The oil and gas industry generates vast amounts of data at every stage of the well lifecycle: exploration, drilling, completion, and production. Yet much of it remains siloed and underutilized. The Open Subsurface Data Universe (OSDU™) addresses this challenge by providing a common framework for storing, accessing, and exchanging information across workflows.
At IPT Global, we believe the future of well assurance depends on combining advanced digital solutions with industry-wide standards. By aligning well integrity and operational data with these standards, operators gain new ways to improve efficiency, ensure compliance, and strengthen safety.
The OSDU Forum, launched by The Open Group, provides a neutral space where operators, service companies, and technology providers can standardize the way subsurface and operational data is structured, accessed, and shared. The Forum’s goal is to establish a common data platform that removes silos and promotes interoperability across digital tools.
Through this collaboration, the forum unites operators, service companies, and software providers to create shared standards and reference implementations, forming the foundation for managing and exchanging energy data.
The OSDU Data Platform is an open-source, technology-agnostic environment created to eliminate silos and establish a single source of truth for subsurface, well, and operational data.
By providing a secure, scalable foundation, the framework makes information more accessible to operators, service companies, and regulators. This interoperability drives collaboration, speeds decision-making, and enables advanced digital solutions at scale.
Oil and gas companies face persistent data management challenges, including siloed information, inconsistent formats, limited accessibility, and difficulties collaborating across operators, service companies, and regulators.
The OSDU data platform addresses these challenges by providing standardized frameworks and integration across workflows. Adoption of OSDU enables better data accessibility, faster decision-making, lower costs, and a foundation for advanced analytics like AI and machine learning.
The strength of OSDU lies in its reference architecture and standardized data schema. These define how subsurface and operational information is structured, ensuring it can flow seamlessly between different software and workflows.
At IPT Global, we actively contribute to this effort. Our teams have shaped the schemas for Well Barrier Element (WBE) and Well Control Equipment (WCE) Pressure Tests, which are now part of the OSDU reference implementation. This work standardizes well integrity data and contextualizes it for use across drilling, completion, and abandonment workflows.
By working within the OSDU architecture, IPT Global eliminates inefficiencies of custom integrations and positions data for advanced analytics and automation.
As an active member of the OSDU Forum, IPT Global collaborates with industry leaders, technology providers, and regulators to advance open data standards. Together with other OSDU members, we contribute expertise in well assurance, pressure testing, and barrier management to shape how operational data is stored and exchanged.
This role delivers IPT Global clients access to data models designed with real-world assurance workflows in mind, allowing them to adopt OSDU more efficiently and with greater value.
Our standards-based approach extends into IPT Global technology. Through secure application programming interfaces (APIs), we integrate well data, incorporate pressure test results, and connect with cloud-based data lakes. Built on service bus architecture, these integrations deliver information that is consistent, traceable, and actionable across planning, execution, and real-time operations.
By aligning our well integrity and barrier management solutions with the OSDU platform, IPT Global makes assurance data practical and accessible across day-to-day workflows.
The OSDU™ standard is transforming how oil and gas companies manage and use operational data. By replacing fragmented systems with a unified platform, operators can unlock greater value from their information and more effectively adopt advanced digital technologies.
At IPT Global, we put these standards into action. From structuring assurance data and standardizing formatting to embedding well integrity information into daily workflows, we provide the expertise and tools for end-to-end assurance.
Learn how data standards can be implemented to improve your well assurance.
Data integration, the process of unifying information from multiple sources, is essential for effective well integrity management. This includes gathering and analyzing data from various sources, such as well design and construction, continuous monitoring, and well integrity testing. By integrating data across all phases of a well’s lifecycle, operators gain a holistic understanding of well health, enabling more informed decision-making and improving safety and performance. This article explores how data integration optimizes well integrity management and the benefits it offers for optimizing well operations.
Wellbore data is often used across multiple systems, including well integrity management systems, but is typically entered manually into separate applications. For example, the same data might be used to generate wellbore schematics, barrier diagrams, and test plans—three distinct applications that don’t interact with one another. When wellbore data, such as casing, transitions from “as planned” to “as built,” it must be manually updated in one application (e.g., a spreadsheet) and then reentered into another application for the barrier diagram. This process repeats every time the data changes. Similarly, when a well schematic is used to develop a wellbore integrity test plan prior to operations, it must be updated with as-built data, and then the test plan needs to be revised accordingly. Additionally, wellbore data across different systems or regions may have varying structures or Units of Measurement (UoM), which can lead to issues such as calculation errors and data misinterpretation. This creates inefficiencies and increases the risk of inconsistencies whenever updates occur.
