Several aged oil wells in offshore oil field are drilled in a conventional method. These wells are subjected to Casing-Casing Annulus (CCA) problems that might appear during the production operation and/or the shutdown phases. A continuous monitoring is performed to avoid issues related to well integrity and safety. The expected source of Casing-Casing Annulus (CCA) problem is mainly due to poor primarily cementing placement into the outer-casing strings especially across shallow aquifers formations. Due to long shutdown period on subject wells, these wells are encountered with high rate of CCA phenomena among other wells. An immediate mitigation action is required to resolve the issues by applying rig workover operation which is considered highly cost approach with low success rate. The rig workover operation results might lead to suspension or abandonment of these wells. The impact will affect the production target and the oil recovery around the area.
A new methodology approach was selected using chemical sealant recipes as a rigless operation to repair CCA problem with cost-effective and safe manner for first time in offshore filed. Based on the wellhead and annuli survey, the bleed down and build up tests were conducted and followed by close monitoring on suspected wells, which revealed sustained casing pressures and fluid return at the surface. Several fluid samples were collected and analyzed in the lab. Based on the findings, the procedures and the proper design were conducted to inject the chemical sealant into connected cement channels behind casing strings. Curing time and injection rate with required volumes of chemicals were considered based on the pressure responses and chemical performance.
The results from the rigless operation job utilizing the new approach showed wide-ranging success rates based on well by well cases and conditions such as 1) Age of the well, 2) Sustained pressure observed at the surface, 3) Injectivity rates, 4) Chemical additives volume and 5) Downhole conditions (pressure / temperature).
The new technique added a great value on restoring the well integrity and saving the rig operation cost. In addition, the approach contributed to achieve maximum sustainable production target through ensuring the well operability and reducing the production down time. Challenges, methodology, work schedule, risk assessment, lessons learned and findings have been covered in this paper.
In the world of downhole sealing technology, there have been relatively few new developments in recent years. Traditional methods of cement and bridge plugs continue to be the standard but don't always provide an optimal solution. Thankfully there is a new technology on the market that provides a superior seal in wells when compared to traditional methods. That technology is comprised of bismuth and thermite.
Deng, Guijun (,Baker Hughes, a GE company) | Kendall, Alexander (,Baker Hughes, a GE company) | Cook, Christopher (,Baker Hughes, a GE company) | Wakefield, John (,Baker Hughes, a GE company) | Maenza, Frank (,Baker Hughes, a GE company) | Tom, Andy (,Baker Hughes, a GE company) | Knebel, Mark (,Baker Hughes, a GE company)
This paper is a continuation of a previous work, SPE191734 (
Three factors primarily contributed to its successful qualification. First, new backup technology eliminated traditional design limitations imposed by conventional manufacturing and enabled us to design and print a backup system with ultra-expansion capacity and superior conformability. Second, an internally developed polymer that exhibits great elongation and extrusion resistance played a key role in holding the 15,000 psi pressure reversals at 350F in the ultra-expansion states. Finally, a state-of-the-art design process seamlessly integrated design, material characterization, design optimization, and test validation, enabling rapid failure diagnosis and design iterations to ensure rigorous customer requirements were satisfied. This integrated process reduces development costs and shortens time to market.
An ultra-high expansion openhole HPHT packer was developed as a result of advances in Additive Manufacturing technology, polymeric materials, and a holistic design process. Physical test validation demonstrated:
15,000 psi pressure reversal and 15 minute hold at 350°F. Displacement of 0.5 in and 15,000 pressure reversal at 350°F. Elastomer element system remained in good visual condition in post-test inspection.
15,000 psi pressure reversal and 15 minute hold at 350°F.
Displacement of 0.5 in and 15,000 pressure reversal at 350°F.
Elastomer element system remained in good visual condition in post-test inspection.
This is the industry's first commercial completion packer with an Additive Manufactured element containment system. It is also the industry's first ultra-expansion packer to demonstrate HPHT capability.
This paper reviews existing analysis of well integrity related regulation in upstream unconventional oil and gas projects and proposes a methodology to enhance such regulation in the future. This paper has compiled findings from a number of peer-reviewed sources assessing regulatory systems across a number of jurisdictions. These findings were based around four key questions that this paper has assessed (1) what is the overall assessment of current regulatory systems; (2) where to-date are the key areas that current research have focused on; (3) what are the key strengths identified in current research; and (4) what are the key gaps in current research?
