Challenge A high gas–oil ratio leads to unnecessarily high carbon emissions, lower oil production and increased carbon-per-barrel rates. Managing and processing excess gas requires substantial energy and capital expenditure for surface infrastructure and facilities. In this case, the aim was to identify zones for gas shut-off that would enable the operator to optimise surface infrastructure capacity, maximise oil production and minimise carbon footprint.   Well A-1 features a 7 in. x 4-1/2 in. cemented liner across several commingled oil and gas-bearing zones. Developing compartmentalised multi-stacked reservoirs using simplified well completions makes it challenging for diagnostics to determine production allocation, reveal flow assurance issues, understand reservoir connectivity, monitor individual well performance, and forecast total field production.   Gas production had already exceeded the limit of surface processing facilities for well operation with existing production rates, which meant the operator had to choke back production. In addition, the unwanted gas was taking up part of the operator’s pipeline quota and creating other transportation and flow assurance issues. The well contains at least five clastic reservoir zones, each with multiple layers, that are perforated across an interval of more than 1,500 ft. This level of complexity meant that conventional production logging tools were unable to adequately characterise flow or confidently distinguish the main gas-contributing layers. Total Flow example well sketch. Total Flow locates and quantifies wellbore and reservoir flow, and reveals the relationship between the two. Delivered by our True Flow system with Chorus and Cascade technology, Total Flow provides the clarity and insight needed to manage well system performance more effectively. Total Flow is commonly used to diagnose unexpected or undesirable well system behavior, but it can also be used proactively to ensure the well system is working properly. Solution The operator selected TGT’s Total Flow product, with Cascade, Chorus and Indigo as the main technology platforms chosen to perform the well system diagnostic survey. This would reveal which zones were contributing to the production of oil and gas, diagnose wellbore and reservoir flows, and help identify potential well integrity issues such as annulus sealing problems due to poor cement. The solution combines the sensitive, fast-response temperature sensor of the Indigo platform with high-definition acoustic sensing from Chorus that reveals active flow in the well system.   Comprehensive temperature and flow modelling with Cascade enabled TGT analysts to assess and allocate production distribution and provide accurate oil and gas flow profiles across the reservoir zones. The survey also identified active flow layers and recorded characteristic acoustic signals generated by liquid and gas flowing through reservoir media and the wellbore. Pre- and post-workover survey results illustrate the effectiveness of the gas zone isolation programme and resulting decrease of gas production, which enabled surface infrastructure to stay within its operating envelope. Result Total Flow diagnostics quantified the contribution of reservoir layers from five different zones and identified the main gas producing layers, providing a comprehensive flow profile. The operator was able to define active flow units and differentiate between flows through the reservoir matrix, the behind-casing channels and the wellbore completion components.   This enabled the operator to target and conduct an effective remediation plan. The workover involved a 200-ft-long 2-⅞- in. straddle installed to isolate the zone with the highest gas contribution. A post-workover Total Flow survey was conducted to evaluate the effectiveness of the isolation job. The straddle had isolated 83% of the gas production. This delivered a reduction of 7.9 MMscf per day at surface (equivalent to 2.8 Bscf per year).   Overall, the isolation job was considered highly successful. Identifying the main gas shut-off zones played a crucial role in optimising surface infrastructure, maximising oil production, and minimising carbon footprint for this well.

