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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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    Harts E&P Magazine – Diagnosing flow downhole

    Production logging is an essential resource for managing well and reservoir performance, but traditional methods only see half the picture. In this article, we look at a new approach that looks further to reveal the true flow picture. Article featured in Harts E&P   The last few decades have brought impressive advances in ‘production logging’ technology, especially in the context of new sensor designs and diagnosing complex flow downhole. Fibre optics are also playing an increasing role in production surveillance. However, the fundamental technique of using wellbore-confined production logging tools (PLT’s) to infer total well and reservoir flow performance still dominates the industry.   Basically, PLT measurements are used to monitor fluid properties and flow dynamics in the wellbore and importantly, to determine production and injection ‘flow profiles’ where fluids enter or exit the wellbore, such as via perforations or inflow control devices. These measured and calculated flow profiles are used to assess the production and injection performance of the entire well system.   However, the validity and accuracy of this approach depends on many factors, and chief amongst them is the ‘integrity of communication’ between the wellbore and reservoir formations at the entry/exit points. Analysts and operators using PLT’s must assume that fluids entering or exiting the wellbore are flowing radially from or to the formations directly behind the entry/exit points. And unfortunately, this is often not the case. Flowpaths can exist through annular cement channels, formation packers or natural fissures, and fluid will always find the path of least resistance. From a compliance, environmental and performance perspective, these unwanted flowpaths are bad news. Decisions made assuming wellbore flow correlates directly to target reservoir flow can lead to complex reservoir and field management issues, and compromised asset performance. From a diagnostics perspective, it’s clear that analysts and operators can’t rely on PLT’s alone to diagnose and manage well system performance – a more powerful diagnostic approach is needed. Seeing further The challenge of behind-casing ‘cross-flow’ is not new and the industry has made several attempts over the decades to diagnose this insidious phenomenon. Some of the early techniques used nuclear activation, chemical tracers and noise logging to try to detect and map flow behind pipe, but these methods generally lacked the precision demanded of modern-day diagnostics and were, at best, qualitative. However, fueled by an increased operator focus on compliance, the need for better asset performance, and pure ingenuity, a new diagnostic capability has emerged that is rapidly becoming the new industry standard for diagnosing flow downhole. True Flow system Understanding the dynamics and connectivity of wellbore and reservoir flow downhole with any degree of precision and accuracy is a highly complex task that extends beyond the capabilities of conventional ‘logging’.   Which is why ‘True Flow diagnostics’ utilises a more powerful ‘system-based’ approach. The True Flow system combines experience and expertise with proprietary technology and an industry proven workflow to deliver a more complete picture of well system flow dynamics, and enable better informed well, reservoir and field management decisions (Figure 1). Programmes and methods The first ingredient and stage in the workflow is ‘Programmes & methods’. Following an initial customer consultation, analysis of well performance history, completion design, reservoir and fluid properties and assessment of diagnostic objectives, analysts customise a survey programme that will effectively ‘stress-test’ the well system to expose its flow dynamics in a number of scenarios. This can be likened to a heart specialist exercising a patient on different treadmill settings whilst scanning physiological parameters such as heart-rate, blood pressure and electro-cardio signals. Typical programmes will include a precisely-timed sequence of flowing and non-flowing surveys that allow the entire well system to warm-up and cool-down between surveys. Tools and measurements The second stage and ingredient is the application of high-fidelity ‘Tools & measurements’ by engineers that survey the well according to the diagnostic programme. The measurements come from basic and advanced PLT-type wellbore probes, and a combination of proprietary acoustic and high-precision temperature sensors. Fluids flowing throughout the