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Our first two series of #TechTalks were a resounding success and we've been asked to run more! Hence, we are delighted to launch our 3rd series of #TechTalks. Once again the topics are diverse and reveal a range of powerful well system diagnostics that would help you to maintain safe, clean and productive well operation. #TechTalk No. 7 Diagnosing flow and integrity challenges in dual completions Managing the performance of dual completion wells is challenging. Limited access to the short-string reservoir and complex geometry conspire to hide flow and integrity issues from traditional diagnostic techniques, undermining the success of well management decisions. In today’s climate, ambiguity is no longer an option. Discover how TGT’s ‘Dual String Flow’ and ‘Dual String Integrity’ products enable a more complete understanding of flow and integrity dynamics in dual completions, improve decision making, and help keep wells safe, clean and productive. Presented by: Vasily Skutin, Principal Domain Champion, TGT REGISTER NOW #TechTalk No. 8 Diagnosing flow challenges in horizontal wells with smart completions Horizontal wells are notoriously challenging to diagnose correctly. Complex flow geometry and equally complex completions can task even the most sophisticated wellbore diagnostic techniques. Join us to see how our ‘True Flow’ system senses beyond the confines of the wellbore to reveal a more complete understanding of flow dynamics in horizontal wells, even in the most complex scenarios. Presented by: Vener Nagimov, Principal Domain Champion, TGT REGISTER NOW #TechTalk No. 9 Diagnosing conventional/alternative well barriers to enable rigless abandonment The P&A purpose is clear; for the plugged well to maintain its abandonment integrity until the natural pressures within the borehole and formation return. Two techniques are rising in popularity. One is rig less abandonment and the other is replacing the use of cement as a permanent barrier to an alternative such as Bismuth or shale. In this #TechTalk, we discuss furthering the use of through-barrier diagnostics until the final stage of P&A—when only the tubing/casing remains. Our new patented approach can be used in the pre-abandonment phase and evaluates the isolation of cement/alternative materials behind the first and second casing. This prior knowledge enables the pre-selection of candidates for rigless abandonment, thus leading to a reduction in cost, resource and carbon emissions. Presented by: Maxim Volkov, Principal Domain Champion, TGT REGISTER NOW If you have any questions, please don’t hesitate to email us. Or, if you have a suggestion for a #TechTalk you would like us present, please email: firstname.lastname@example.org.
Exert from Harts E&P's showcase on the latest hydraulic fracturing technologies and how they aim to address operator challenges. Diagnostics locate flow before or after fracturing TGT’s Fracture Flow evaluates the effectiveness of a fracturing program. It uses the Chorus acoustic platform to record and analyze the acoustic wave propagation in the wellbore and rocks, plus well design information, to determine the location of the acoustic source energy produced by fluid flow in the fractures. When used during pre- and post-fracturing, it can analyze the reservoir flow profiles, qualify flow to or from the fracture network, reveal fracture density and identify unwanted fracture components that impact product. The technique can identify the location and determine the distance of the acoustic signal from the receiver. Combined, these insights offer operators the diagnostics they need to improve their fracturing program, so it can be targeted and optimized to deliver maximum time and cost efficiencies. The logplot shows a horizontal tight sand gas condensate producer, completed with a non-cemented multistage ball-activated application. Stage separation was achieved by a dual hydraulic-activated packer. The results identified the presence of 22 active fractures, 17 were offset from flow ports and five could be aligned with the flow ports producing a unique signature covering a wide frequency range. The fracture distribution varied between stages with an average of three active fractures per stage.