Challenge Primary barriers are key for protecting the integrity of a well system. When failures occur in these barriers, they must be diagnosed quickly to avoid unsafe operation, lost production and the risk of escalation. Leaks in wellbore tubulars can lead to unwanted fluid communication between reservoirs that can result in substantial production losses for oil and gas operators.   The subject well in this study is a naturally flowing oil producer that was producing from the top reservoir through the short string while the bottom reservoir, producing from the long string, had watered out and ceased to flow. A sudden increase in water cut at surface prompted the operator to investigate. Primary Seal Integrity is used in a targeted fashion to pinpoint suspected integrity failures in the tubing or other primary barrier components, or proactively for regulatory validation. Solution TGT’s Primary Seal Integrity product locates leaks and evaluates seal performance without needing a workover rig. This rigless approach to seal diagnostics enables operators to optimise workover programmes and can deliver significant cost savings. This is particularly true if the diagnostics reveal that any remedial work can be conducted riglessly, thus avoiding the costs of workover rig mobilisation.   Delivered using TGT’s True Integrity system with Chorus technology, Primary Seal Integrity identifies leaks and unwanted flow paths, guides corrective actions and can be used to validate the effectiveness of remedial work. Primary Seal Integrity combines temperature profile analysis and advanced acoustic analysis to diagnose problems. It is typically used in a targeted fashion to pinpoint a suspected breach in tubing or other primary barrier components within the well. Both temperature and Chorus data indicate water inflow from the bottom reservoir and flow up through the casing and tubing to the leakage zone. This fluid then enters the annulus where it mixes with fluids from the upper reservoir and flows to surface. Result The Primary Seal Integrity survey pinpointed the leaking element in the completion: a tubing collar of the blast joint in the long string (Figure 1). The leak was enabling water produced from the bottom reservoir to flow into the short string production of the upper reservoir, thereby causing the sudden increase in water cut at surface. A plug was set, riglessly, in the landing nipple of the long string to block the water route from the lower reservoir. After plug setting, a surface production test revealed a sharp drop in the water cut that indicated the success of the remedial operation. The TGT solution saved several days of rig resources and helped to reduce the carbon footprint of the remediation operation.

“The better we get at getting better, the faster we will get better.”                                                                                                    Douglas Engelbart Article featured in Harts E&P Magazine   Over the past 60 years, a couple of trends and specific events contributed to drastically changing the way we live and work today. The reasons why we even entertain a conversation about digital transformation takes its roots from these few trends and events.   The future is exponential In the 1980’s we had the first laptops. In the 1990’s the Internet was becoming global and gaining in popularity. In the 2000’s high speed internet is introduced and humanity is moving data at the speed of light for the first time ever (we think). Literally. In the 2010’s cloud computing, ‘Infrastructure as a Service’ (IaaS), and ‘Software as a Service’ (SaaS) were becoming a standard, and storage virtually limitless.   Memory storage has become extremely cheap and storage devices are getting increasingly smaller in size and bigger in capacity. Computing power available on an average laptop is increasingly getting bigger. And quantum computing is just around the corner.   The increasing speed at which these consecutive transformations have taken place have forced our culture to adapt. Everything is needed now, sometimes yesterday, because tomorrow is going to be too late. The foreign exchange and stock exchange markets, leaders of the world economies, are fully relying on Artificial Intelligence (AI) for trading. And this is what is driving business transformations and change in organisations. Adapting to market change, and increasingly predicting change in order to know how to proactively adapt. The future is digital The future of oil and gas producers and service companies will depend on how fast they adapt to the constantly evolving energy landscape. Recent years have demonstrated how difficult it is for non-digitalised companies to cope with the ever-changing market conditions, and how increasingly difficult it has become for the oil and gas industry to recover from each successive economic crisis.   Our industry is far behind in digitalisation. Only 5% of data generates value, 3% of equipment is connected, 1% of data supports decision making. Clearly, the industry has a long way to go in leveraging this new digital reality.   This is why it is now vital for us as an industry to embrace digitalisation as a positive disruption to traditional data processing workflows, understand the opportunity and potential behind AI and its many applications, and ensure we are transforming our industry to become smarter, leaner, and most importantly, sustainable.   