well system generate acoustic signals encoded with flow information. The acoustic sensing technology used by the True Flow system captures this information in the form of sound pressure across a wide frequency and amplitude range. Importantly, the remarkable dynamic range of this technology means it can sample absolute sound levels from deafeningly loud to imperceptibly quiet without losing clarity or detail. This means that a wide variety of flow scenarios can be located and characterised throughout the well system, from the wellbore to several metres into the reservoir formation. The temperature sensor in itself is unremarkable, being an industry standard fast-response, high-precision type capable of resolving to decimals of degrees. However, correlating temperature changes observed during the diagnostic programme and combining it with the acoustic data, wellbore flow measurements and other well and reservoir information is the key to quantifying flow by the next ingredient of the system – ‘Processing & modeling’. Processing and modeling During the processing and modeling stage, data acquired during the survey programme are enhanced further by analysts using a proprietary digital workspace and a number of processing and modeling ‘plug-ins’. High-resolution acoustic data are transformed into an ‘Acoustic Power Spectrum’ to reveal the characteristic signatures of different types of flow. Analysts can select from a catalogue of digitally enhanced spectra to illuminate particular aspects of the flow and extract maximum information from the acoustic signals.   The subsequent flow modeling is integral to the entire True Flow system and represents another significant advancement in flow diagnostics. Precision temperature measurements acquired during all stages of the diagnostic programme are assimilated together with all other data to derive ‘reservoir flow profiles’. These are distinct from conventional PLT-derived wellbore flow profiles because they quantify flow exiting or entering formation layers whether or not casing or perforations are present. Built on more than a decade of R&E and commercially proven in thousands of wells, the flow modeling engine solves complex thermohydrodynamic physics by matching simulated and measured temperature and other responses in the flow scenarios created during the diagnostic programme. The result is ‘quantified reservoir flow’ that together with wellbore flow measurements complete the total flow picture. Analysis and interpretation The previous True Flow stages are curated under the watchful eye of analysts who also administer the final important stage of the workflow – ‘Analysis & interpretation’. Armed with all available well data, processed and modeled results, and an expert knowledge of true flow applications, the analyst will derive and compile the diagnostic result. Whilst more complex scenarios can take a number of days to complete, the final result is a more comprehensive and accurate diagnostic of reservoir and wellbore flow that ultimately leads to better well management decisions and improved asset performance.   The True Flow system is used to provide a range of diagnostic answer products that address most flow-related applications. These products include ‘Total Flow’, which combines both wellbore and reservoir flow (Figure 2), ‘Sand Flow’ for sand management applications, ‘Fracture Flow’ to optimise fracturing programmes, ‘Stimulate Flow’, ‘Horizontal Flow’, and many more. FIGURE 2. A typical Total Flow answer product derived using the True Flow system is depicted. The PLT-derived wellbore flow profile (left) shows oil and water entering the wellbore at P2 only, suggesting the source of production is from the target reservoir at the same depth. However, the True Flow system reveals that several other formation layers are contributing to this flow, including that the main oil production is coming from the upper and lower sections of the A1 formation, and the water is emanating from deeper layers. By seeing the total flow picture, the operator has a more accurate and complete understanding of well and reservoir behavior and is able to target appropriate remediation. A bright future The old thinking cannot answer today’s new challenges. As well systems become more complex and older, managing performance will remain a priority and continue to task the industry. Wells are built to connect the right fluids to the right places, safely and productively, but forces, materials and age conspire to undermine this perfect balance. Traditional production logging will continue to play an important role in managing production, but it’s clear that we need to look beyond the wellbore, to the reservoir itself, in order to see the true picture.