Integrity and corrosion assessment for successful slot recovery and plugging & abandonment (P&A) applications Article featured in Oilfield Technology For all plug and abandonment applications, either permanent or for slot recovery, the sealing performance of well system components needs to be assured, and remain intact. Well systems are complex and need to work perfectly to perform safely, cleanly, and productively. Understanding the condition and sealing performance of well system barriers can be challenging once the well has been brought onstream and access to these elements and components is restricted. Current mainstream technologies only provide partial answers, leading to an incomplete assessment. However, through-barrier diagnostics look at the well system in a far more holistic and uncompromising way. These technologies have the capability of seeing through multiple barriers to provide a more complete picture of the condition of the metal tubulars and the flow around them to see if the seals are holding, prior to plug and abandonment. In the case of permanent abandonment, natural barriers that prevent the movement or migration of downhole fluids, must be restored. And the performance of the well system barriers must remain intact indefinitely. In the case of slot recovery, the well components must be in good enough condition to be used again for the upcoming production cycle. A comprehensive integrity assessment is required for either scenario. Optimising P&A operations Planning and executing a flawless plug and abandonment requires prior knowledge of the integrity of the well barriers, and the precise position of all downhole completion elements. Operators armed with this information can determine the location of the permanent plugs and the best depths for the casing cuts for an optimised retrieval procedure. During the productive life of a well it may experience several operator changes, perhaps after concessions expire or following divestment decisions. This can often lead to historical data being lost which, when it comes to well decommissioning, can increase the potential for making decisions without knowing all the facts about the well system, particularly the position of the casing collars, fins, centralisers or other components that impede successful decommissioning. Using a simple multifinger caliper or an ultrasound survey, the location of the first-barrier casing collars can be determined, but the locations of the collars in the subsequent casing strings remain unknown. This approach contains an element of risk and may result in a cut planned directly in line with a thick section of metal, like a casing collar, or fin. Cutting across a collar or a fin, would mean an increase in the rig and intervention time of several hours, or potentially days. TGT’s Multi Tube Integrity product uses the Pulse electromagnetic sensing platform to provide accurate barrier-by barrier assessment of up to four concentric tubulars (up to 20” diameter) in one single through-tubing deployment. Pulse can also pinpoint to within 1ft the location of completion elements. The ‘electromagnetic signature’ of each tube or metal completion component, contains information about its wall thickness. The Pulse platform harnesses this information and through 3D modeling, can decipher metal loss as well as metal gain, in multiple casing strings throughout the entire well system. Pulse can identify the location of known completion elements, but also identify new ones, not expected including welded fins on the outer casing string, often inaccessible to other evaluation technologies. If Multi Tube Integrity is used prior to the P&A planning, the diagnostic results would remove the uncertainty allowing operators to confirm the optimum cutting window location in all casings, thus minimising the intervention time and reducing rig time and costs. Integrity & corrosion assessment for slot recovery Slot recovery offers operators a way of capitalising on existing assets, by providing a new means of extending a well’s productive life. It is a robust solution which utilises the existing surface and downhole infrastructure, to create a “new” offshoot well, which would reduce the costs associated with drilling. However, before this can become a reality, the inspection of downhole completion elements such as surface casing and its cemented annulus are a must. Limitations in current technologies have meant that barrier verification is performed while the rig is in place, and once the tubulars (production and intermediate casings) have been retrieved. Key input parameters, such as the cement condition and the integrity of the casing are obtained at the last stage of the planning. The late arrival of this critical information results in a complex well intervention plan, with several contingent scenarios based on a range of potential outcomes from the downhole integrity assessment. The industry is calling for a new solution. One which can determine the condition and sealing performance of the cement and the metal barriers, prior to planning the slot recovery. Pulse data showing wall thickness, collars and completion elements in 5 ½ in., 9 5/8 in., 13 3/8 in. and 20 in. tubulars. A powerful diagnostic combination TGT’s Multi Tube Integrity product used together with the Multi Seal Integrity product is the answer. This powerful combination utilises TGT’s Pulse electromagnetic platform, the Chorus acoustic platform and the Indigo multisense platform, and it can be deployed in one through-tubing deployment. Pulse is used to evaluate the metal thickness of multiple tubulars, including the surface casing. It also has the unique capability of being able to confirm the position of critical completion components, including collars, centralisers, and casing shoes. Chorus is used to assess the hydraulic seal integrity of the cement barrier to determine where the cement is sealing and where it is not. Fluid flow in the well system creates a rich spectrum of acoustic energy that penetrates the surroundings. This acoustic wave is encoded with information that Chorus can convert into acoustic spectra that can locate leaks and flowpaths throughout the well system, from the wellbore to the outer annuli. The Pulse, Chorus and Indigo platforms are part of TGT’s True Integrity System which provides a clear diagnosis of integrity dynamics throughout the well system. The key to success It is critical that before slot recovery can be executed, there is an understanding of the collective integrity of the tubes, seals and barriers of the mother well. Only in doing this can there be a guarantee of the secure passage for pressurised fluids. The key to success for any P&A or slot recovery operation is knowing all the facts about the integrity of the well system prior to planning and execution. This delivers the potential to reduce costs, minimise schedule overruns, and ensures the integrity of the final outcome.
