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  • ChorusX

    The industry’s most advanced acoustic sensing and analysis platform Bringing a new level of clarity, precision, and certainty to well system acoustics A flowing well is full of sound encoded with information about the flow that created it. This, and the fact that sound energy penetrates through well and reservoir materials, is why acoustics has become a powerful diagnostic technique for locating and characterising flow. However, the fidelity and resolution of the sound recording, and the effectiveness of processing and analysis technologies all have a direct bearing on the accuracy and certainty of the diagnosis and resulting decisions.   The well reservoir system is a challenging environment for capturing and analysing the high-fidelity sound required for precise diagnostics. There is a combination of materials and fluids with different acoustic properties, multiple boundaries and mechanical noise that act together to create a complex spectrum of acoustic energy. Decoding the sound and extracting useful flow information from this cacophony requires a special combination of technology, expertise, and experience.   TGT has been advancing the use of acoustics to locate and characterise flow in the well system for two decades. The Chorus brand is already recognised for its sensitivity and dynamic range when capturing high-fidelity flow sounds. Our new generation ChorusX platform takes this acoustic capability to a whole new level to deliver exceptional precision, clarity and certainty. ChorusX brochure ChorusX ingredients ChorusX is the sum of many parts that work in concert to deliver a range of important benefits to analysts and customers. Each ingredient is special in its own way, but the big wins occur when they are multiplied together.   Features Explained Benefits ChorusX has been designed to overcome the limitations of conventional acoustic technology and to provide the three essential capabilities of an effective flow-finding resource.   Reach Ultrahigh sensitivity and extreme dynamic range give ChorusX the spatial and audible reach to record the furthest and quietest flows.   Identify Four new high-definition acoustic maps enable analysts to recognise and distinguish different types of flow easily and confidently.   Locate Eight high-definition array sensors and a unique phase analysis engine work join forces to pinpoint flow sources everywhere in the well system in depth, and radial distance. Diagnostics products and applications Well systems perform by connecting the right fluids to the right places, and mapping flow dynamics downhole is essential to keeping wells safe, clean and productive. ChorusX provides asset teams with the flow insights they need to manage well and reservoir performance more effectively.   As an integral part of TGT’s ‘True Flow’ and ‘True Integrity’ diagnostic systems, ChorusX capability is available through a range of application-specific answer products. Through these answer products, ChorusX delivers clear, complementary answers that enable analysts and customers to reach an accurate diagnosis more efficiently. A robust and accurate picture of the well system enables better decisions and positive outcomes. This means that, when remediation plans are being implemented, there is a greater prospect of first-time success.   True Flow products help asset teams to understand flow dynamics between the reservoir formations and the well completion. Notably, these answer products reveal flow where it matters most—at the reservoir. Some of the distinct True Flow applications and benefits brought by ChorusX include fracture assessment, delineating active formations, and distinguishing between reservoir flow and completion flow.   True Integrity / Seal Integrity products help asset teams to validate the performance of seals and barriers throughout the well system, including packers, cemented annuli, tubulars, and valves. Typical applications for ChorusX include revealing low-rate leaks, tracing the source of B and C annulus pressure, and resolving leaks in close proximity to each other. Resources Platform flyers(8) Hardware specifications(7) Case studies(36) Technical papers(128) Intellectual property(48) More(45) Product flyers(22) System flyers(2) White papers(0) Product animations(21) Resources

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    Case studies
    CS035 Fracture Flow