Integrating well integrity data unifies these workflows into a single application, enabling seamless communication of schematic and test plan changes while automating test planning and barrier management processes.
One of the leading causes—as much as 50%— of non-productive time (NPT) is the mechanical failure of equipment such as BOPs, subsea trees, and wellheads. There are more than 100 hydroelectric valves and regulators inside a BOP and historically, little was known about the fatigue life of these components. This lack of insight resulted in BOP manufacturers arbitrarily replacing as much as 25% of the BOP stack each time it underwent scheduled maintenance – an approach designed to prevent breakdowns but often resulting in excessive and unnecessary part replacements.
One of the most significant advantages of data integration in well integrity management is the ability to leverage predictive analytics for proactive maintenance and risk mitigation. By analyzing historical data and monitoring real-time data from multiple sources, operators can reduce the likelihood of well integrity issues that could lead to costly downtime or safety incidents. For BOPs, condition-based monitoring (CBM) allows potential problems to be predicted, based on the remaining service life of individual components. This enables BOPs to remain subsea longer without being retrieved to the rig for premature repairs. CBM also allows operators to schedule maintenance at optimal intervals, minimizing unnecessary NPT while ensuring equipment remains in reliable working condition. As a result, unplanned maintenance and production disruptions are reduced, contributing to improved operational safety and efficiency.
Operators must comply with strict regulatory standards and recommended practices for well integrity monitoring and reporting. Non-compliance can lead to fines, operational delays, or even well shutdowns. Data integration ensures that operators meet regulatory requirements more efficiently and comprehensively. By consolidating production data into a unified system, operators can generate regulatory reports more quickly, reducing the time and effort involved in manual data collection. This automated reporting process minimizes the risk of human error and ensures that all relevant data is captured accurately. Additionally, integrated data systems offer real-time updates on well integrity status, enabling operators to respond swiftly to emergencies and remain compliant.
Well integrity management requires close collaboration between various teams, including engineers, operations staff, and safety personnel. Effective communication between these groups is critical for promptly identifying and resolving well integrity issues. When data is spread across multiple applications, teams often rely on phone calls and emails to share updates, which can lead to delays and miscommunication. Data integration addresses this challenge by providing all teams with real-time access to the same information. This unified data view eliminates silos, enabling teams to collaborate more effectively and identify potential issues sooner. Additionally, integrated data systems allow for single updates across platforms, ensuring that all teams can make informed decisions using the most current data without needing to switch between multiple sources.
The digital transformation in the oil and gas industry is progressing rapidly, with companies increasingly leveraging technologies such as artificial intelligence (AI), machine learning, and the Internet of Things (IoT) to optimize well operations. Central to this transformation is data integration and the preparation of data for AI analysis, which forms the foundation for applying advanced analytics to well integrity data. For example, AI-powered analytics can process vast amounts of historical well integrity data to uncover trends and anomalies that humans may overlook. These insights can then be used to inform maintenance strategies, optimize well operations, and improve safety.
Data integration is crucial for effective well integrity management. By consolidating information from well design, construction, and continuous monitoring, operators can enhance their understanding of well health, leading to more informed decision-making and improved safety. Data integration enables the use of predictive analytics to anticipate equipment failures, mitigate risks, and reduce downtime. It also supports the development of unified applications that consolidate, integrate, and automate well integrity management workflows. Moreover, data integration simplifies regulatory compliance by enabling faster and more accurate reporting and incident response.
Collaboration among teams is significantly improved as all members gain access to real-time data, breaking down communication barriers. As the oil and gas industry increasingly embraces AI and IoT technologies, data integration will continue to be essential for optimizing operations and ensuring safety.
At IPT Global, we are dedicated to helping organizations tackle data integration challenges. Our team of experts is ready to assist you in streamlining your data processes and maximizing your operational potential. Contact us today to discover how we can support your data integration needs!
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 monitoring annular casing pressure (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.
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 sustained casing pressure (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 digital solutions, 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 our digital solutions can enhance your well integrity management, contact IPT Global today.
IPT and Horizon56 have partnered to deliver an integration designed to enhance efficiency and assurance during operations. With the integration of IPT’s SureTec and Horizon56’s RigFlow, operators can now visualize live pressure tests in real-time alongside other critical operations, all within a single, streamlined platform.
The integration of IPT’s application within Horizon56 RigFlow transforms the way operators view and manage their operations. With Remote View part of RigFlow, users can monitor integrity assurance tests while executing DOPs—all from a single screen. Gone are the days of switching between platforms to access critical operational data.