Dubai, UAE – 16 September 2020 TGT announced today that their brand transformation won Gold for “Best visual identity from the energy and utilities” sector and Silver for “Best visual identity from the engineering and manufacturing” sector at last night’s seventh annual Transform Awards MEA 2020. TGT enlisted Handsome Brands and Emberson to create a new brand that would better reflect the business, cut through the competition, and outperform in a challenging market. This meant completely rewriting the brand strategy; engineering a new brand architecture, technology brands, naming system, and a new product portfolio; then seamlessly connecting everything at all touchpoints with a distinctive visual identity. “This was much more than a ‘re-brand’, this was a total brand transformation”, commented Ken Feather, Chief Marketing Officer, TGT. “Twenty years of pioneering break-through diagnostics meant TGT had the pedigree and ingredients to become a winning brand. We needed to establish a unique position with a compelling brand promise that resonated with our customers and reflected our category-leader status,” adds Ken. TGT’s new brand is built on a simple, yet powerful idea – truth – a fitting attribute for a diagnostic leader. The brand delivers on this via two core product lines – True Flow and True Integrity. Flow and integrity are the two vital functions that allow oil and gas wells to operate safely, cleanly and productively. “In an industry that is inherently complex, we needed to untangle the language and cut through the noise. We needed a new brand identity that was striking, simple and clean, in line with the simplicity of the new product architecture and offering,” said Ian Haughton, Founder and Creative Director of Handsome Brands. TGT also achieved Highly Commended for “Best creative strategy” and “Best naming strategy”. Established in 2009, the Transform Awards has evolved into a celebration of the indispensable talent that exists within the branding sphere. The Awards evaluate exemplary work in brand development and acknowledge the growing significance of brand in strategic corporate communications – developing and sustaining a strong brand is imperative for success. Andrew Thomas, the publisher of Transform magazine and founder of the Transform awards, says, “This is the seventh year the Transform Awards has benchmarked the transformative power of brand strategy and design across Middle East and Africa. The Transform Awards has grown every year. But this year we saw phenomenal growth. This was – without any doubt – the toughest year to make the shortlist.” The awards ceremony, hosted by Ali Al Sayed, was held at the V Hotel, Dubai. With its transformation efforts successfully implemented, TGT is now focused on providing diagnostic solutions that enable oil and gas wells to perform better, with the aim of protecting people and the planet.