    Challenge Multistage fracturing is a highly effective development strategy for ultralow- to low-permeability reservoirs. However, in uncemented completions with fracturing sleeves and packers, it can be challenging to identify fracture initiation points and confirm the number of fractures initiated in each treatment.   A lateral wellbore in a horizontal gas producer was completed with more than 3,000 ft of open hole (OH) section across five fracturing stages in a high-temperature and high-pressure tight-gas interval. This well presented several key challenges.   With OH intervals ranging from 200 to almost 1,000 ft, the operator could not be sure how many fractures had been created or where precisely these fractures were located. The initial stage plan was not sufficient to guide packer placement. Placement had to be decided in conjunction with the caliper log and gauged hole analysis. Interstage communication owing to packer bypass or ball failure is a common problem in completions of this kind. This can be caused by higher differential pressure being exerted on the packers during fracturing. Figure 1: Active frac ports and fracture distribution across all stages and three bypassed packers. Solution Fracture Flow is delivered by TGT’s analysts and engineers using the True Flow system with Chorus and Cascade platforms. Integrating insights from a Chorus acoustic survey and Cascade temperature and flow modelling with the production logs, OH logs and calculated rock mechanical properties provides a better understanding of the fracturing process, completion performance and production performance in an OH multistage fracturing completion.   Chorus acoustics and Cascade flow modelling provided a quantitative assessment of flowing fractures and stagewise production from the reservoir behind the liner.   Multi-array production logging results quantified the flow and flow profile inside the horizontal liner. The integration of datasets was conducted in a single deployment to deliver a comprehensive understanding of well completion and production, including clear identification of water-producing intervals. Figure 2: Flow geometry and contribution across the horizontal section. Result The Fracture Flow diagnostic programme evaluated the active fracture ports and fracture contribution in each stage. It also enabled the team to assess the packers, completion integrity, and production distribution behind the liner (Figure 1). Multi-array production logging was used to investigate the flow profile entering the liner.   The survey results identified 34 active fractures and showed that some flow was bypassing several packers. Figure 2 shows the reservoir flow profile provided by Cascade and the True Flow system. Most fractures were clustered around Stage 4 and Stage 5, and this had a major impact on production. Survey results revealed good completion integrity overall, with only three bypassed hydraulic packers. The dual packer isolation systems were shown to prevent communication between contributing stages.   Based on the comprehensive analysis result the water being produced from all fracture entry ports except Stage 5, where water contribution was minimal. Engineering work decreased the water–gas ratio to 5%.

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    Case studies
    CS031 Horizontal Flow

    Challenge Low-permeability oil rim reservoirs can be developed using horizontal wells and multistage fractures. The challenge for operators is to find a hydraulic fracture design that improves production while minimising the risk of gas or water breakthrough from adjacent formations. Fluid breakthrough harms well economics and can lead to significant environmental impacts, for example, through the need for gas flaring.   Predicting and preventing water or gas breakthrough is one of the most important tasks faced by reservoir engineers. Operators will typically use pressure-transient analysis to assess fracture sweep efficiency, but this provides only average fracture parameters. A deeper understanding of downhole flow dynamics can provide an early warning of the locations where water or unwanted gas is reaching the well.   A horizontal well had been drilled into the oil rim of a low-permeability reservoir formation and hydraulically fractured in 12 stages. The gas/oil ratio for the well was high, indicating a potential issue with the fracture design that would need to be addressed before delivering or completing further wells in the field. Quantifying flow dynamics in horizontal well systems and accessing accurate reservoir flow profiles is fundamental to managing well and reservoir assets. Horizontal Flow with Cascade3 is designed to help Production and Reservoir Engineers complete daily tasks with greater certainty and confidence. Whether its locating water/gas breakthrough, understanding the influence of fractures, or maintaining an accurate reservoir model, Horizontal Flow delivers reliable flow profiles in a wide range of completion scenarios. Equipped with the right information, asset teams can take direct action to keep well and reservoir performance on track. Solution TGT’s new Horizontal Flow diagnostics with Cascade3 technology has been created to provide asset teams with the flow insights they need to manage horizontal well and reservoir performance more effectively. This technology can locate fracture entry points and accurately quantify flow in horizontal well systems. This enables operators to assess the fluid contributions from various fractures and porous matrix zones across a wide range of completion designs.   In this case, combining Cascade3 flow modelling and Chorus acoustic sensing would enable TGT analysts to locate and quantify the gas breakthrough zones present in the well, assess current 'out-of-target' fracture size and potential fracture growth, and confirm the source(s) of gas inflow. Horizontal Flow diagnostics with Cascade3 and Chorus technology identified three gas breakthough zones and estimated potential fracture growth for these fractures. Estimated fracture size is shown in 'cross section' track. The results confirmed fracture propagation to an out-of-zone gas bearing formation. The QZI track shows three zones contributing to the gas inflow. There is minor oil contribution from the target formation. The higher formation pressure of the gas-bearing zone reduces the oil contribution from the target formation. Result The Horizontal Flow survey identified three gas breakthrough zones responsible for the well’s high gas/oil ratio and estimated potential fracture growth, thereby indicating how far the fractures penetrated into the overlying gas-bearing formation (Figure 1). Fracture entry points behind the liner were assessed using the Chorus platform. This also revealed fractures in the target oil-bearing formation that were idle or non-productive owing to the gas breakthrough.   In this well, the completion contained swellable packers, which meant that gas-producing zones could be mechanically shut off. For future wells, the operator has redesigned the fracture programme so that production from the low-permeability oil rim can be maximised while preventing gas breakthroughs caused by out-of-zone fractures. Reducing the fracture pressure was identified as the most effective way to achieve this.

