Challenge The gas-lift producer in this case study had been shut-in due to sustained annulus pressure (200 bar) and excessive volumes of H2S that could not be handled by the production facilities. The operator wanted to assess primary barrier integrity and guide a workover programme. Traditional diagnostics methods, such as production logging tools (PLT) and temperature logs, were deemed inefficient because they could scan only the production tubing and were unable to confirm the integrity of the packer and production casing. Identifying and shutting off the source of the water with high H2S content would protect the environment and deliver a production gain of 2,050 barrels of oil per day (BPD). Eliminating the production of highly toxic H2S and ensuring its containment within the well system would also deliver important environmental and safety benefits. Figure 1: Failures in the gas-lift mandrels (or gas-lift valves) were indicated by Chorus spectral acoustic diagnostics. Conventional production logging tools failed to identify any of these leaks. Solution TGT’s True Integrity system with Chorus technology uses spectral acoustic methods to assess barrier sealing performance. The system offers a large scanning radius and the sensitivity to detect even small leaks. The ability to indicate failures in the tubing, in the casing behind the tubing, and in key completion components such as the production packer and gas-lift mandrels makes this technology highly effective at establishing the best approach for remediation when barrier failures occur.   High precision surveys across the reservoir zone characterised the flow and its content, thereby guiding operations for shutting off the water zone with high H2S content. Traditional PLT methods would not have been enough to make this identification as the water source may be above or below the perforated interval. The diagnostics also revealed the effectiveness of cement sealing across the reservoir zones. Figure 2: Reservoir crossflow under shut-in and bleed-off conditions. The zone at 13,440 ft shows flow upwards and downwards and charges the wellbore with water. This zone was isolated using a straddle packer. Result The Multi Seal Integrity product with Chorus technology revealed leaks in all four of the well’s gas-lift mandrels (Figure 1). Having confirmed that the failures were only in the mandrels, the operator changed them using the slickline, thereby eliminating the issue of sustained annulus pressure. Traditional sensors, such as spinner, resistivity and capacitance had not identified an issue in the mandrels, which indicates that the leaks were below their detection thresholds.   TGT’s diagnostics solution also identified an active crossflow between the perforated intervals in this well (Figure 2). The direction and content of the crossflow were determined, indicating which zone had to be isolated. Verifying cement integrity behind the casing enabled the operator to select a cost-effective isolation programme that involved running straddle packers across the interval that was producing the water containing H2S.   After the workover, the well returned to H2S-free production with oil rate increased by 2,050 BPD and reduction in water cut from 96 to 80%. Increased oil production at a reduced water cut boosts recovery efficiency, enabling the operator to extract hydrocarbons in a shorter time period, and to reduce energy consumption and carbon- per-barrel over the life of field. In addition, having less water to manage and treat at surface reduces the energy requirement and emissions associated with these processes.

Here are alternative solutions to improve P&A operations by reducing cost and increasing the reliability of E&P operations Article featured in Harts E&P Magazine   Today, more and more wells are reaching the end of their economic life and need to be decommissioned—a process often referred to as Plug and Abandonment (P&A). Many factors need to be considered when designing an effective P&A operation, especially those that relate to barrier integrity, such as cement bond quality, the presence of behind casing flow, and potential inflow zones.  Oil and gas producers are obligated to perform P&A operations in accordance with regulations and guidance typically developed in collaboration with government bodies to ensure that decommissioned wells and safe and secure.   The main objective of P&A is to restore previously penetrated natural barriers by securing potential barrier failures within the well system. These failures could be related to steel or cement barrier degradation during the operational phase of the well. Steps are taken to verify the sealing capacity of so-called external well barrier elements, including cement bonding, shale or formation creep, and baryte sediments. For offshore wells, re-entry of decommissioned wellbores becomes virtually impossible after a new lateral has already been drilled or when topsides have already been removed. Therefore, it is critical that the well is robustly and permanently sealed.   The resources required and cost of planning and performing a P&A operation are mainly driven by the complexity of the P&A, including whether it can be done riglessly or with a drilling rig. The operator has to strike a balance between meeting the required regulatory needs, deploying the required diagnostics tests, and optimising the time spent to prepare and execute the process. Fig.1: Example of the cost estimation of the onshore geothermal well P&A. Click image to view full report. This P&A cost is not an investment into future profit. It is an investment in protecting the environment and eliminating future hazards. In order to address all concerns, operators are seeking alternative solutions to improve the efficiency and effectiveness of P&A operations by reducing cost and at the same time increasing the reliability of operations.   