Dubai, 8 September 2020 - Independent global completions service company Tendeka and diagnostic specialists TGT have agreed a partnership to mitigate the costly consequences of sand control failure in wells. The remedial sand control collaboration known as ‘Find Fix Confirm’, will see TGT’s Sand Flow product used to accurately identify the locations of sand ingress within the wellbore. Then, Tendeka’s Filtrex thru-tubing sand control system is precisely situated to quickly repair the damage. Crucially, the service can confirm the effectiveness of the solution with the redeployment of TGT’s diagnostic product. 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. Launched in 2019, Tendeka’s Filtrex solution is a one-trip remedial system enabling sand-free production to be restored effectively and efficiently. It is fully compatible with thru-tubing operations, even through the tightest of restrictions. The first of its kind, Filtrex can perform sand clean out and chemical treatments during live well deployment. TGT’s Sand Flow product precisely locates sand entry to the wellbore and provides a qualitative sand count, clearly identifying problem zones, even in turbulent flow conditions. Delivered by the ‘True Flow’ system with ‘Chorus’ acoustic technology, Sand Flow provides the clarity and insight needed to manage sand production more effectively. Although commonly used to diagnose a known sand production issue, it is also used proactively to ensure downhole sand control measures are working correctly. Paul Lynch, Advanced Completions Director at Tendeka said: “The management and control of sand production is an inherent problem in the oil and gas industry. Often, the first indication of sand issues downhole will be as a result of detrimental effects that can occur at surface, such as fill in separators or erosional damage to pipe work, ultimately resulting in a shut-in well. Existing solutions have been extremely limited due to their high cost and/or poor performance. “Our Find Fix Confirm sand remediation service addresses both issues to offer a more effective, intervention-based solution. We believe this is the first time a specialized, integrated tool can fully understand and fix sand production issues, to ultimately maintain asset integrity and extend the product life of the asset. We are already seeing significant interest from operators around the world.” Ken Feather, Chief Marketing Officer at TGT commented: “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. “Our Sand Flow diagnostics are powered by Chorus technology which captures and decodes the acoustic signature generated by sand particles entering the wellbore to reveal sand ingress locations and sand count. Equipped with that information, Filtrex can be targeted to repair the breach, then Chorus can be deployed again to confirm that the breach is fixed. Overall, Find Fix Confirm enables better use of resources and more reliable sand control outcomes.” The ‘Find’ element of the solution will see TGT’s Chorus acoustic sensing platform deployed in hole on wireline to pinpoint sand entry locations utilizing time-domain analysis. 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, particle size and volume can be identified. The ‘Fix’ aspect will see Filtrex deployed via coiled tubing into the well and positioned across the target area. 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. Lastly, is the ‘Confirm’ stage. Here, the Chorus tool is deployed again but this time passed through the internal diameter of the Filtrex system to confirm that no sand is entering at that depth.
Challenge A 60-year old well in the Chadar field, Libya was exhibiting a leak at surface and sustained pressure in all three annuli – A, B and C. The age of the well coupled with the symptoms suggested a complex multi-barrier failure scenario that needed to be diagnosed quickly and accurately so that the well could be secured safely. Multi Seal Integrity example well sketch. Multi Seal Integrity evaluates the seal performance of multiple barriers, locating leaks and flowpaths throughout the well system, from the wellbore to the outer annuli. Delivered by our True Integrity system with Chorus, Indigo and Maxim technology, Multi Seal provides a clear diagnosis of leaks and rogue flow paths so the right corrective action can be taken. Multi Seal is used in a targeted fashion to investigate a known integrity breach anywhere in the well system. Barriers can also be validated proactively to confirm integrity. Either way, Multi Seal provides the insights needed to restore or maintain a secure well. Solution The customer selected TGT’s ‘Multi Seal Integrity’ diagnostic product to locate the source of pressure and associated flowpaths. Multi Seal Integrity diagnostics are delivered using TGT’s proprietary True Integrity system, leveraging a combination of key technology platforms applied by diagnostic experts using a methodical workflow. In particular, Chorus acoustic and Indigo multisense technology were utilised to precisely locate seal failures and associated flowpaths throughout the well system, from the reservoir, through barriers to the wellbore. The critical first step in applying the True Integrity system involves developing a customised diagnostic programme that would ’stress-test’ the well whilst Chorus and Indigo sensors recorded the resulting well dynamics downhole. Data acquired during the programme was then processed and analysed by experts using a third platform, the Maxim digital workspace. The diagnostic programme involved activating the well in four well state scenarios; one shut-in, and the others bleeding-off each of the three annuli. In the shut-in state, pressurised fluids from inside the tubing enter the A-annulus at three distinct points – X2000 ft, X4800 ft and X6400 ft. The fluid then enters the B- and C-annuli at X3600 ft via failures in the 7” and 9-5/8” casings. Fluid in the C-annulus then re-enters the formation via a failure in the 13-3/8” casing at X0900 ft. In the B-annulus bleed state, fluid from within the tubing follows the same flowpaths as in the shut-in state but in addition, formation fluid is entering the C- and B-annuli at X3600 ft. Result The True Integrity system successfully identified the sources of pressure and revealed a highly-complex geometry of interconnected flowpaths between several formation layers and through multiple tube and cement barriers. Equipped with a complete diagnosis, the operator was able to design and execute an appropriate P&A programme to secure the well permanently, eliminating any further risk to people and the planet.