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    Safe and Sound P&A. Decommissioning wells using acoustics

    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.  

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    Keeping Wells Safe, Clean, and Productive from the Inside Out

    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.

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    TGT launches industry first in well integrity diagnostics

    Pulse1 technology for production tubulars delivers five times the accuracy of conventional techniques, with ‘all around’ sensing of tube condition Dubai, 14 July 2020 - TGT announced today the launch of Pulse1, the industry’s first slimhole tube integrity technology that delivers actual wall thickness measurements in eight sectors with ‘all around’ sensing of tube wall condition. This advanced diagnostic capability underpins new answer products and enables operators to assess the condition of production tubulars more accurately than previously possible, helping the industry to ensure safe, clean and productive well operations.   Commenting on the launch, Mohamed Hegazi, TGT’s CEO said, “Proactive inspection and accurate diagnosis of well integrity is fundamental to ensuring safe production, and Pulse1 delivers on that promise for primary tubulars. Conventional measurements like mechanical calipers will still have a role to play, but the addition of Pulse1 diagnostics will address customer needs with greater accuracy. Pulse1 is defining a new benchmark in well integrity diagnostics.”   Pulse1 is the most recent extension to TGT’s Pulse platform: one of five proprietary technology platforms that provide powerful through-barrier diagnostics for the oilfield. Pulse technology powers TGT’s ‘True Integrity’ answer products with a particular emphasis on ‘Tube Integrity’. Pulse1 is designed primarily for ‘production tubing’ and delivers answers that are up to five times more accurate than conventional techniques.   Ken Feather, TGT’s chief marketing officer said, “Pulse1 has been designed to meet the growing industry need for ‘no compromise’ integrity management and overcome the drawbacks of current technologies, particularly mechanical calipers and conventional electromagnetics. This makes it the ideal choice for routine or targeted tube integrity surveillance, especially when accuracy is the top priority.”   “Production tubulars have a special role in keeping wells safe, clean and productive, and they need to perform 24/7 without compromise. Operators use calipers to monitor tube wall thickness, but the error can be 10% or higher. Pulse1 delivers up to 2% accuracy in eight sectors around the tube, providing operators with a higher level of integrity assurance than previously possible”, continued Feather.   Alexey Vdovin, TGT’s head of electromagnetic systems development added, “We have been advancing electromagnetic diagnostic technology for many years and our Pulse platform is favoured by customers globally for its accuracy and reliability in a wide range of multi-barrier completion scenarios. Pulse1 builds on that pedigree to deliver eight-sector wall thickness for primary tubulars, which I believe is an industry-first in a slimhole package.” Pulse1 diagnostics are now available to oilfield operators through TGT’s comprehensive range of ‘True Integrity’ answer products.

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    Unconventional diagnostics for unconventional wells