This integration provides a holistic view of your operations, allowing operators to watch live pressure tests as they take place, check plan steps, and add comments in real time. By combining these capabilities into a single interface, Horizon56 and IPT make it easier than ever to ensure efficiency, accuracy, and smooth communication throughout the operation.
Watch live pressure tests as they occur within the broader scope of your operations. Stay updated in real time without switching between multiple systems or platforms.
Add comments and check off plan steps as they are completed, all within the same interface. The ability to communicate directly on each step enhances clarity and reduces the risk of miscommunication.
Operators and rig crews can visualize every step of the process in real time, ensuring that all operations are being carried out in the correct order.
By consolidating rig operations across different software platforms into one interface, this integration significantly reduces inefficiencies, helping to improve workflow and reduce errors.
One of the biggest challenges in operations is managing different processes tracked across various platforms. This can lead to gaps in communication, errors, and inefficiencies. The integration of IPT’s SureTec with Horizon56’s RigFlow addresses this issue by providing a seamless, real-time view of all critical operations.
With Horizon56 and IPT, you can be assured that your team has access to all necessary information for efficient well operations—whether it’s pressure test results, operational steps, or direct communication with your crew.
If you’re ready to take your operations to the next level with real-time insights and unified platform, contact us today to learn more about the integration between IPT SureTec and Horizon56 RigFlow.
Ensuring well integrity is critical in offshore operations to ensure safety and efficiency in oil and gas production. Pressure tests are vital for confirming that well components can withstand the pressures encountered during operations. Just as important are the reports that document these tests, serving as a historical record and helping track the well’s performance over time. Implementing a digital pressure testing solution with integrated reporting capabilities and adhering to best practices for report generation, ensures the data is accurate, clear, and compliant with industry standards.
A major challenge in pressure test reporting is ensuring data accuracy, as errors in data collection or transcription can lead to incorrect assessments of well integrity. Digital pressure testing software, such as IPT SureTec, addresses this issue by automatically converting test data into reports, ensuring the information is accurate, complete, and consistent.
Regular audits further ensure that these reports meet regulatory standards, helping companies avoid fines and penalties.
Pressure tests may sometimes provide results that are unclear or on the edge of acceptable limits when readings fluctuate or are close to preset thresholds. To address this, detailed documentation of test conditions and consultation with experts are essential to determine if further testing is needed.
IPT SureTec’s digital testing software enables detailed notetaking during testing, ensuring clear documentation of uncertainties, which supports informed decision-making regarding well integrity.
A major challenge is ensuring consistent documentation across various test types and wells. Variations in report formats or terminology can cause confusion and make it hard to compare results. Standardized templates and report structures resolve this issue by ensuring that the same format is used for all tests.
IPT provides standardized test reports, making it easier to interpret and compare results across multiple tests.
Test plan reports and test results must be submitted to key stakeholders for review, approval, and signatures. Traditional manual paper-based processes for approving reports often result in delays, lost documents, and version control issues. Ensuring traceability during report handover and approval is crucial for regulatory compliance, while accountability and transparency also enhance business processes.
Digital approval and handover processes reduce the risk of delays, lost paperwork, and version control issues, ensuring reports are quickly approved and stakeholders have access to the most up-to-date version. IPT’s software enables digital distribution of test reports for instant approval, with an audit log tracking all approval activities.
Utilizing IPT’s SureTec and SureView applications offers significant advantages in generating and managing well integrity test reports. SureTec is a desktop testing application, facilitating the creation of test plans and executing tests. It generates standardized reports, detailing each test step, including pressure graphs, schematics, and comprehensive documentation of tested components. With built-in compliance features, SureTec ensures that all reports meet industry standards and regulatory requirements. Test plan and test reports can be routed instantly from the platform upon completion of setting up a test plan or running a test.
Testing data, reports, and analytics are stored in IPT’s cloud-based SureView application, which also supports watching tests remotely in real-time. SureView includes an audit log for tracking all approval activities and allows digital distribution of reports for handover and approval. It also facilitates long-term data storage and easy retrieval, ensuring seamless access to historical test data.
Effective pressure test reporting is crucial for maintaining well integrity and operational safety. Leverage IPT’s solutions to streamline the process, enhance data accuracy, ensure documentation consistency, and simplify handover and approval workflows. For more information on how our digital solutions can enhance your well integrity management, contact us today.
Artificial intelligence (AI) is transforming oil and gas operations by enhancing efficiency, improving decision-making, and reducing risks. However, the success of AI applications depends on high-quality, well-managed data. Preparing data for AI analysis requires strategic planning and adherence to best practices to ensure data is accurate, complete, and suitable for complex AI models. Here are key best practices that companies should adopt to ensure their data is ready for AI applications.