Today, ‘P&A optimization’ is developing in two main areas: A transition towards ‘rigless’ mode, where P&A operations are performed using slickline, wireline or coil-tubing before the rig moves to the well. Rigless operations may include the abandonment of the reservoir, verification of the well barriers and gathering the input parameters for P&A sequence improvement. The key advantage here is to verify the existing well barriers when the tubing is still in the well. There are recent developments in tubing cement logging (spectral acoustics and through tubing ultrasound), enabling the evaluation of cement bond and seal with certain thresholds to determine barrier isolation. Utilization of alternative or natural barriers instead of conventional cement barriers. This allows P&A engineers to consider shale and formation creep, salt dome, squeezing bismuth and polymers to improve the sealing of the external well barriers and take the reliability of the barriers to the next level. The main advantage that operators see today is that shale, for example, may work as the best downhole barrier, because it does not degrade with time, has close to zero permeability, and may even seal potential future leaks or failures. In fact, simple calculations show that 30 m average cement barrier (as per NORSOK and U.K. P&A guideline) with permeability of 20 micro darcy will start to leak at a rate of 0.25 m3 gas a year if 1,000 psi pressure is applied. A similar leak rate for typical shale creeps permeability will only be observed in the presence of 2-5 m of well-bonded shale. The same 30 meters of shale will be almost impermeable (link to the presentation). Fig.2: Graph showing the optimization of the P&A process. Operators typically plan P&A processes years in advance and develop the strategies individually for each well, taking into account the construction of the well, lithology and the technologies available on the market today. Above all, the strategy should meet the requirements of the regulatory bodies of the country in which the operator abandons the wells, as well as the operators own policies.   The example below shows the experience of a North Sea operator in using ‘P&A optimization.’ To improve the P&A process and demonstrate the ability of natural barriers to withstand reservoir pressure, the operator performs a test of the shale barriers for future abandonment.   For a particular field on the Norwegian Continental Shelf, characterization of the overburden formations indicated that a simplified permanent P&A strategy is possible based on a concept with annular sealing from ‘creeping’ Green Clay and a buffering capacity in the underlying Balder formation. Leak scenario simulations with a fracture growth simulator concluded that such a permanent P&A strategy is robust against deep gas migrating, given that a sufficient stress contrast is present between the sealing Green Clay and the Balder. Estimates of the stress profile in the overburden derived from sonic logs indicated such a favorable stress profile is present. However, this stress profile had to be confirmed by dedicated stress tests. Consequently, ‘Extended Leak Off Tests’ (XLOT) were planned and performed during the P&A operations in both the Balder and Green Clay.   The XLOT in the Balder formation was performed through perforations in the intermediate casing. However, as the Balder interval consisted of varying degrees of poorly bonded cement, this introduced a risk of uncertainty with regards to depth control—where the fracture(s) propagate and if there is communication to above or below the Balder formation.   To mitigate this risk, the operator utilized TGT’s True Integrity system with Chorus acoustic technology, combined with downhole temperature and pressure sensors positioned close to the perforation depth. Chorus and its ‘Acoustic Power Spectrum’ was used to establish the injection/fracture point in the Balder during the XLOT and confirm the integrity of cemented casings above and below the Balder.   Fig.3(a): Advanced Extended Leak Off Test. Chorus tracks and classifies the flow behind 13 3/8” through tubing. Deployed riglessly and through tubing, the Chorus Acoustic Spectrum enabled the induced flow classification (no flow, channeling in cement, and fracture flow) in the Balder formation and revealed the fracture initiation points behind the casing. It also confirmed there are no issues with cement seal integrity with accuracy of 15 psi/day pressure failure or 10 ml/min of leak rate.   The XLOT test conducted by the operator showed the main test output list can be extended in cases where Chorus acoustic monitoring is implemented. This case proved that the integration of the downhole data acquisition can be performed with no interference in the traditional XLOT program.     Fig.3(b): Advanced Extended Leak Off Test. Chorus tracks and classifies the flow behind 13 3/8” through tubing. The Chorus Acoustic Power Spectrum visualizes active induced fractures and cement seal integrity behind the casing. The exact fracture depth can be determined and capacity analysis can be performed by monitoring the decay of the acoustic signal over time during the flowing-back stage. Cement sealing can be verified by interpretation of the acoustic signature recorded across the cement barrier.   The above-listed unique datasets can be used today by rock mechanics, well integrity, and well abandonment engineers.   With the right combination of technologies, good planning and execution, the operation was successful and results were confirmed, in addition to validating the sealing Green Clay intervals, a stress contrast of 11 points, and proving this new permanent P&A concept (details in SPE). This enabled the consideration of the shale barriers such as Balder for permanent P&A.   Decommissioning a well securely and permanently requires both an accurate P&A program and the use of alternative barriers to ensure long-term, sustainable integrity. It is essential to use proven verification techniques to inform the P&A program and validate the seal integrity of critical barriers.  