Did you miss out? Due to an overwhelming response to our first series of #TechTalks came back for series 2! Once again the topics were diverse and revealed a range of powerful well system diagnostics that would help you to maintain safe, clean and productive well operations. If you missed the sessions, they are available to watch again by clicking the links below. The series was a resounding success, so have planned a second series covering different topics. To find out more click here. #TechTalk No. 4 – Pulse1 diagnostics Enabling "no compromise" integrity management for primary tubulars Pulse1 is the newest addition to our Pulse electromagnetic platform. It is the industry’s first slimhole 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. Multifinger calipers and conventional electromagnetics are a popular choice to assess the integrity of production tubulars. They are tried and tested, but each technique has its drawbacks. In this #TechTalk, Ken Feather uncovers how a new diagnostic resource delivers five times the accuracy of conventional techniques, enabling operators to assess the condition of production tubulars more accurately than previously possible, helping the industry to ensure safe, clean and productive well operations. TechTalk No. 4 – Pulse1 diagnosticsDOWNLOAD PRESENTATION #TechTalk No. 5 – Multi Tube Integrity Diagnosing the integrity of multiple tubulars, accurately and efficiently The miles of metal tubulars that form the backbone of every well system and are fundamental to its integrity. Tracking the condition and wall thickness of these tubulars is essential to maintaining a secure well. In this #TechTalk, Asiya Zaripova and Natalya Kudryavaya reveals how TGT’s Multi Tube Integrity product provides an accurate barrier-by-barrier assessment of up to four concentric tubulars from a single through-tubing deployment. Multi Tube Integrity #TechTalkDOWNLOAD PRESENTATION #TechTalk No. 6 – Get the most from your fracturing resources with "Fracture Flow" Effective hydraulic fracturing requires careful planning and a huge fleet of pumps, equipment and people. Knowing how these costly resources can deliver maximum impact is literally the million-dollar question. In this #TechTalk, Remke Ellis reveals how our new ‘Fracture Flow’ product can be used pre- or post-fracturing to evaluate actual reservoir flow profiles, so fracturing can be targeted, assessed and optimised to deliver maximum efficiency—without the million-dollar price tag. Get the most out of your fracturing resourcesDOWNLOAD PRESENTATION If you have any questions, please don’t hesitate to email us. Or, if you have a suggestion for a #TechTalk you would like us present, please email: email@example.com.
The oil and gas industry is continually raising well integrity standards and moving closer to a ‘no compromise’ approach. Article in Harts E&P Mechanical “multifinger” calipers have been used routinely by integrity managers for decades as the primary diagnostic method to evaluate production tubulars, partly because they offer a broad range of benefits, but partly because there was no viable alternative. There is now another option. The miles of metal tubulars that form the backbone of the well system are fundamental to its integrity. Chief among these are the production tubing and production casing, often referred to as “primary tubulars” or “primary barriers” because of their special role in keeping wells safe, clean and productive. Primary tubulars are the central conduits that transport fluids between reservoirs downhole and the wellhead. Collectively, primary tubulars form the wellbore and, from an integrity perspective, their main task is one of containment—keeping pressurized fluids safely inside the well system permanently—protecting and producing 24/7 for the entire life of the well. But primary tubulars have their work cut out for them; they need to unfailingly withstand the rigors of downhole conditions. Well systems are dynamic and can be hostile environments for man-made materials, even steel. Extremes and variations of pressure and temperature can cause mechanical stresses, well fluids can potentially corrode and erode the steel tubes, and mechanical interventions can cause additional wear over time. Regular inspection is therefore important to ensure continued safe, clean and productive operations. Tube Diagnostics Tube inspection tends to focus on three main attributes: tube wall thickness, tube wall defects and tube geometry. And although tube geometry or profiling is important, wall thickness and defect sensing are typically the two main objectives from an integrity perspective. With these applications in mind, the industry has developed a number of diagnostic technologies and methods aimed at tracking the condition of primary tubulars. Each has its strengths and drawbacks in terms of accuracy, resolution, coverage, efficiency and cost, when