  • Cascade

    Where heat measurements become flow insights Harnessing thermal energy to quantify flow, from the reservoir to the wellbore.   Fluids moving through the reservoir to the well system have thermal mass and can heat or cool the areas they touch. These temperature changes carry valuable information about fluid behaviour, particularly flow rates and profiles.   The physical laws of thermo-hydrodynamics are incredibly complex, and the interactions between them even more so. The 3D world of metal, concrete and earth that we call the 'well system' adds more complexity. Extracting accurate flow data from this environment can seem like an impossible task.   But not for Cascade.   TGT founded its business on transforming temperature changes into flow information, and since then we have taken this capability further than anyone.   Today, Cascade delivers that capability through our True Flow products to reveal flow like never before. Cascade architectureProgrammes & methodsAnalysts customise proprietary diagnostic programmes in our digital workspace, Maxim, activating well system behaviour to expose targeted thermal and fluid dynamics.Analysts customise proprietary diagnostic programmes in our digital workspace, Maxim, activating well system behaviour to expose targeted thermal and fluid dynamics. Tools & measurementsCascade uses fast response, high resolution temperature sensors from the Indigo platform to deliver accurate answers.Cascade uses fast response, high resolution temperature sensors from the Indigo platform to deliver accurate answers. Processing & modelingPowerful 3D thermo-hydrodynamic modeling code, unique to TGT, reconciles all critical well system elements including reservoirs, completion components and fluid types to produce accurate flow profiles. Automated modeling code rapidly resolves the answer from input data. Parallel processing makes thousands of calculations, accurately solving multiple thermo-hydrodynamic equations.Powerful 3D thermo-hydrodynamic modeling code, unique to TGT, reconciles all critical well system elements including reservoirs, completion components and fluid types to produce accurate flow profiles. Automated modeling code rapidly resolves the answer from input data. Parallel processing makes thousands of calculations, accurately solving multiple thermo-hydrodynamic equations. Analysis & interpretationAnalysts combine Cascade findings with information from Chorus and Indigo to provide accurate flow profiles across the reservoir. Maxim, our digital workspace, provides analysts with a host of Cascade Apps and versatile visual displays to facilitate detailed analysis and confident interpretation.Analysts combine Cascade findings with information from Chorus and Indigo to provide accurate flow profiles across the reservoir. Maxim, our digital workspace, provides analysts with a host of Cascade Apps and versatile visual displays to facilitate detailed analysis and confident interpretation. ProductsOur products offer critical well diagnostics to address the full spectrum of well system flow and integrity challenges.Our products offer critical well diagnostics to address the full spectrum of well system flow and integrity challenges. Our approach We recognise that delivering accurate diagnostics requires not only the highest fidelity measurements, but also a system-based approach. It is important to have the best sensors and measurements, but it also important to use them in the right way and then to filter, process and model the data into tangible answers.   We pursue a diagnostic system approach where multiple platforms come together, bringing their own unique diagnostic capability to be used in the framework of the proven workflow.   Cascade is our thermal platform and, when in the hands of our engineers and analysts, can qualify and quantify any kind of flow event, critically reservoir flow, and reveal the relationship between the two. Pedigree Cascade diagnostic platform has been designed and engineered entirely in-house. More than 10 years of pioneering scientific research, ingenuity and direct field experience in applying thermal flow diagnostics to thousands of well systems globally. Advancing industry knowledge in temperature, hydrodynamics and 3D numerical modeling. Two confirmed patents (and patent pending) for specific data acquisition techniques required for reservoir flow quantification in producers and injectors. Tested and proven in several thousand well systems, servicing more than 70 international operators. More than 70 recognised industry publications. Resources Platform flyers(6) Hardware specifications(5) Case studies(23) Technical papers(85) Intellectual property(48) More(44) Product flyers(19) System flyers(2) White papers(2) Product animations(21) ResourcesMediaOur True diagnostic systems and products extract accurate information from your well and turn it into unique actionable insights so you can manage performance safely, productively and profitably.TGT continues to advance our in-house production of key devices, components and electronic boards.