Doing so will take a lot of adapting, and adopting new digitally enabled ways of working. Oil and gas companies will need to revamp their data ecosystem, data architecture and create data platforms fit for AI processing. They will equally need to develop internal talent to ensure their resilience and long term sustainable transformation. It will also require program management discipline, change management culture, both short and long term projects, and a very good understanding by the decision makers of the risks of ignoring the digital disruption. Furthermore, decision makers need to action these steps fast because the world is changing around us faster than ever.   This decade is the decade of ever more change. We are going through the COVID-19 pandemic imposed changes. The acceleration in adopting digital tools to accommodate remote ways of working is phenomenal and only illustrates the point that organisations that are digital, fit and lean will make it through the crisis and emerge even stronger. The future is exponential. The future is digital Our vision at TGT is to pioneer and lead the advancement of Predictive Diagnostics in the energy sector, positively impacting long term sustainability and ESG initiatives. TGT is developing multiple AI-enabled products that will fulfil the growing sector demand for predictive analytics and diagnostics, leading the industry to a digital future. “Societies are driven by technology, but defined by humanity.”                                                                                                                       Gert Leonhard

Dubai, UAE - 28 June 2021 TGT Diagnostics, leaders in through-barrier diagnostics for the oilfield, today announced the appointment of Andre Sayeh as Chief Financial Officer. In this role, he will be responsible for managing all aspects of TGT’s finance, compliance and legal functions.   Andre will focus on maintaining the high standard of financial rigor for which TGT is well known, as well as continuously improving business processes to support our expanding geographical footprint.   TGT CEO, Mohamed Hegazi commented, “Andre brings extensive knowledge of the finance function and an impressive depth of experience spanning strategic global roles in one of the industry’s most respected brands. I’m delighted that Andre has joined our executive team at a time when there are so many positive dynamics around us, including a fast-paced digital transformation, a post-pandemic recovery, and a growing ESG momentum.”   Andre joins TGT Diagnostics with more than 30-years’ experience with the oilfield services firm Schlumberger. His prior roles include Global IT Vendor Management, Business Systems Special Projects and Global ERP Portfolio Manager, as well as numerous Financial Controller and Tax Manager roles for multiple businesses.   Andre holds a Bachelor’s Degree in Banking and Corporate Finance, and a minor degree in Marketing from Kuwait University. In addition to driving many financial achievements, Andre has led several global contract negotiations and ‘ERP Business System’ consolidation projects relating to company acquisitions. Andre also led the design and implementation of a new ‘ERP Business Demand Portal’ for the finance function, the concept and architecture of which was adopted by other corporate functions across the organisation.   “TGT is the category leader in oilfield diagnostics with an impressive reputation in the industry; I look forward to helping the company achieve its full growth potential and utilising my skills and experience to bring process automation to the next level.” Commented Andre. “I feel privileged to be part of TGT team, as it brings unique diagnostic products that sets it apart from other brands, and I see a tremendous opportunity for the company to play a crucial role in helping the oil and gas sector deliver a sustainable future.”

Dubai, UAE - 15 June 2021 TGT Diagnostics, leaders in through-barrier diagnostics for the oilfeld, today announced the appointment of Rizkallah Ward, as Chief Digital Officer. In this new role, he will be responsible for managing all aspects of TGT’s digital transformation.   Rizkallah will focus on expanding our capabilities in the arena of predictive diagnostics, as well as enhancing our AI data platforms and analytics, and transforming our internal systems and diagnostic workflows through digitalisation.   “TGT Diagnostics is continually advancing data intensive workflows, and evolving them to solve multiple diagnostic challenges with precision and accuracy as a priority. All industries are embracing digitalisation as a positive disruption to traditional data workflows. We intend to lead the industry in leveraging digitalisation, taking well diagnostics to a completely new level,” said Mohamed Hegazi, CEO of TGT. “Oil and gas extraction is a data-rich environment where data can be used more effectively to support operators by predicting flow and integrity challenges. I am delighted to have Rizkallah’s expertise in the executive team to spearhead our digital strategy.”   Rizkallah is a recognised leader in AI and digital transformation. He joins TGT with more than 30-years’ experience in technology and digital solutions, and has worked in a wide range of sectors including, telecommunications, military, government, utilities as well as in oil and gas. One of his most recent achievements included presenting how digitalisation is changing the oil and gas industry, at the Vienna OPEC conference.   “The company’s ambition to reshape the oil and gas industry with through-barrier diagnostics, its history, international footprint, culture and its people, are why I’m delighted to join TGT and lead its digital transformation”, commented Rizkallah. “The future of energy companies will depend on how fast they adapt to the constantly evolving energy landscape. TGT will develop multiple AI-enabled products that will feed the growing demand for predictive analytics and diagnostics. The future is exponential. The future is digital.”