    New fracture flow diagnostics help operators elevate fracture performance (in the Permian) Article featured in Harts E&P   In recent years, the Permian basin is been the most prolific shale play in the US. Production in this area increased to 3.8 million barrels by 2019, representing almost 70% of the whole US production growth from 2011 to 2019 according to International Energy Agency (IEA). The impressive aspect of this achievement is that the growth has not stopped. On the contrary, the Permian is expected to continue growing and is estimated to achieve up to 5.8 million barrels by the end of 2023.   Such impressive growth doesn’t come easy. Significant advances in drilling, completing and multi-stage fracturing will continue to drive production increases. But evaluating the performance of fracturing programmes and the wells they deliver is key to optimising resources and ensuring maximum return on investment. Conventional diagnostics [such as production logging tools or ‘PLT’s’] can’t provide all the insights required to ensure the operator is achieving the best returns. This article focuses on the challenges faced when assessing unconventional reservoirs in terms of production, and features a new diagnostic capability introduced by TGT to evaluate the flow performance of hydraulically fractured wells, stage-by-stage. The new diagnostic product is aptly called ‘Fracture Flow’.   Operators have been drilling aggressively and pushing the boundaries of hydraulic fracturing beyond conventional standards compared to other plays. The drilled length of lateral sections has been constantly boosted, adding more footage as well as more production stages. The ultimate objective is to penetrate deep into the target formation increasing the area of contact with the specific reservoir or formation making the well, its completion and the reservoir one dynamic production system. Piezo crystals used in the Chorus tools and sensorThrough barrier diagnostics Champions of this approach include a Houston-based operator that recently drilled such a well at the Wolfcamp. The completion included a lateral section of more than 17,900 ft running through the Spaberry formation. The completed well had a total measured depth exceeding 24,500 ft with a customised completion design and fracking treatment. The completion included more than 50-stages and sand was pumped along more than 2,200 ft of reservoir to increase the well productivity.   These extended laterals have been engineered to optimise production performance and leverage improvements in drilling, fracking treatments and completion designs. The operators have overcome the number of well construction challenges and have quickly moved up a steep learning curve.   Like the challenges encountered with well construction, the Permian basin faces its own challenges. Following such an extensive multistage hydraulic fracturing programme, the wells are brought onstream at high initial production rates. But most of these extended-lateral producers tend to decline dramatically over a very short period. To help combat this challenge, and many others, TGT has developed a number of application-specific diagnostic products using its ‘True Flow System’ to quantitively evaluate flow dynamics throughout the entire well system – from reservoir to the wellbore, and the dynamic interplay between the two.   When talking about a hydraulic fracturing job, we all know the importance of the programme design prior to execution. During this phase, sophisticated software is utilised to model and optimise the fracturing programme, taking into consideration multiple variables. These variables include formation properties, lithology, depth, mechanical stresses and other parameters that can affect the final outcome. Another important consideration is the formulation of the hydraulic fracturing fluid. This fluid is normally comprised of sand (or proppant), gels (foam or sleek-water) and additives that are pumped downhole following the job design to prop open the induced fractures and maximise the extension of the fracture in terms of length, height and aperture as well as the integrity of the fractured conduit itself, so hydrocarbons can flow unabated.   TGT’s diagnostic ‘Fracture Flow’ product is able to locate and evaluate fracture inflows and quantify inflow profiles in hydraulically fractured wells. The product is delivered by our analysts using the ‘True Flow System’, which combines several technology platforms – Chorus (acoustic), Cascade (thermal), Indigo (multisense) and Maxim (digital workspace), to acquire, interrogate and analyse the acoustic spectra and temperature changes generated by the hydrocarbons or any other fluid flowing from the reservoir through active fractures and into the completion. This diagnostic capability goes beyond conventional flow measurement techniques that generally stop sensing at the wellbore and are therefore unable to quantify flow within the reservoir itself.   The Fracture Flow product extract shown in figure-1 represents the diagnosis of a hydraulically fractured oil producer with >80 degrees deviation. The reservoir has a gross thickness of approximately 1,200 ft and is fully cased. ‘Fracture Flow’ diagnostics compare fractured intervals [blue] to main producing intervals [green] at different choke sizes in order to evaluate the true effectiveness of hydraulic fracturing programmes and maximise well performance. The operator’s objectives in this case were to evaluate the post-fracture performance of three zones, and in particular: Compare the effectiveness of fractured stages by assessing the production contribution from each fractured interval Identify crossflow or behind-casing communication Increase production efficiency by identifying the optimum production choke for this well system.   The results revealed by the Fracture Flow analysis clearly revealed that the fractured intervals (figure-1 – blue coding) were not contributing fully to production in their entirety. Furthermore, it identified exactly the active zones and where the main production was coming from (figure-1 green coding). Fracture Flow revealed that only 62%, 59% and 56% of each zone was actually producing at the outset.   The Fracture Flow analysis also indicated that there were no crossflows among the three zones which was another key finding from an integrity perspective.   Thirdly, the Fracture Flow diagnostic programme helped to determine the optimal choke size required to ensure that the fractured zones were contributing at maximum rate.   TGT work in close collaboration with operators using Fracture Flow to help them reach their frac evaluation objectives; locate effective fracture inflows; quantify inflow profiles; and assess the effectiveness of fracture programmes, helping to optimise future programmes and maximise return on investment. TGT is an international diagnostics company that specialises in ‘through-barrier diagnostics’ for the oilfield. Our Houston-based operation provides unique ‘True Flow’ and ‘True Integrity’ diagnostics to operators throughout the United States, including the Permian. We are also working actively in deep water Gulf of Mexico, Latin America and other major basins around the globe.