  • Pulse

    Pioneering electromagnetics delivering highly accurate tube integrity diagnostics The miles of metal tubes that form the backbone of your well system are fundamental to its integrity. Tracking the condition and wall thickness of all tubes is essential to maintain a secure well.   The ‘electromagnetic signature’ of each tube contains information about the wall thickness, but extracting this accurately pushes the boundaries of electromagnetics, 3D modeling, and wellbore measurements to the furthest limits.   That’s exactly what we’ve managed to achieve with Pulse.   Pulse powers our True Integrity Tube products to accurately assess up to four concentric tubes from inside the wellbore. And unlike conventional systems, it works in all completion types, including dual string and corrosion resistant alloys. Pulse architectureProgrammes & methodsPulse is deployed using industry standard diagnostic programmes.Pulse is deployed using industry standard diagnostic programmes. Tools & measurementsUltra-fast sensor technology with rapid relaxation work with patented time domain measurements to deliver supreme accuracy in all completion materials, including specialised alloys with high chrome and/or nickle content. Multi-sensor tool design and proprietary ultra-fast coils optimise energy transfer with each tube, to deliver industry-leading accuracy in multi tube completions. Sensors designed and built in-house, incorporating tuned geometry and ‘fast coil cores’.Ultra-fast sensor technology with rapid relaxation work with patented time domain measurements to deliver supreme accuracy in all completion materials, including specialised alloys with high chrome and/or nickle content. Multi-sensor tool design and proprietary ultra-fast coils optimise energy transfer with each tube, to deliver industry-leading accuracy in multi tube completions. Sensors designed and built in-house, incorporating tuned geometry and ‘fast coil cores’. Processing & modelingOur model solves Maxwell equations which help transform raw data into accurate wall thickness measurements in all well geometries, including dual string completions, so you know your well’s condition from top to bottom.Our model solves Maxwell equations which help transform raw data into accurate wall thickness measurements in all well geometries, including dual string completions, so you know your well’s condition from top to bottom. Analysis & interpretationAnalysts leverage their deep experience in performing tube integrity analysis in thousands of wells globally. Maxim, our digital workspace, provides analysts with a host of Pulse Apps and versatile visual displays to facilitate detailed analysis and confident interpretation.Analysts leverage their deep experience in performing tube integrity analysis in thousands of wells globally. Maxim, our digital workspace, provides analysts with a host of Pulse Apps and versatile visual displays to facilitate detailed analysis and confident interpretation. ProductsOur products offer critical well diagnostics to address the full spectrum of well system flow and integrity challenges.Our products offer critical well diagnostics to address the full spectrum of well system flow and integrity challenges. Our approach We recognise that delivering accurate diagnostics requires not only the highest fidelity measurements, but also a system-based approach. It is important to have the best sensors and measurements, but it also important to use them in the right way and then to filter, process and model the data into tangible answers.   We pursue a diagnostic system approach where multiple platforms come together, bringing their own unique diagnostic capability to be used in the framework of the proven workflow.   Pulse is our electromagnetic platform, providing accurate barrier-by-barrier assessment of up to four concentric tubulars from a single through-tubing deployment.   Pulse platform is part of our True Integrity System and is used to evaluate the metal condition of tubulars throughout the well system. Pulse supports the diagnostic answers for the True Integrity Tube products Pedigree 10 years of pioneering scientific research, ingenuity and direct field experience in applying electromagnetic diagnostics to thousands of well systems globally. Five international patents for electromagnetic technology and methods. Extensive ‘multi-barrier’ research, testing and calibration facilities enable continuous advancement of electromagnetic diagnostics. Experts in high-performance, fast switching electronic circuit design and 3D numerical modeling. Designed and built entirely in-house at our Technology Centre. Resources Platform flyers(6) Hardware specifications(5) Case studies(23) Technical papers(85) Product flyers(19) More(52) System flyers(2) Intellectual property(48) White papers(2) ResourcesMediaWe strive for continuous advancement of electromagnetic diagnostics.Extensive ‘multi-barrier’ research, testing and calibration facilities.