This paper demonstrates that the body of work provides a wide array of assessments and conclusions. Whilst some are quite explicit in their judgment of a particular system’s effectiveness, many refrain from making a holistic assessment in a particular jurisdiction. Much of the research involves the application of prisms, such as environmental risks or local government jurisprudence. Along with these prisms, a number of common aspects of research are identified that strengthen the analyses, such as the use of ‘as drilled’ data and the use of relevant data samples. Some research gaps remain despite these strengths.
The majority of previous researchers can identify some degree of ineffectiveness in various regulatory regimes. Further, a number of gaps exist as a result of regulatory systems being incomplete or inadequate, potentially masking other inadequacies. To address these gaps, this paper proposes a methodology to improve and clarify knowledge and practical recommendations to improve the effectiveness of assurance activities by both regulatory agencies and operators. Specifically, this methodology focuses on a typological assessment of written rules in a number of jurisdictions. As an example, we present an ‘as built’ dataset to assess compliance with rules and identify means of assurance. This methodology proposes surveying of regulatory agencies and operators to validate the assertion that gaps can be identified and corrected and provide more insight into how regulatory systems function and the systematic causes of gaps.
Nafikova, Svetlana (Schlumberger) | Bugrayev, Amanmmamet (Schlumberger) | Taoutaou, Salim (Schlumberger) | Baygeldiyev, Gaygysyz (Schlumberger) | Akhmetzianov, Ilshat (Schlumberger) | Gurbanov, Guvanch (Schlumberger) | Eliwa, Ihab (Dragon Oil)
A major operator on the Caspian Turkmen shelf has started to encounter sustained casing pressures (SCP) attributable to insufficient isolation across a hydrocarbon gas zone, due to downhole stresses and other contributing factors. Enhanced placement techniques of conventional cements failed to prevent SCP, confirming the requirement for an alternative cement system that can withstand anticipated stresses and resolve this challenge. An innovative and cost-effective solution was applied and successfully solved the SCP challenge due to its unique self-healing properties.
If cracks or microannuli occur and hydrocarbons reach the cement, the system has the capability to repair itself, restoring integrity of the cement sheath without external intervention. The cement system is placed conventionally in the annulus across or above the hydrocarbon-bearing formation. It then acts as a pressure seal, expanding to accommodate downhole changes and healing if any hydrocarbon reaches it. This technology has been used in four wells in the field with excellent results.
Two wells were used to demonstrate the capabilities of the self-healing cement as a lead cement slurry, which created a cap over the pay zones. The self-healing cement was designed with low Young's modulus for optimum flexibility. To minimize the risk of set cement integrity failure due to microannuli or microdebonding from chemical shrinkage after setting, linear expansion up to 1.2% was incorporated into the design. After cementing, the wells were intentionally exposed to a sequence of high-pressure tests, which induced annular pressures in the wells. However, because of the self-repair capability of this cement, isolation and integrity were effectively restored in the two wells within 1 to 2 weeks without external intervention. As a result, the self-healing cement technology has become the standard for the field for all future wells, and the operator plans to extend the self-healing cement technology to other fields with similar challenges.
This paper clearly demonstrates successful casing pressure remediation without intervention by engineering a flexible, self-healing cement system. The design strategy, execution, evaluation, and results for two wells are discussed in detail and will help to guide future engineering and operations around the world.
Offshore field started on operation to produce crude oil with 27 API° as sweet crude and sour crude with 32 API° since 1960. Large number of wells in offshore field revealed undesirable phenomena related to well integrity issues as potentially sustained pressure on several casing strings. Well integrity management emphasis on preventing well problems related to well safety and integrity such as casing leak, Sustained Casing Pressure (SCP), downhole safety valve (DHSV) failures. The direct impact from integrity management added great value in terms of decreasing in operating down time, improvement in well control and safety aspects, and reducing unplanned repair intervention. In addition, the loss of well integrity can cause major accidents with a severe risk to the personnel, asset and environment.
The paper aims to illustrate a methodology results on applying effective well integrity monitoring techniques. A focus was made to improve monitoring well integrity through reviewing wellhead surface parameters, annulus sections pressure and downhole condition. In addition, the subject wells should be kept under close monitoring at a safe operable with an integral condition. Non-integral wells are common in aged wells, which are becoming a challenging issue to restore its integrity and operability especially for such aged completion. As a part of well integrity review, the concerns had been identified, investigated, and subsequently mitigations actions are recommended to restore the well integrity. Currently, it is confirmed that 25 oil producers with casing leak problems, which resulted to be converted from conventional completion to a slim hole with limited future accessblity. Based on lab reusltes and logging interpretations, it is indicated that the root cause of casing leaks is due to corrosive water flow from shallow aquifer formation. Therefore, an immediate remedial action is required to improve well construction.