Collaboration combats sand control failures Article featured in Harts E&P Magazine   In mature basins, sand issues can account for up to 10% of all shut-in wells either due to failure of the existing downhole sand control or onset of sand production due to pressure depletion and/or water production.   There are many reasons for sand or fine material entering and accumulating in the wellbore, and depending on the level of severity, the consequences need not be detrimental. However, the accumulation of sand production downhole or in surface equipment can lead to production being killed, wells shut-in, or collapse of the formation.   As an inherent problem in the oil and gas industry, the first indication of sand issues downhole will often be as a result of detrimental effects that can occur at surface, such as fill in separators or erosional damage to pipe work.   As existing solutions have been extremely limited due to their high cost and/or poor performance, together, independent global completions service company Tendeka and diagnostic specialists TGT have created Sandbar to mitigate the costly consequences of sand control failure in wells. Downhole monitoring and remediation The conventional process of thru-tubing sand control can be costly and time consuming. In many cases there is a requirement to remove sand from the wellbore prior to installing the chosen sand control solution. Once installed many traditional remediation techniques still allow the wellbore to refill with formation sand reducing productivity and increasing susceptibility to erosional failure.   Therefore, the major challenge is to regain sand control in existing completions and prevent sand from filling the wellbore, without the requirement to perform a workover or complex thru-tubing gravel packs.   Proper diagnosis is the critical first step to any kind of well remediation planning and execution. But determining the precise location and extent of sand ingress downhole has challenged the industry for decades, as previous attempts were unable to reliably distinguish between sand and fluid flow.   The challenge of locating and effectively mitigating sand production has now been addressed by combining the features of two products, one to accurately identify the locations of sand ingress within the wellbore, and the other to quickly repair the damage. The conventional process of thru-tubing sand control can be costly and time consuming. In many cases there is a requirement to remove sand from the wellbore prior to installing the chosen sand control solution. Once installed many traditional remediation techniques still allow the wellbore to refill with formation sand reducing productivity and increasing susceptibility to erosional failure.   Therefore, the major challenge is to regain sand control in existing completions and prevent sand from filling the wellbore, without the requirement to perform a workover or complex thru-tubing gravel packs.   Proper diagnosis is the critical first step to any kind of well remediation planning and execution. But determining the precise location and extent of sand ingress downhole has challenged the industry for decades, as previous attempts were unable to reliably distinguish between sand and fluid flow.   The challenge of locating and effectively mitigating sand production has now been addressed by combining the features of two products, one to accurately identify the locations of sand ingress within the wellbore, and the other to quickly repair the damage. Accurately eliminating sand issues Managing and curtailing sand production issues is essential to maintain asset integrity and extend the life of the asset. Tendeka and TGT have joined forces to create the more effective, intervention-based solution, ‘Find Fix Confirm’ sand remediation service, which is believed to be the first specialized, integrated approach to fully understand and fix sand production issues.   First, the ‘Find’ element of the solution, whereby TGT’s ‘Sand Flow’ diagnostics precisely locates sand entry to the wellbore and provides a qualitative sand count, clearly identifying problem zones, even in turbulent flow conditions (Figure 1). Figure 1: TGT’s Anechoic Chamber completely absorbs reflections of sound and electromagnetic waves, enhancing the company’s acoustic diagnostic capabilities Although commonly used to diagnose a known sand production issue, Sand Flow is also used proactively to ensure downhole sand control measures are working correctly. This can include targeting unconsolidated formation that requires regular intervention, sand screen failure, and surface equipment failure.   