  • True Integrity Tube Products
    Collars Tube Integrity

    Evaluate integrity of casing collars Casing connections are particularly prone to corrosion or damage. This can be due to fluid entry and galvanic forces between the threads accelerating decay or due to thermal expansion causing mechanical stress across the well construction. Regular monitoring is important to maintain integrity.   Collars Tube Integrity provides a collar-by-collar assessment of casing connections from a single through-tubing deployment.   Powered by our True Integrity system using the Pulse (electromagnetic) platform, Collars Tube Integrity delivers clear visibility of collar connection status through multiple barriers.   Collars Tube Integrity, if used routinely, can support your ongoing integrity management programme, or in a targeted fashion to investigate a specific integrity breach.   Our ability to assess up to four concentric tubulars simultaneously means that most of the collars can be evaluated in a single deployment, without pulling the tubing. Challenges Evaluate tube integrity of casing collars Manage integrity of casing collars Routine or targeted surveillance of casing collars Time-lapse barrier condition monitoring Locate potential source of sustained annulus pressure Locate damaged casing connection in thermal projects Benefits Proactive integrity management mitigates risk and maintains safe and productive operations Track and validate tube condition over time and spot collar weakness before it fails Through-tubing deployment minimises disruption and cost Better remediation decisions, precisely targeted Maintain regulatory compliance Resources Product flyers(22) Case studies(36) Product animations(21) Platform flyers(8) System flyers(2) More(183) Hardware specifications(7) Technical papers(128) Intellectual property(48) White papers(0) Resources Related Systems & Platforms True Integrity System Flow isn't workable without integrity. And system integrity depends on the collective integrity of the tubes, seals and barriers that make a well function. LEARN MORE Platforms Pulse Indigo Maxim MediaCollars Tube Integrity gives you the clarity and insight needed to manage well system performance more effectively.Well sketch shows a range of typical collar condition scenarios that Collars Tube Integrity can diagnose.Indicative logplot for Collars Tube Integrity. Clear collar break response is seen on the Pulse responses (FR36). This shows significant deflection at the lower edge of casing collar. Assessed casing thickness, shows negative deflection indicating circumferential metal loss typical for damaged casing collars.

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    Delivering diagnostics for the lifetime of your well