The oil and gas industry is continually raising well integrity standards and moving closer to a ‘no compromise’ approach. Article in Harts E&P   Mechanical “multifinger” calipers have been used routinely by integrity managers for decades as the primary diagnostic method to evaluate production tubulars, partly because they offer a broad range of benefits, but partly because there was no viable alternative. There is now another option.     The miles of metal tubulars that form the backbone of the well system are fundamental to its integrity. Chief among these are the production tubing and production casing, often referred to as “primary tubulars” or “primary barriers” because of their special role in keeping wells safe, clean and productive. Primary tubulars are the central conduits that transport fluids between reservoirs downhole and the wellhead. Collectively, primary tubulars form the wellbore and, from an integrity perspective, their main task is one of containment—keeping pressurized fluids safely inside the well system permanently—protecting and producing 24/7 for the entire life of the well.     But primary tubulars have their work cut out for them; they need to unfailingly withstand the rigors of downhole conditions. Well systems are dynamic and can be hostile environments for man-made materials, even steel. Extremes and variations of pressure and temperature can cause mechanical stresses, well fluids can potentially corrode and erode the steel tubes, and mechanical interventions can cause additional wear over time. Regular inspection is therefore important to ensure continued safe, clean and productive operations. Tube Diagnostics Tube inspection tends to focus on three main attributes: tube wall thickness, tube wall defects and tube geometry. And although tube geometry or profiling is important, wall thickness and defect sensing are typically the two main objectives from an integrity perspective.     With these applications in mind, the industry has developed a number of diagnostic technologies and methods aimed at tracking the condition of primary tubulars. Each has its strengths and drawbacks in terms of accuracy, resolution, coverage, efficiency and cost, when measured against their ability to assess wall thickness, defects and geometry. In a recent industry survey of 100 well integrity management professionals conducted by TGT, mechanical “multifinger” calipers were identified as the most prolific diagnostic method used to evaluate production tubing. For production casing, electromagnetic and ultrasound techniques were the most popular, but calipers were still prominent.     Mechanical calipers offer a broad mix of attributes that make them suitable for tube diagnostics. They are widely available to suit all sizes of production tubing and casing, they are relatively inexpensive and easy to deploy, and can provide comprehensive assessment in all three areas of wall thickness, defect sensing and tube geometry. However, calipers have several application-specific drawbacks, mainly in terms of accuracy in determining actual wall thickness in some scenarios, and sensing small defects.     According to the industry survey of integrity managers, the most important attributes experts consider when selecting diagnostic methods to evaluate production tubing are: the accuracy and sectorial coverage of wall thickness measurements, and the completeness and resolution of defect sensing. Geometry assessment is a lesser priority. Furthermore, the experts required a wall thickness accuracy of at least ±3% and a defect resolution of approximately 3 mm.     To track tube wall thickness, calipers measure internal diameter (ID) and estimate thickness by assuming a nominal outside diameter (OD). Variations in the actual OD or external corrosion, both invisible to calipers, can invalidate the thickness value. Also, scale or wax deposits on the inner surface can mask internal defects and lead to further false thickness computations. And while the accuracy of caliper ID measurements is approximately ±5% (±0.5 mm), the total system error for wall thickness can reduce to ±10% (±1 mm), or worse if there is scale or external corrosion. This accuracy is far below the ±3% level currently required by integrity managers.     