measured against their ability to assess wall thickness, defects and geometry. In a recent industry survey of 100 well integrity management professionals conducted by TGT, mechanical “multifinger” calipers were identified as the most prolific diagnostic method used to evaluate production tubing. For production casing, electromagnetic and ultrasound techniques were the most popular, but calipers were still prominent. Mechanical calipers offer a broad mix of attributes that make them suitable for tube diagnostics. They are widely available to suit all sizes of production tubing and casing, they are relatively inexpensive and easy to deploy, and can provide comprehensive assessment in all three areas of wall thickness, defect sensing and tube geometry. However, calipers have several application-specific drawbacks, mainly in terms of accuracy in determining actual wall thickness in some scenarios, and sensing small defects. According to the industry survey of integrity managers, the most important attributes experts consider when selecting diagnostic methods to evaluate production tubing are: the accuracy and sectorial coverage of wall thickness measurements, and the completeness and resolution of defect sensing. Geometry assessment is a lesser priority. Furthermore, the experts required a wall thickness accuracy of at least ±3% and a defect resolution of approximately 3 mm. To track tube wall thickness, calipers measure internal diameter (ID) and estimate thickness by assuming a nominal outside diameter (OD). Variations in the actual OD or external corrosion, both invisible to calipers, can invalidate the thickness value. Also, scale or wax deposits on the inner surface can mask internal defects and lead to further false thickness computations. And while the accuracy of caliper ID measurements is approximately ±5% (±0.5 mm), the total system error for wall thickness can reduce to ±10% (±1 mm), or worse if there is scale or external corrosion. This accuracy is far below the ±3% level currently required by integrity managers. For defect sensing, calipers offer highly precise radial measurements via 24, 40 or 60 fingers spaced azimuthally around the inner tube surface. Thin, 1.6 mm fingertips can sense the smallest defects provided the defect lies in the path of the finger passing over it. Practically, there are gaps between fingers that vary according to tube size and finger density. For example, the gap between 24 fingers in 3-1/2 inch, tubing is about 7 mm. This means that the fingers only sense about 10%-30% of the inner wall surface and it is possible for small defects or holes to pass undetected between fingers. A new alternative Despite the drawbacks, mechanical calipers have been used routinely by integrity managers for decades as the primary diagnostic method to evaluate production tubing, partly because they offer a broad range of benefits, but partly because there was no viable alternative. In an effort to provide an alternative, TGT has developed a new diagnostic platform that can be used independently, or together with calipers or other techniques to provide a more accurate and comprehensive evaluation of tube integrity. Pulse1 is the industry’s first slim tube integrity technology capable of delivering “true wall thickness” measurements of production tubing in eight sectors, with complete all-around sensing of tube wall condition. Unlike calipers that measure ID to estimate thickness, Pulse1 uses electromagnetic energy to measure actual metal wall thickness directly. This can translate into greater accuracy, especially if the tube wall is coated with scale or has external corrosion. Pulse1 delivers eight sectorial wall thickness measurements up to an accuracy of ±2% in all common tubing sizes, and up to ±3.5% in production casings. This meets or exceeds new industry requirements and represents about a five-fold improvement on caliper accuracy. In terms of defect sensing, Pulse1 can sense localized metal loss defects equivalent to 7-10 mm diameter holes in the most common production tubing sizes. Calipers offer greater resolution, and Pulse1 provides greater coverage, so combining both delivers a more comprehensive assessment then previously possible. The graph depicts primary tube integrity utilizing Pulse1 to evaluate 6-5/8-in. casing, and a comparison with XY caliper. Overall metal loss measured from Pulse1 is greater than that estimated by XY caliper. The caliper will only detect internal loss, whereas Pulse1 will measure actual metal thickness and assess both internal and external loss. (Source: TGT Diagnostics) Efficiency, versatility and chrome Corrosion-resistant chrome alloy completions provide protection from corrosive and toxic fluids, and the inner wall surfaces are often coated with an additional thin protective film. Many operators prefer not to use calipers to inspect such completions because the millimeter-thin