    Article featured in Oilfield technology   Well integrity management is a full lifecycle process adopted from the well design and construction phase right through to abandonment.   Yet, just as well diagnostics should take place at the outset of the well life – with even new completions sometimes containing flaws such as leaking connections and poor cement isolation – there is an increased focus today on routine integrity management, as well systems age and move towards abandonment. Revitalising aging wells In many regions of the world, increasing demands are being placed upon ageing well stock as operators seek to extend field life. Significant remaining reserves are the prize and technology-enabled process innovations, such as drilling multi-lateral extensions from existing wells, allow this to happen.   In the Middle East, for example, more than 70% of the ~800 Middle East platforms and associated well-stock are more than 25 years old, and in the North Sea, according to the UK Oil & Gas Authority, there remain 20 billion barrels of oil and gas resources still to be recovered on the UK Continental Shelf – a region that has been continually developed for nearly 50 years.   In such cases, whilst multi-lateral well components are new, the original wellhead, conductor and production casings have remained the same.   However, whereas previously such well stock survived through regular maintenance of the more accessible elements of the well, today more powerful well integrity diagnostics are required to monitor casing strings, tubulars and other crucial well components throughout the well system – from inside the tubing.   This article will look at how this is being achieved with through-barrier diagnostics. Through-barrier diagnostics Through-barrier diagnostics, a capability developed and perfected by TGT since it was founded two decades ago, is a valuable resource in proactive integrity management today because it evaluates critical aspects of the entire well system from inside the tubing.   Through-barrier diagnostic systems can sense dynamic well behavior and properties throughout the well, helping operators to evaluate the condition and performance of critical well components from inside the tubing.   By cleverly harnessing heat, acoustic and electromagnetic [EM] energy, through-barrier diagnostics can determine the wall thickness of individual tubulars, and locate and quantify fluid movements behind the pipe.   Two key areas where through-barrier diagnostics are having a major impact today are in tracking corrosion and sustained annulus pressure [SAP]. Tackling corrosion in the rise of chrome In some regions, downhole conditions are highly corrosive and well completions are constantly under attack from aggressive fluids, such as hydrogen sulphide, carbon dioxide and chloride. The degradation of wellbore tubulars and metal barriers is a major threat to well integrity.   On the Arabian Peninsula for example, formations such as Rus, Simsima, and Daman can cause severe corrosion of the outer well casing strings. Corrosive fluids from the aquifers can reach the outer casing surface because of integrity breaches in the outer well annulus. This is because either the outer cement sheath has degraded over time, or the initial cementing operation may have been compromised by the inability of formations to support pressure, resulting in cement losses and an imperfect seal.   In such cases, comprehensive and regular inspection is required by operators to determine whether corrosion is taking place at an acceptable rate, or if intervention and remedial action is required. To this end, the well diagnostics approach must provide quantitative information about multiple casing strings efficiently and reliably.   Yet, previously few operators were able to track corrosion to this level of detail and across all pipe strings.   To address this challenge, TGT has developed EmPulse® – a multi-barrier pipe inspection system capable of providing barrier-by-barrier visualisation of the tubulars that make up the well operating envelope, reliably and proactively. Ultra-fast EM-based sensor technology and time-domain measurements, coupled with advanced Maxwell processing, enable the system to quantify metal loss in up to four barriers independently and accurately.   In this way, it delivers sensitive and fast response measurements, bringing with it significant advantages over the frequency-based measurements offered by ordinary pipe inspection systems. Frequency-based measurements are also unable to distinguish the thickness of individual barriers and as a result provide limited information about barrier condition or the precise location of failures.   Another challenge EmPulse is addressing is that of chrome.   In a bid to pre-empt corrosion, many operators are opting for alternative steels and corrosion resistant materials, such as chrome, nickel and molybdenum. However, such materials pose even more challenges to ordinary pipe inspection systems with the decrease in ferrous content causing EM signals to decay too quickly for an effective measurement.   Yet, recent deployments in the Middle East have shown that EmPulse can again quantitatively determine the individual tubular thickness of up to four concentric barriers, even when there are high amounts of chrome in the tubulars.   In one Middle East operator-witnessed ‘yard test’ consisting of a 28% chrome pipe with built-in mechanical defects, the high-speed EM sensor technology within the EmPulse system correctly identified the man-made problems in a controlled environment.   Additional operations took place in two live Middle East wells in a very high hydrogen sulphide gas production scenario with 28% chrome tubulars. In this case, the EmPulse system again functioned as planned, and recorded the status of three concentric well barriers. A multi-finger caliper recording also confirmed the electromagnetic results for the condition of the inner pipe.   