For defect sensing, calipers offer highly precise radial measurements via 24, 40 or 60 fingers spaced azimuthally around the inner tube surface. Thin, 1.6 mm fingertips can sense the smallest defects provided the defect lies in the path of the finger passing over it. Practically, there are gaps between fingers that vary according to tube size and finger density. For example, the gap between 24 fingers in 3-1/2 inch, tubing is about 7 mm. This means that the fingers only sense about 10%-30% of the inner wall surface and it is possible for small defects or holes to pass undetected between fingers. A new alternative Despite the drawbacks, mechanical calipers have been used routinely by integrity managers for decades as the primary diagnostic method to evaluate production tubing, partly because they offer a broad range of benefits, but partly because there was no viable alternative.     In an effort to provide an alternative, TGT has developed a new diagnostic platform that can be used independently, or together with calipers or other techniques to provide a more accurate and comprehensive evaluation of tube integrity. Pulse1 is the industry’s first slim tube integrity technology capable of delivering “true wall thickness” measurements of production tubing in eight sectors, with complete all-around sensing of tube wall condition.     Unlike calipers that measure ID to estimate thickness, Pulse1 uses electromagnetic energy to measure actual metal wall thickness directly. This can translate into greater accuracy, especially if the tube wall is coated with scale or has external corrosion. Pulse1 delivers eight sectorial wall thickness measurements up to an accuracy of ±2% in all common tubing sizes, and up to ±3.5% in production casings. This meets or exceeds new industry requirements and represents about a five-fold improvement on caliper accuracy.     In terms of defect sensing, Pulse1 can sense localized metal loss defects equivalent to 7-10 mm diameter holes in the most common production tubing sizes. Calipers offer greater resolution, and Pulse1 provides greater coverage, so combining both delivers a more comprehensive assessment then previously possible. The graph depicts primary tube integrity utilizing Pulse1 to evaluate 6-5/8-in. casing, and a comparison with XY caliper. Overall metal loss measured from Pulse1 is greater than that estimated by XY caliper. The caliper will only detect internal loss, whereas Pulse1 will measure actual metal thickness and assess both internal and external loss. (Source: TGT Diagnostics) Efficiency, versatility and chrome Corrosion-resistant chrome alloy completions provide protection from corrosive and toxic fluids, and the inner wall surfaces are often coated with an additional thin protective film. Many operators prefer not to use calipers to inspect such completions because the millimeter-thin tips of caliper fingers might scratch the inner surface, exposing the alloy and leaving it vulnerable to attack. It’s a dilemma because regular inspection is essential, and previous electromagnetic methods only provided an average non-sectorial thickness measurement. Pulse1 provides eight thickness measurements and is deployed with soft-touch roller centralizers with less point-pressure on the tube wall, minimizing the risk of scoring. This makes it a safer alternative for inspecting chrome completions. And because Pulse1 utilizes ultra-fast sensing technology and time-domain techniques, it is as effective in chrome alloys as in conventional steel tubulars.     In terms of efficiency, diagnostic interventions cost time and money. The Pulse1 tool OD is 48 mm slim and delivers accurate sectorial wall thickness in tube sizes from 2-7/8 inch to 9-5/8 inch. This means operators can survey production tubing and the casing below the tubing shoe in a single deployment, saving rig time and intervention costs. Combining Pulse1 with Pulse4 enables multi-barrier assessment, and both can be deployed rigless on slickline improving efficiency. Enhancing integrity management The oil and gas industry is continually raising integrity standards and moving closer to a “no compromise” approach, and this development is helping the industry to achieve that goal. For applications where accurately tracking wall thickness is the main priority, Pulse1 can be considered as a reliable and practical alternative to mechanical calipers. And if the well is prone to scale, wax or external corrosion, Pulse1 can deliver significantly improved accuracy. If the diagnostic objective is a more comprehensive no compromise evaluation, then combining Pulse1 with caliper will offer the best results.