In the oil and gas industry, various data formats can hinder AI applications, which thrive on consistency. Implementing standardized data schemas and company-wide data exchange protocols (e.g., WITSML, PRODML) ensures data is uniform and interoperable, making it easier for AI systems to analyze. Standardization simplifies preprocessing for AI and enhances compatibility.
In the oil and gas industry, various data formats can hinder AI applications, which thrive on consistency. Implementing standardized data schemas and company-wide data exchange protocols (e.g., WITSML, PRODML) ensures data is uniform and interoperable, making it easier for AI systems to analyze. Standardization simplifies preprocessing for AI and enhances compatibility.
AI algorithms need comprehensive and accurate data to provide meaningful insights into oil and gas operations. Fragmented or missing data can reduce the reliability of AI applications. A key step in ensuring data integrity is conducting routine data audits to catch missing, duplicated, or inaccurate records. These audits can identify and address incomplete or inaccurate data sets that could otherwise distort AI models and lead to faulty conclusions.
Data governance defines who is responsible for managing data, how it is accessed, and how it is protected. Strong governance ensures compliance with industry standards and protects sensitive information. Achieving AI readiness requires a solid governance framework to securely manage data collection, storage, and access. Establish a dedicated data governance team to oversee roles, responsibilities, and data access controls, ensuring secure and consistent data management practices.
A data lake is a centralized repository for storing raw historical and real-time data in its native format until it’s needed for analysis, without requiring prior structuring or processing. In the oil and gas industry, large volumes of structured and unstructured data are generated, such as seismic data, well logs, production information, and well integrity test data. While structured data is well-organized and easy to search, unstructured data is less organized, making it harder to analyze using traditional methods. To address this, companies should leverage cloud-based data lakes to centralize data storage in its raw form, enabling AI models to more easily access and process data from various sources.
Supervised learning is a machine learning approach where an AI model is trained using a labeled dataset, which includes both inputs and corresponding known outputs (labels). For example, if images of cars and planes are the input, the output label would specify whether it’s a “car” or “plane.” The model’s goal is to learn patterns between the inputs and outputs to accurately predict outcomes for new, unseen data.
In the case of a predictive maintenance model for offshore rigs, labeled data is required to indicate whether equipment is in good or bad condition. Without proper labeling, AI predictions will be compromised.
To enhance the precision of AI models, companies should invest in both manual and automated data labeling processes to improve the accuracy of AI-driven models.
Protecting AI-ready oil and gas data from breaches or unauthorized access is a top priority considering the strategic importance of operational and geological data. Robust security measures, including encryption and access controls, are critical for maintaining the integrity of data used in AI applications. Companies must ensure their data security protocols are up-to-date and capable of protecting not only existing datasets but also the increasing volumes of data that future AI applications will depend on.
Protecting AI-ready oil and gas data from breaches or unauthorized access is a top priority considering the strategic importance of operational and geological data. Robust security measures, including encryption and access controls, are critical for maintaining the integrity of data used in AI applications. Companies must ensure their data security protocols are up-to-date and capable of protecting not only existing datasets but also the increasing volumes of data that future AI applications will depend on.
The volume of data used in oil and gas AI applications is constantly expanding. As AI adoption grows, so will the demands on data storage, processing power, and bandwidth. Being AI-ready means ensuring that your data infrastructure can scale with the volume and complexity of data. By leveraging scalable cloud solutions, companies can manage growing data volumes while maintaining the flexibility to adapt to evolving AI requirements.
Oil and gas companies can position themselves for AI success by standardizing data formats, ensuring data completeness and accuracy, implementing strong governance, and utilizing scalable cloud solutions. For more information on preparing your well integrity data for AI, contact us today.
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:
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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.
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A wellbore diagram/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, encompassing activities such as drilling, completions, interventions, and abandonment, during each respective phase.
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 softwares 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.
The importance of wellbore diagrams cannot be overstated. Over the lifecycle of wells, 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 risk 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, bottom measured depth, 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 mandrals |
| 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, bottom measured depth, 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 |
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 with 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 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.
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.
Softwares 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 toolface 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, production, intervention, and abandonment |
| Geothermal information | Captures Surface Ambient Temperature, Seabed/Mudline Temperature and Formation Temperatures |
| Formation Input / Information | Comprises of Pore Pressure data, Fracture gradient data |
When using wellbore diagramming 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, equipment, 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, which result 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 integrity issues of over the life cycle 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 Diagramming Tool.
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.