workflow tool.
The Assurance Workflow tool allows signatories to download and review drilling and completion test plan reports, and it simplifies the gathering of digital approvals via mobile devices. It streamlines collaboration and communication by rerouting rejected test plans and test reports for modifications and final approval.
Performing accurate, comprehensive, and efficient integrity tests during drilling and completion is a challenge in high-pressure, high-temperature environments. It requires comprehensive well integrity management software and effective collaboration between the operator and service company performing the tests. An accurate, consistent, and transparent methodology is necessary for validating and managing the integrity of WBEs. IPT’s patented algorithms—including Thermally Compensated Leak Detection evaluate pressure test data based on objective criteria and definitively confirm whether an integrity test passed or failed. Reports for completed tests are automatically uploaded to the cloud and routed for digital approval using the Assurance Workflow tool. The cloud-based platform also provides remote viewing of active tests from anywhere in the world, test data archival and retrieval, and advanced data visualization analysis.
IPT collaborates with operators and contractors on-site and remotely through its industry-leading experts. Field Service Advisors provide on-site integrity test coordination and optimization. Engineers perform post-test reviews to ensure that all components are properly tested. Real-Time Operations Engineers & Advisors (RTOAs) verify that test reports are published properly to assure the traceability of all integrity tests for hand off to the production team. BOP Compliance Surveyors provide third-party equipment inspection and auditing using industry recommended survey and inspection practices.
Blowout preventers (BOPs) serve as a critical secondary barrier during drilling. The challenge for drilling contractors and operators is to know when to repair or replace BOP components to minimize non-productive time (NPT) due to component malfunction or failure. Regulations require operators to periodically pressure test and function test BOP stack components to ensure well integrity. Contractors perform weekly function tests to actuate the rams and annular preventers to ensure they will operate properly in an emergency. The actuation duration and volume of hydraulic fluid required are important indicators of the health of critical BOP components.
IPT engineers monitor and analyze BOP pressure tests, BOP function tests, maintenance, and failure data to gain insight into when and why failures occur. Engineers use data visualization to spot trends in pressure and function test data so that contractors can repair and replace BOP components, when necessary, rather than on an arbitrary schedule as commonly used.
Production has a different set of challenges to maintain well lifecycle integrity while optimizing production. These challenges include complex physical and chemical process changes that occur in the wellbore and surrounding formations. Adding to this complexity, aging oil and gas wells become more prone to corrosion, erosion, and other forms of wear and tear that can compromise well integrity. The production team must decide when to intervene and extend production or retire a well that is no longer safe or economically viable.
The centralized well lifecycle integrity management solution ensures complete documentation handover to the production team. It gives the team access to WBE integrity data and reports for transparency and compliance. It also allows the team to compare integrity data with other wells to identify potential issues before they become major problems.
Integrity testing of well components during light and heavy (workover) interventions presents different challenges for well lifecycle integrity management than testing during well construction. As interventions have a shorter duration of a few weeks, component integrity tests are carried out more frequently compared to the construction of a well. Many offline integrity tests are performed simultaneously on the deck of the intervention vessel to eliminate delays once the crew connects to the well.
Multi-testing capability enables the crew to perform integrity tests thoroughly and efficiently to avoid delays in critical path operations that would be costly for both the intervention service company and the operator. After the intervention is completed, there is traceability of all well integrity tests to hand off to the production team and for compliance with local regulatory bodies.
Compliance regulations that govern plug and abandonment regulations can vary across jurisdictions, which makes compliance challenging for operators with international assets. Operators must comply with these regulations to ensure safe and environmentally responsible operations. Regulations typically cover a range of areas, such as casing and cementing requirements, pressure testing procedures, and monitoring and reporting requirements.
A critical aspect of compliance with plug and abandonment regulations is the need for integrity management of well barrier elements (WBE). Well integrity management software can be used to provide historical data on each WBE. This data can help operators identify any potential issues that may arise during the abandonment process, such as defective equipment or oil leaks. All P&A activities can be tracked and documented with integrity management software providing a comprehensive record of the operation ensuring compliance with regulations are met. By having this data, operators can take steps to ensure that the well is abandoned safely and mitigate risks.
Ensure the reliability of well barrier elements over the entire well life cycle. Implement IPT’s centralized cloud-based platform to manage well integrity data, regulatory compliance, and integrity testing through each phase of the well’s life cycle. With IPT, you can improve well integrity management during drilling and completion, maintain BOP integrity, optimize production while ensuring well integrity, and comply with plug and abandonment regulations. Act now to minimize risk and ensure the safety and sustainability of your operations. Contact us for more information on managing integrity throughout the well lifecycle.