Challenge The completion string of a gas producer was upsized from 3 ½’’ x 4 ½’’ to 4 ½’’ x 5 ½’’ with 13% chrome tubing to enhance production. Prior to starting the workover, the A-annulus was successfully pressure tested to 1,500psi. The old completion string was cut above the AHC packer, retrieved and replaced with the new ‘13CR95’ tubing together with a new packer. An A-annulus leak was then observed after setting the packer, but with no TCA communication.   Before continuing, the operator needed to understand the integrity dynamics at play and ensure that the new packer was sealing. Conventional diagnostics could have meant another costly workover, lost production, and the risk of damage to the expensive 13CR95 tubing joints. All of which were clearly undesirable. Multi Seal evaluates the seal performance of multiple barriers, locating leaks and flowpaths throughout the well system, from the wellbore to the outer annuli. Solution To identify the integrity breach, TGT designed a diagnostic programme utilising the ‘True Integrity’ system with Chorus (acoustic) and Indigo technology. Slickline conveyance was used for efficient and low cost rigless operation, and minimal footprint.   Two survey passes were deployed, one with the well shut-in and another with continuous water injection into the A-annulus. During shut-in conditions, the baseline temperature and acoustic responses confirmed that there was no cross flow or lateral flow anywhere in the well system.   Injection was then started in A-annulus and the acoustic and temperature surveys were repeated. This time, the temperature profile exhibited a cooling effect caused by water being forced into A-annulus, but there was no temperature difference across the upper packer.   Notably, clear acoustic responses were evident at two intervals under injection conditions. A high amplitude wide frequency band acoustic signature, typical of ‘leak flow’ was observed at X175 ft. Also, a lower amplitude, lower frequency signal was observed around X650 ft. No acoustic signal was observed across the upper packer confirming it was sealing properly. Multi Seal Integrity answer product showing comparison between measurements acquired during shut-in and injection conditions. The primary leak point is clearly visible at X175 ft, and a minor leak interval is evident around X650 ft. Result The analyst confirmed the leak point in the 9-5/8” casing at X175 ft. The operator was able to assess the integrity of the well and decided not to remediate the casing leak, deciding instead to operate the well with the proper monitoring and risk mitigation plans in place.

Challenge Using corrosion-resistant materials such as high-chromium–nickel alloy for tubulars helps to protect well completions from corrosive fluids. But these alloys present a serious challenge for conventional electromagnetic pipe inspection systems.   This ADNOC survey took place in a high-temperature sour well. The flow-wetted areas of the well had been completed with chrome-resistant alloy (CRA) tubulars. The diagnostic system, particularly the data acquisition and interpretation process required for the corrosion assessment of CRA tubulars, is much more complex than for conventional steel tubulars. In this case, the corrosion study was a high-temperature environment where the produced gas contained hydrogen sulphide (30%) and carbon dioxide (10%). Chrome Tube Integrity gives you the clarity and insight needed to manage well system performance more effectively. Solution The operator, ADNOC Sour Gas, selected TGT’s Chrome Tube Integrity product to provide an accurate barrier-by-barrier assessment of the corrosion-resistant alloy tubulars in the well.   Powered by the True Integrity system using the Pulse electromagnetic platform, Chrome Tube Integrity delivers accurate wall thickness data for CRA tubulars and can differentiate between internal and external defects, when complemented with the calliper data. TGT has conducted detailed tests on machined defects to calibrate the Chrome Tube Integrity product for this purpose. The assessment of low-magnetic tubulars such as CRA is possible without compromising on quality if the fast-response Pulse sensor is used.   The Chrome Tube Integrity measurements were made in memory mode with the sensors being run on slickline. This was an industry first for through-barrier integrity diagnostics in highly corrosive gas wells completed with high-chromium–nickel tubing. Pulse technology showing its capability to differentiate between standard collars and CRA collars. Result The survey provided a quantitative assessment of corrosion across three barriers: tubing, production casing and intermediate casing. The survey also updated and confirmed the depths for casing collars and centralisers. A fourth barrier (surface casing) was identified and qualitative assessment made.   Chrome Tube Integrity showed that all the CRA tubulars complied with the manufacturing standard; no corroded intervals were detected (See logplot). This new approach provided the operator with an integrity baseline and enabled optimisation of future assessment and intervention plans.   This project confirmed the value of Chrome Tube Integrity as an effective product for a targeted investigation of specific integrity breaches or as routine surveillance support for ongoing integrity management programmes. It also demonstrated the suitability of Chrome Tube Integrity for conducting multi-barrier assessments in wells that contain corrosion-resistant alloy (CRA) tubulars.