  • Indigo

    Multisense functionality completes the diagnostic picture in real-time Delivering the right information at the right time is fundamental to successful diagnostics. Measurements must be accurate and appropriate for the task, particularly when you want to see more.   Many companies use mass produced, off-the-shelf tools to make and convey well measurements. But not all follow our exacting design standards.   That’s why we make our own.   Indigo is a seamless ‘silent’ platform of wellbore sensors, memory, communication and power modules that have been engineered to synchronise perfectly with TGT’s Chorus, Cascade and Pulse technology. The result is enhanced measurement accuracy and a more complete picture.   Also, Indigo enables memory mode and real-time operation. This capability provides extra flexibility and boosts the efficiency of through-barrier interventions. Indigo architectureProgrammes & methodsReal-time ‘surface read-out’ capability enables programme optimisation and enhanced data quality assurance during diagnostic interventions. ‘Daisy-chain’ deployment is available for enhanced data accuracy and operational efficiency.Real-time ‘surface read-out’ capability enables programme optimisation and enhanced data quality assurance during diagnostic interventions. ‘Daisy-chain’ deployment is available for enhanced data accuracy and operational efficiency. Tools & measurementsComprehensive suite of conventional and proprietary wellbore measurements. Custom designed ‘low noise, low impact’ circuitry and components minimise interference with high-performance acoustic and electromagnetic measurements delivering better accuracy. Patent pending single-bus protocol with ‘common clock’ ensure full measurement synchronisation of multiple sensors and tools for enhanced accuracy. Patented heat exchange measurement (HEX) provides accurate flow measurement in very low flow rates. Real-time data enables improved quality control and faster decisions.Comprehensive suite of conventional and proprietary wellbore measurements. Custom designed ‘low noise, low impact’ circuitry and components minimise interference with high-performance acoustic and electromagnetic measurements delivering better accuracy. Patent pending single-bus protocol with ‘common clock’ ensure full measurement synchronisation of multiple sensors and tools for enhanced accuracy. Patented heat exchange measurement (HEX) provides accurate flow measurement in very low flow rates. Real-time data enables improved quality control and faster decisions. Processing & modelingComprehensive processing of conventional and proprietary wellbore production measurements implemented to the highest industry standards.Comprehensive processing of conventional and proprietary wellbore production measurements implemented to the highest industry standards. Analysis & interpretationComprehensive analysis and interpretation of wellbore measurements complement through-barrier measurements to provide a more complete understanding of well system dynamics. Maxim, our digital workspace, provides analysts with a range of Indigo Apps and versatile visual displays to facilitate detailed analysis and confident interpretation.Comprehensive analysis and interpretation of wellbore measurements complement through-barrier measurements to provide a more complete understanding of well system dynamics. Maxim, our digital workspace, provides analysts with a range of Indigo Apps and versatile visual displays to facilitate detailed analysis and confident interpretation. ProductsOur products offer critical well diagnostics to address the full spectrum of well system flow and integrity challenges.Our products offer critical well diagnostics to address the full spectrum of well system flow and integrity challenges. Our approach We recognise that delivering accurate diagnostics requires not only the highest fidelity measurements, but also a system-based approach. It is important to have the best sensors and measurements, but it also important to use them in the right way and then to filter, process and model the data into tangible answers.   We pursue a diagnostic system approach where multiple platforms come together, bringing their own unique diagnostic capability to be used in the framework of the proven workflow.   Indigo is our multi-sense platform, which provides complimentary measurements required to deliver diagnostics for True Flow and True Integrity products. True Flow System focuses on locating and quantifying flow and the True Integrity System is used to evaluate the condition of tubulars and validate sealing performance. Pedigree 10 years of engineering ingenuity and direct field experience in applying wellbore measurements to thousands of well systems globally. Patented measurement capability. Experts in high-performance, low-noise electronic circuit design. Designed and built entirely in-house at our Technology Centre. Tested and proven in thousands of well systems for more than 70 international operators. MediaPatented measurement capabilityComprehensive analysis and interpretation of wellbore measurements complement through-barrier measurements

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    20th Anniversary

    Kazan, Russia, 2018: TGT Oilfield Services, the market leader in through-barrier diagnostic systems, celebrated 20-years of Research and Development and technological advancements.   Mohamed Hegazi, Chief Executive Officer, said: “We are delighted to have reached this milestone, especially in an increasingly competitive market place and at a challenging time in our industry. We enjoyed our celebration with valued employees, partners, and customers from around the world. This achievement is a testament to the uniqueness and strength of TGT ‘s technologies, Geoscience expertise and best in class service delivery”.   “The past 20-years have been an incredibly exciting time for us. We have continuously outpaced the market growth, expanded our geographical footprint and continue to be actively engaged in industry forums and publications. TGT uniquely designs, develops, manufactures and patents its own hardware and software”.   TGT has grown from a small office with a handful of employees, to a company with 12 offices globally, operating in more than 20 countries for more than 40 customers. Mohamed Hegazi, CEO, TGTBringing global colleagues together to celebrateArthur Aslanyan, Founder, TGTTraditional Russian dance To celebrate, TGT invited employees, customers, and business partners to an evening which relived the company’s scientific breakthroughs using acoustic, thermal and electromagnetic energy to reveal unique answers within and beyond the well bore.   Dr. Arthur Aslanyan, TGT’s Co-Founder commented, “It gave me great pride to attend the event and celebrate the company's 20th anniversary. We have come a long way since we first started the business. We are very excited about our future as the company continues to thrive”.   The event was attended by Saad Bargach, TGT Chairman and LimeRock Partners -private equity investors.   Hegazi continued, “Looking to our future, TGT is releasing several lines of new technologies and applications in coming months to further cement our position as pioneers of Through-Barrier Diagnostics. Our patent technology developments coupled with our unrivalled Geoscience organisation and global footprint, provide unique and reliable diagnostic services to our customers. This has been key in maintaining our fast growth trend and industry reputation. I am confident this foundation along with our excellent teams, will continue to fuel our growth for many years to come.