A successful worked over well with integrity issue as a casing leak was repaired by cement squeeze into across the corroded casing interval, which enhanced well integrity and restore well productivity. The resulted showed that tubing leaks encountered with well integrity due to sustained casing pressure. Therefore, the pressure on production casing can cause severe failure with catastrophic damage. The results also illustrated that a water flow through poor cement is a major cause of sustained casing pressure in the outer casing strings. The cause of pressure on production casing is generally easier to diagnose than that pressure on one of the outer casing strings. Challenges, methodology, work schedule, risk assessment, lesson learned and findings are included in this paper. The effective well integrity management resulted on great deal of benefits, which are related to securing wells, well operability, cost saving, and sustained maximum production target.
Well Integrity engineers are commonly challenged with using limited resources, and even more limited data, when trying to identify which wells amongst their diverse well inventory may be prone to damage and failure, the mechanisms and influential factors responsible for the potential damage and failures, and the reason why certain wells may pose the greatest risk. Furthermore, these integrity engineers are often uncertain as to the parameters that should be tracked; what inspection methods should be conducted, in which wells and at what frequency measures should be taken; and how the asset risks can be adequately determined and relayed to management to prioritize near-term and future financial investments into well integrity and decommissioning cost centres. In this paper, an approach and workflow are described on how the application of a combination of reliability and risk methods, parameter-based damage models and available field data can be used to develop a tool used by asset integrity and operations personnel to risk-rank wells by the probability of failure and associated consequences. Additionally, this paper illustrates how the approach and models developed are adaptable to both the damage mechanisms specific to the application and to the data and parameters that are currently being measured or readily obtained, or other related variables that can used as suitable proxy parameters. As experience and history build (adding to the understanding and prioritization of damage mechanisms and key parameters), and to improve estimated values of the associated probability of failure due to these mechanisms, the knowledge is fed back into the model to improve its predictive capabilities. This paper also describes how the methodology was applied by a commercial SAGD operator to develop a subsurface isolation risk assessment tool that was tailored to their wells, their application conditions and the parameters that they measure. The types of static and dynamic parameters that this tool considers, including geologic, well design, construction and operational data, are also illustrated, as well as how the tool is being used to prioritize injection and production wells by relative risk. Illustrative examples of how well, pad and asset risks are being identified, rolled-up across the asset and summarized are presented, and how well integrity and risk metrics are being communicated within the company. Ongoing activities to continue to update and advance the risk-ranking model are also noted; in particular, potential opportunities to develop improved mechanistic and data-driven models and predictions of damage and failure likelihoods, based on pooled reliability data and information across the broader thermal recovery sector. 2 SPE-196081-MS
Metal expandable annular sealing systems were used in a 4 ½" completion as an effective high-pressure isolation method inside 6" open hole mudstone formation in the Foothills Basin of Colombia. Effective isolation proved to be historically difficult to achieve.
The operator was approached with a solid metal expandable sealing system with rotation capabilities as an annular barrier for a preferred cementless completion. The sealing system needed to be assembled on a full-bore liner able to deliver robust deployment with a high-pressure seal in a worse case washed-out scenario. The deployment of the system consisted of one annular barrier placed above and one annular barrier placed below the mudstone zone.
Following careful job planning with the operator, the rotationally capable completion was deployed without any incidents. To achieve pressure integrity to set the metal expandable annular barriers, a ball seat sealing system was incorporated to allow the system to be closed and the annular barriers to be set.
After putting the well onto the pipeline, the client recorded a 52% increase in their expected produc-tion from previous wells. Successful results were accomplished as effective isolation was achieved and enhanced production was obtained because of the effective stimulation. This paper overviews the appli-cation, design, implementation and results of the use of new metal annular sealing systems in a 4 ½" completion as an effective high-pressure isolation method inside a 6" open hole, drilled in fractured sandstone and mudstone formations.
This document describes the process of planning and the execution of the production tubing micro-leak’s location detection with the use of Spectral Noise-High Precision Temperature Logging and globally novel technology of multi-set bridge plug services and its isolation with an ISO 14310 V0 rated (bubble tight) Straddle Packer assembly, fully compliant to H2S service per NACE TM0177 / ISO 11960
Accurate location identification of communication between production tubing and annulus in the corrosion resistant monobore completion of a raw gas injector well with ultra-high concentration of H2S and CO2 led to intense research for optimal solutions to detect micro-leak location and its further remedial solution.