As operators endeavor to protect well integrity in challenging production environments and require versatility over tubular materials, it’s good to see that through-barrier diagnostics – backed up by many of the industry’s leading well log analysts – are meeting these challenges and providing a complete end-to-end well diagnostics solutions. Cementing and sustained annulus pressure (SAP) Two other challenges to well integrity today – both interlinked – are that of well cementing and sustained annulus pressure [SAP].   As operators look to deeper and longer reach wells, cementing techniques and sealing abilities have been pushed to the limit. According to the Society of Petroleum Engineers [SPE], at least 25-30% of wells are estimated to have annular pressure problems with cementing being one of the root causes. One outcome of this is SAP – pressure in any well annulus that rebuilds when bled down.   SAP is often the result of weaknesses in the cement during completion; or cement degradation due to thermal and pressure loading; leaking tubing connections or wellhead seals; and corrosion. According to a 2013 SPE webinar on wellbore integrity [Paul Hopmans], out of ~1.8 million wells worldwide, a staggering 35% have SAP.   So how can well cementing and SAP be addressed?   To date, conventional means of tracking poor cementing and SAP is through surface measurements, such as fluid sampling, bleed-off/build-up data and downhole measurements such as ‘cement bond logs’, temperature and ordinary noise logs. This, however, only provides limited information and may be unable to locate leaks and unwanted flowpaths behind multiple barriers – especially when the leak rate is low.   To address this information gap, TGT’s ‘spectral diagnostics’ technology tracks fluid movement behind pipes from within several casing strings. This is achieved using high-fidelity downhole sound analysis systems to capture the frequency and amplitude of acoustic energy generated by liquids or gas moving through integrity breaches and restrictions. Complementing this, spectral diagnostic systems utilise high-precision temperature measurements to help locate integrity breaches throughout the well system.   While conventional production logging measurements typically assess only high-rate first-barrier failures – the high-fidelity recording, sensitivity and clarity of spectral diagnostics enables the tracking of even low-rate leaks at very early stages behind multiple barriers, thereby enabling timely intervention.   In figure 2, a water injector well experienced sustained B-annulus pressure, although the build-up rate did not exceed one bar a day – indicating a low-rate leak. A cement bond survey indicated good cement bonding below X500m, and poor bonding above, likely to provide flowpaths for fluid movement behind casing.   A survey utilising TGT’s spectral diagnostics system was conducted and revealed fluid flow from the reservoir around X540m and channelling up the annulus through the incorrectly assumed ‘good bonding’ area.   The frequency spectrum pattern correlated with reservoir permeability and fluid-type profiles, suggesting gas was being produced from these formations. The operator used the information to target a cement squeeze operation at the desired location in the well – restoring B-annulus integrity and eliminating the SAP. Figure 2 – Information from spectral diagnostics in a water Injector well Spectral diagnostics to abandon wells securely Spectral diagnostics can also play an important role in ensuring that wells are properly sealed during abandonment, especially with respect to unwanted fluid flow along the outer boundaries of the well system to surface – clearly a situation the operator wants to eliminate.   Operators perform through-barrier spectral diagnostics prior to abandonment to indicate the integrity status of the entire well system, and reveal where special remediation measures need to take place to seal the well properly and permanently. Diagnostics are also performed post-abandonment to validate that there is no unwanted fluid flow taking place and that the well is secure.   The well shown in figure 3 was part of an abandonment campaign where the operator observed sustained annulus pressure building at a rate of 0.1 bars per day in the C-annulus and 5 bars per day in the B-annulus. The maximum pressures in B-annulus were 35 bars while in C-annulus it was only 3.2 bars.   Multiple survey and plug/section milling stages were executed to abandon the well and each time through-barrier spectral diagnostics aided in targeting the plug intervals and verifying the integrity of the plug.   After the third stage, the sustained annulus pressure was eliminated in both annuli and spectral data confirmed that the unwanted flow in the outer annuli had been abated. In figure 3, one can see that the acoustic frequency-amplitude spectrum seen at stages 1 and 2 reveal zones of upward gas migration behind casing. The acoustic spectrum seen after stage 3 confirm that the gas migration had been stopped [the small acoustic response is due to residual gas].   As a result, the operator could depart from the well confident that the well was totally secure. Figure 3—Spectral diagnostics were performed during the three stages of abandonment for this well, helping the operator target special remediation measures pre-abandonment and validating integrity post-abandonment. Effective diagnostics throughout the well system Well integrity is all about ensuring that the right fluids connect safely and productively via the wellbore to the surface and don’t stray along unwanted flowpaths inside or outside the well system.   Operators select through-barrier diagnostics to deliver the crucial information they need to ensure well system integrity throughout the well lifecycle. It is these technology innovations supported by the skills and experience of TGT’s experts and others that are leading the way and reshaping well integrity management as we know it.