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    Real Time Indigo Platform

    New ‘real-time’ technology expands convenience, flexibility and fidelity of powerful well system diagnostics for oilfield customers TGT announced today the release of its real-time Indigo platform, significantly expanding the range of benefits brought by its family of powerful through-barrier diagnostic systems. The new real-time technology enables well data to be viewed and analysed at surface during the execution of well diagnostic programmes without compromising on measurement fidelity. This will bring several benefits to customers, including improved data quality, enhanced intervention efficiency and faster remediation decisions.   Ken Feather, TGT’s Chief Marketing Officer commented, “Real-time data isn’t new to the oil industry, but currently available transmission systems couldn’t meet our exacting data quality standards—so we developed and built our own high-fidelity system. In doing that we have taken conveyance and decision-making flexibility to an entirely new level for our customers, with no compromise on measurement quality. As a result, we expect the popularity of our diagnostic systems and products to expand even further.”   TGT creates all its own hardware and software in-house and follows a strict philosophy of ‘fidelity’ in the design and manufacturing of its diagnostic sensor technology and instruments. This philosophy is clearly embodied in its ‘Indigo’ platform of complementary sensors and auxiliary equipment. Indigo technology is distinctly ‘low noise’ and custom-built to operate perfectly with TGT’s through-barrier suite. The new real-time capability is particularly relevant to TGT’s acoustic-based ‘spectral’ and electromagnetic-based ‘EmPulse’ diagnostic systems, which lead the industry in diagnosing flow and integrity dynamics within oil and gas wells, helping operators to improve well performance.   Traditionally, through-barrier diagnostics are performed using ‘memory-mode’ deployment. With a track record of 20-years and an efficiency of more than 99%, TGT’s memory-mode deployment remains a flexible and popular choice across the industry. With this approach, diagnostic information is accessed when the measuring instrument is retrieved from the well. However, with real-time access, data can be viewed during the diagnostic intervention and streamed remotely from the wellsite enabling a host of benefits, such as dynamically adjusting the acquisition program, and making faster decisions.   Artem Buharaev, TGT’s head of Indigo development also commented, “We have overcome many technical challenges in commercialising our real-time Indigo platform. Existing data transmission technology available within our industry generates unacceptable levels of acoustic and electromagnetic [EM] ‘noise’, that would otherwise degrade our highly-sensitive sound-based and EM-based measurements, so we developed our own design that was both ‘quiet’ and fast.”   The real-time system comprises of a downhole Indigo modem module and a surface interface unit that enables two-way communication between surface recording equipment and the downhole instruments. Testing Indigo's 'high fidelity' platformReal-time Indigo platform structure Indigo is a fully integrated ‘high-fidelity’ platform of wellbore production sensors, communication, navigation, memory and power supply modules that are designed to work seamlessly with TGT’s flagship through-barrier diagnostic systems. Engineered and built completely in-house, all Indigo modules have been designed to eliminate the possibility of interference with TGT’s high-performance acoustic and electromagnetic sensors. Conventional industry wellbore instruments contain components and circuitry that generate rogue acoustic and electromagnetic [EM] noise that can interfere with measurements, effectively compromising the data analysis. Our customers rely on the fidelity of our diagnostic insights, so it’s important that our measurements only capture true well system behaviour, which is why we developed Indigo.   Indigo enables both memory-mode and real-time data acquisition from production sensors housed in titanium. Measurements include high-precision temperature, pressure, gamma ray, casing collar locator, fluid capacitance, fluid resistivity and heat-exchange. Fullbore and continuous flow spinner modules are added to provide complete wellbore flow diagnostics.

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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.

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    TGT News – Drilling & Completion (Feb 2018)

    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. 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. To celebrate, TGT invited employees, customers, and business partners to an evening which relived the company’s scientific breakthroughs using acoustic, thermal and electromagnetic energy to reveal unique answers within and beyond the well bore.   Dr. Arthur Aslanyan, TGT’s Co-Founder commented, “It gave me great pride to attend the event and celebrate the company's 20th anniversary. We have come a long way since we first started the business. We are very excited about our future as the company continues to thrive”.   The event was attended by Saad Bargach, TGT Chairman and LimeRock Partners -private equity investors.   Hegazi continued, “Looking to our future, TGT is releasing several lines of new technologies and applications in coming months to further cement our position as pioneers of Through-Barrier Diagnostics. Our patent technology developments coupled with our unrivalled Geoscience organisation and global footprint, provide unique and reliable diagnostic services to our customers. This has been key in maintaining our fast growth trend and industry reputation. I am confident this foundation along with our excellent teams, will continue to fuel our growth for many years to come. 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.