The micro leak exhibited unique behavior which occurred mainly in a gas phase with a long duration build-up of annulus pressure. This required a complex leak detection campaign, involving Spectral Noise-High Precision Temperature Logging as the primary method of determination, and pressure testing of tubing string with the multiset retrievable bridge plug, being set on an electric wireline at different depths, as the secondary method of leak and confirmation.
The most suitable method of isolation from a feasibility and reliability points of view was to manufacture specific H2S/CO2 resistant straddle packer capable of withstanding the raw gas injection requirements.
During the non-intrusive testing it was possible at an early stage to confirm the location of the leak above the downhole safety valve. The noise-temperature surface read-out mode logging tools were run down to safety valve depth in a liquid and gas phase, indicating a zone of suspicion. The zone of suspicion matched the tubing tally with a tubing connection.
In order to confirm the presence of micro-leak at suspected points a multiset retrievable bridge plug was utilised. The tool used was a new to market multiset bridge plug with a unique technology which gave the possibility to re-set the plug multiple times within one electric wireline run. Considering the unique behaviour of the leak which appeared mostly when a production tubing was containing a gas phase under a high pressure the pumping of nitrogen in the top section of the tubing string was performed. The Multi Set bridge plug confirmed the location of the leak flawlessly showing a perfect results of execution and reliability. Checking the zone of interest with multiset bridge plug installed across and pressure tested with nitrogen confirmed the presence of leak at a tubing joint connection.
The next step after the leak location had been identified was to restore the well integrity with the installation of V0 rated Straddle Packer, which was successfully installed at the first attempt. It is important to note the highest available grade of H2S/CO2 resistant materials (Inconel 718 and FFKM elastomer) was selected during the design, manufacturing and qualification of the Straddle Packer. Restoration of well integrity has been confirmed during the following start-up of the raw gas injection.
Rigorous planning and coordination of several vendors resulted in the excellent collaboration introducing the latest global technologies in an extremely corrosive well environment. The resultant success of the complex well intervention activity, when leak investigation and remedial plans were worked out in parallel, led to restoration of the well and recommencement of Raw Gas re-injection in a record time of 8 months from the problem discovery to its solution.
This paper presents the rapid development of a high expansion retrievable V0-rated bridge plug that effectively leveraged engineering simulation and additive manufacturing to design, optimize, and qualify the new plug in accordance with the ISO14310 and API11D1 standards. This technology was mobilized for deployment into a customer well within less than 12 months.
For this project, a major Norwegian continental shelf (NCS) operator required a high expansion wireline retrievable bridge plug with a small outside diameter (OD) that was capable of gas-tight zonal isolation in 7 in. tubing while meeting the ISO14310 and API 11D1 V0 classifications. To address this challenge, several design concepts were developed using computer-aided design (CAD) and simulated using finite element analysis (FEA) to determine the optimal design and to establish the design factor of safety. Initial prototype testing showed unexpected failures of the mechanical backup system as a result of non-uniform loading from the rubber element, which had been assumed to be evenly distributed for the initial FEA. Leveraging FEA to verify the failure mode increased its fidelity and enabled successful generation of alternate solutions with an alternate material, in this case nickel alloy 718. A revised mechanical backup system was manufactured within three weeks using internal direct metal additive manufacturing capability; it was successfully validated within an additional two weeks. The final V0 trials were successfully completed a month later with additively manufactured components, and the technology was mobilized for deployment into the operator’s well within less than 12 months.
The successful design, development, and mobilization of the 7-in. high expansion V0-rated bridge plug within only 12 months demonstrates how FEA modeling and additive manufacturing can be successfully leveraged to reduce development timelines while identifying and producing innovative solutions. Speed to market and the delivery of robust solutions on time are becoming more critical in the cost-constrained oil market; consequently, tools such as FEA and additive manufacturing are increasingly becoming fundamental methods for meeting these new challenges, as demonstrated by the 7-in. high expansion V0 bridge plug project.
This paper shows how leveraging FEA in conjunction with fundamental testing failure analysis can be critical to overcoming technical challenges. Furthermore, combining these capabilities with additive manufacturing can accelerate timelines and increase the probability of project success and operator satisfaction.