Sand Flow diagnostics are delivered using TGT’s ‘True Flow’ system and ‘Chorus’ acoustic sensing platform. Fluids travelling through the well system produce a rich spectrum of acoustic energy, and Chorus captures and decodes the acoustic signature generated by sand particles entering the wellbore. Deployed in hole on wireline, Chorus reveals sand ingress locations and sand count by analysing the acoustic power spectrum of acquired data, and discriminating between sand flow and fluid flow. By flowing from the reservoir whilst the tool is in the well, the acoustic signature of any sand within the production stream can be characterized such that the sand entry points and sand rate can be identified. Chorus leverages high-fidelity recording across a wide dynamic range and proprietary sand-recognition analysis to deliver robust sand detection in a broad range of sand flow scenarios.   To ‘Fix’ or regain sand control in existing completions and prevent sand from filling the wellbore, Tendeka’s one-trip, thru-tubing sand control system ‘Filtrex’, is deployed via coiled tubing into the well and positioned across the target area to quickly repair the breach or damage (Figure 2).   Figure 2: Sand clean out and screen installation by Filtrex is performed across three key stages As a retrievable thru-tubing system, the flexible, open cell matrix polymer filter can be easily installed by conventional means in a live well, this includes thru-tubing, and through tight nipple restrictions.   When self-centralized, it can expand in deviations up to 90˚ and is understood to be the only product of its kind that can be run through larger casing/liner configurations, for example, a 3.688-in. nipple and set in a 7-in. liner. It can be deployed in-hole compressed within the running tool and compression sleeve. This offers full compliance to the damaged section once set. By dropping a ball from surface, a simple two-stage application of pressure firstly sets the anchor, and secondly releases the compression sleeve.   Upon removal of the sleeve, the matrix polymer expands to contact the wellbore and the deployment string can be retrieved from the well. Filling the annular gap with the open cell matrix polymer prevents further ingress of formation solids into the wellbore whilst still allowing passage of liquids or gases. The multilayer system ensures full expansion in the damaged screen section or casing and effective flow divergence regaining sand control in existing completions (Figure 3).     Figure 3: Filtrex expanding out of compression sleeve The first of its kind, the device can perform sand clean out and chemical treatments during live well deployment, thereby preventing multiple intervention trips. When deployed on coiled tubing the installation of the system has the potential to significantly improve the financial feasibility of restoring production to failed wells. As it negates the need for a workover or complex thru-tubing gravel packs, the remedial system can also cut intervention timings and associated run changes by at least half.   The length can be modified to suit the application and lubricator length restriction. If longer lengths are required these can be stacked on top the previous screen section. The system design allows the combination of many distinct layers with a range of cell sizes. This ensures the design has the flexibility to size the screening for each application to ensure appropriate retention of sand in reservoirs up to 110°C (230°F).   Finally and crucially, the service can ‘Confirm’ the effectiveness of the solution with the redeployment of TGT’s Sand Flow diagnostics through the internal diameter of the Filtrex system to confirm that no sand is entering at that depth. This enables better use of resources and more reliable sand control outcomes.   Innovation through partnership As a single approach, existing remedial methodologies to address sand management, such as running an insert sand screen, applying consolidation treatment or performing a remedial gravel pack, are disjointed, lack insight on the precise location of the problem, and often fail to fully eliminate the problem. Likewise, their use can vary in complexity, cost, risk, longevity and effectiveness. Associated weaknesses can often result in reduced production or in extreme cases, loss of surface containment due to erosion.   Bringing together two technologies in one service offering will ensure fast, accurate and tailored remediation to a variety of sand control issues at a fraction of the time, cost and risk of conventional solutions to this age-old problem. Being compatible with thru-tubing operations, including live well deployment and single trip sand clean out, provides greater flexibility and assurance.   Ultimately, it will empower operators to better understand the true sources of sand production and its behaviour and ensure reservoir management decisions are precisely targeted for improved integrity and enhanced asset life.

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.

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.