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    Drilling & Completion

    Total well system integrity and ‘the containment and prevention of the escape of fluids’ (ISO TS 16530-2) remains one of the biggest challenges Middle East operators face today. Article featured in Oil and Gas News   The Middle East has been the world’s most prolific oil-producing region for decades with one of the largest populations of ‘hard-working’ aging wells – many of which operate continuously in extreme environmental conditions. More than 70% of the ~800 Middle East platforms and associated well-stock are more than 25 years old.   Not surprisingly, Middle East operators are facing a constant challenge to manage corrosion and sustained annulus pressure [SAP] in their well systems, and are always on the lookout for new innovations to help. This article will provide examples of two such innovations – corrosion surveillance in chrome-based tubulars, and addressing SAP. Overcoming chrome As Middle East well conditions become more corrosive, so operators have looked to more corrosion resistant materials in the completion process, leading to a rise in chrome and nickel content in steel tubulars. However, one unintended side effect is the decrease in the effectiveness of ordinary electromagnetic [EM] well and pipe inspection systems and the tracking of corrosion in multiple barriers.   The increase in chrome and decrease in ferrous content causes EM signals to decay too quickly for such systems to be truly effective in monitoring corrosion and evaluating pipe thickness or metal loss in casing strings. So while corrosion resistance may have increased, there is now a potential information vacuum.   TGT, the market leader in through-barrier diagnostic systems, has developed a new multi-barrier integrity diagnostics system – EmPulse®. The system quantitatively determines individual wall thickness in up to four concentric tubulars, ensuring long-term well performance in the most challenging high-chromium production environments.   The EmPulse system incorporates ‘ultra-fast’ sensor technology, three independent sensors, and ‘time-domain’ measurement techniques to capture EM signals rapidly and accurately in a wide range of pipe materials before the signals decay.   In three recent Middle East deployments – an operator witnessed ‘yard test’ in 28% chrome pipe with built-in mechanical defects, and two live wells – the EmPulse system correctly identified man-made defects and quantitatively determined the individual tubular thickness.   This successful validation in high-chromium tubulars brings important reassurances for Middle East operators in protecting well system integrity – providing accurate corrosion information and addressing a crucial information gap. The case of sustained annulus pressure (SAP) Figure 2: Spectral diagnostics survey revealing source of SAP behind casing at X540m where the cement map indicates ‘good cement’. Another major challenge to Middle East well system integrity is that of SAP – pressure in any well annulus that rebuilds when bled down.   Reasons for SAP can vary but are often due to weaknesses in the cement during completion; cement degradation due to thermal and pressure loading; leaking tubing connections or wellhead seals; and corrosion. According to a 2013 SPE webinar on wellbore integrity [Paul Hopmans], out of ~1.8 million wells worldwide, a staggering 35% have SAP, with many Middle East fields facing varying levels.   Wells with SAP need to be carefully managed and production can be adversely affected or halted. SAP can also cause further damage to the well system, potentially resulting in the failure of the production casing or outer casing strings, and well blowouts.   While many operators are addressing SAP through new well designs and barriers, and better quality control over cementing – with existing wells they are having to rely on surface data – fluid sampling and bleed-off/build-up data, for example – to investigate the problem downhole.   There is also the challenge of being able to locate leaks and unwanted flowpaths behind multiple barriers, not clearly seen by conventional temperature and ordinary noise logs.   TGT’s spectral diagnostics technology locates leaks and flowpaths throughout the well system by tracking fluid movement behind pipes within several casing strings.   Spectral diagnostics utilise high-fidelity downhole sound recording systems to capture the frequency and amplitude of acoustic energy generated by liquids or gas moving through integrity breaches and restrictions such as cement channels, faulty seals and casing leaks. When coupled with surface data, the information can narrow down the range of remedial options available, and target leak repairs.   Spectral diagnostics include fast, high-precision temperature measurements to locate integrity breaches throughout the well system. High-precision temperature sensors respond more quickly than conventional sensors to the localised thermal changes caused by integrity failures, complementing acoustic measurements by providing a visual confirmation of leaks and flowpaths.   While conventional production logging measurements typically assess only high-rate first-barrier failures – the high-fidelity recording, sensitivity and clarity of spectral diagnostics enables the tracking of even low-rate leaks at very early stages behind multiple barriers, enabling timely intervention and prolonging well life. In the following example [figure 2], a water injector well experienced sustained B-annulus pressure, although the build-up rate did not exceed one bar a day – indicating a low-rate leak.   A cement bond survey indicated good cement bonding below X500m, and poor bonding above. Poor cement bonding is likely to provide flowpaths for fluid movement behind casing. Unfortunately, cement bond log indications of ‘good bonding’ don’t guarantee annulus integrity. Flowpaths can exist that remain unnoticed by the cement bond log.   A survey utilising TGT’s spectral diagnostics system was conducted and revealed fluid flow from the reservoir around X540m and channelling up the annulus through the ‘good bonding’ area.   The frequency spectrum pattern correlated with reservoir permeability and fluid-type profiles, suggesting gas being produced from these formations. The operator used the information to target a cement squeeze operation at the desired location in the well – restoring B-annulus integrity and eliminating the SAP. Evolving challenges, new technologies As Middle East operators continue to face well integrity challenges, gaining a deeper insight into both well and reservoir dynamics is vital. Advanced well diagnostics systems are now available to allow this to be achieved.