tips of caliper fingers might scratch the inner surface, exposing the alloy and leaving it vulnerable to attack. It’s a dilemma because regular inspection is essential, and previous electromagnetic methods only provided an average non-sectorial thickness measurement. Pulse1 provides eight thickness measurements and is deployed with soft-touch roller centralizers with less point-pressure on the tube wall, minimizing the risk of scoring. This makes it a safer alternative for inspecting chrome completions. And because Pulse1 utilizes ultra-fast sensing technology and time-domain techniques, it is as effective in chrome alloys as in conventional steel tubulars. In terms of efficiency, diagnostic interventions cost time and money. The Pulse1 tool OD is 48 mm slim and delivers accurate sectorial wall thickness in tube sizes from 2-7/8 inch to 9-5/8 inch. This means operators can survey production tubing and the casing below the tubing shoe in a single deployment, saving rig time and intervention costs. Combining Pulse1 with Pulse4 enables multi-barrier assessment, and both can be deployed rigless on slickline improving efficiency. Enhancing integrity management The oil and gas industry is continually raising integrity standards and moving closer to a “no compromise” approach, and this development is helping the industry to achieve that goal. For applications where accurately tracking wall thickness is the main priority, Pulse1 can be considered as a reliable and practical alternative to mechanical calipers. And if the well is prone to scale, wax or external corrosion, Pulse1 can deliver significantly improved accuracy. If the diagnostic objective is a more comprehensive no compromise evaluation, then combining Pulse1 with caliper will offer the best results.
Challenge The completion string of a gas producer was upsized from 3 ½’’ x 4 ½’’ to 4 ½’’ x 5 ½’’ with 13% chrome tubing to enhance production. Prior to starting the workover, the A-annulus was successfully pressure tested to 1,500psi. The old completion string was cut above the AHC packer, retrieved and replaced with the new ‘13CR95’ tubing together with a new packer. An A-annulus leak was then observed after setting the packer, but with no TCA communication. Before continuing, the operator needed to understand the integrity dynamics at play and ensure that the new packer was sealing. Conventional diagnostics could have meant another costly workover, lost production, and the risk of damage to the expensive 13CR95 tubing joints. All of which were clearly undesirable. India, approximately $1.2 billion is lost per day due to well integrity issues. A major operator performed a gas lift on a newly drilled well to initiate production but when the sustained annulus pressures (SAP) raised to alarming levels in nearby well systems, all wells had to be shut in resulting in a loss of production from multiple wells. The scope was to identify the path of communication between the inner and middle annulus of the subject well. Multi Seal evaluates the seal performance of multiple barriers, locating leaks and flowpaths throughout the well system, from the wellbore to the outer annuli. Solution To identify the integrity breach, TGT designed a diagnostic programme utilising the ‘True Integrity’ system with Chorus (acoustic) and Indigo technology. Slickline conveyance was used for efficient and low cost rigless operation, and minimal footprint. Two survey passes were deployed, one with the well shut-in and another with continuous water injection into the A-annulus. During shut-in conditions, the baseline temperature and acoustic responses confirmed that there was no cross flow or lateral flow anywhere in the well system. Injection was then started in A-annulus and the acoustic and temperature surveys were repeated. This time, the temperature profile exhibited a cooling effect caused by water being forced into A-annulus, but there was no temperature difference across the upper packer. Notably, clear acoustic responses were evident at two intervals under injection conditions. A high amplitude wide frequency band acoustic signature, typical of ‘leak flow’ was observed at X175 ft. Also, a lower amplitude, lower frequency signal was observed around X650 ft. No acoustic signal was observed across the upper packer confirming it was sealing properly. Multi Seal Integrity answer product showing comparison between measurements acquired during shut-in and injection conditions. The primary leak point is clearly visible at X175 ft, and a minor leak interval is evident around X650 ft. Result The analyst confirmed the leak point in the 9-5/8” casing at X175 ft. The operator was able to assess the integrity of the well and decided not to remediate the casing leak, deciding instead to operate the well with the proper monitoring and risk mitigation plans in place.
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.