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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.
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.
Pulse1 technology for production tubulars delivers five times the accuracy of conventional techniques, with ‘all around’ sensing of tube condition Dubai, 14 July 2020 - TGT announced today the launch of Pulse1, the industry’s first slimhole tube integrity technology that delivers actual wall thickness measurements in eight sectors with ‘all around’ sensing of tube wall condition. This advanced diagnostic capability underpins new answer products and enables operators to assess the condition of production tubulars more accurately than previously possible, helping the industry to ensure safe, clean and productive well operations. Commenting on the launch, Mohamed Hegazi, TGT’s CEO said, “Proactive inspection and accurate diagnosis of well integrity is fundamental to ensuring safe production, and Pulse1 delivers on that promise for primary tubulars. Conventional measurements like mechanical calipers will still have a role to play, but the addition of Pulse1 diagnostics will address customer needs with greater accuracy. Pulse1 is defining a new benchmark in well integrity diagnostics.” Pulse1 is the most recent extension to TGT’s Pulse platform: one of five proprietary technology platforms that provide powerful through-barrier diagnostics for the oilfield. Pulse technology powers TGT’s ‘True Integrity’ answer products with a particular emphasis on ‘Tube Integrity’. Pulse1 is designed primarily for ‘production tubing’ and delivers answers that are up to five times more accurate than conventional techniques. Ken Feather, TGT’s chief marketing officer said, “Pulse1 has been designed to meet the growing industry need for ‘no compromise’ integrity management and overcome the drawbacks of current technologies, particularly mechanical calipers and conventional electromagnetics. This makes it the ideal choice for routine or targeted tube integrity surveillance, especially when accuracy is the top priority.” “Production tubulars have a special role in keeping wells safe, clean and productive, and they need to perform 24/7 without compromise. Operators use calipers to monitor tube wall thickness, but the error can be 10% or higher. Pulse1 delivers up to 2% accuracy in eight sectors around the tube, providing operators with a higher level of integrity assurance than previously possible”, continued Feather. Alexey Vdovin, TGT’s head of electromagnetic systems development added, “We have been advancing electromagnetic diagnostic technology for many years and our Pulse platform is favoured by customers globally for its accuracy and reliability in a wide range of multi-barrier completion scenarios. Pulse1 builds on that pedigree to deliver eight-sector wall thickness for primary tubulars, which I believe is an industry-first in a slimhole package.” Pulse1 diagnostics are now available to oilfield operators through TGT’s comprehensive range of ‘True Integrity’ answer products.
Challenges Waterflooding involves injecting water into a reservoir, usually to increase pressure and thus stimulate production. However, when this action is being performed in a multi-layer reservoir it requires constant monitoring to identify the potential for water breakthroughs and target intervals not flowing, that may affect fluid production. The operator’s main goal was to gain a quantitative assessment of the flow contributions from each layer in the producer well, particularly in the undersaturated reservoir areas which hold free gas behind the tubing and casing. Solution The operator selected TGT’s Reservoir Flow product which is delivered by the True Flow diagnostic system, using Chorus (acoustic) and Cascade (thermal) technology. Reservoir Flow complements conventional Wellbore Flow (conventional production logging) diagnostics by evaluating flow profiles behind casing. The diagnostic programme for data acquisition involved two passes for flowing and shut in surveys. The Chorus surveys revealed the flow contribution from each layer, which is a significant advantage over conventional production logging (PLT). True Flow system uses a combination of Chorus, Cascade and PLT to reveal phase segregation and downhole contributions in this producer. Results The producer under investigation was completed for separate production from two sections of the multi-layer reservoir, with the upper section gathering production through the sliding sleeve door (SSD). The diagnostics were performed across the target reservoir (Figure 1). Chorus (acoustic) platform captured multiple high-amplitude, broadband, depth-specific acoustic signals across the most permeable layers in both the flowing and shut-in regimes showing the fluid flow through the reservoir layers. The acoustic signals observed in the long shut-in regime indicated the presence of multiple wellbore crossflows, due to formation pressure differences between the layers and the heterogeneity of the oil displacement. Cascade platform made it possible to estimate the production profiles across both sections of the multi-layer reservoir, including the one behind the tubing, which was not possible by using PLT data alone. The diagnostic results provided the answers the operator needed to plan an effective workover. Plan included the zonal isolation of water filled layers and a well recompletion that would improve waterflooding performance and increase recovery.
New fracture flow diagnostics help operators elevate fracture performance (in the Permian) Article featured in Harts E&P In recent years, the Permian basin is been the most prolific shale play in the US. Production in this area increased to 3.8 million barrels by 2019, representing almost 70% of the whole US production growth from 2011 to 2019 according to International Energy Agency (IEA). The impressive aspect of this achievement is that the growth has not stopped. On the contrary, the Permian is expected to continue growing and is estimated to achieve up to 5.8 million barrels by the end of 2023. Such impressive growth doesn’t come easy. Significant advances in drilling, completing and multi-stage fracturing will continue to drive production increases. But evaluating the performance of fracturing programmes and the wells they deliver is key to optimising resources and ensuring maximum return on investment. Conventional diagnostics [such as production logging tools or ‘PLT’s’] can’t provide all the insights required to ensure the operator is achieving the best returns. This article focuses on the challenges faced when assessing unconventional reservoirs in terms of production, and features a new diagnostic capability introduced by TGT to evaluate the flow performance of hydraulically fractured wells, stage-by-stage. The new diagnostic product is aptly called ‘Fracture Flow’. Operators have been drilling aggressively and pushing the boundaries of hydraulic fracturing beyond conventional standards compared to other plays. The drilled length of lateral sections has been constantly boosted, adding more footage as well as more production stages. The ultimate objective is to penetrate deep into the target formation increasing the area of contact with the specific reservoir or formation making the well, its completion and the reservoir one dynamic production system. Piezo crystals used in the Chorus tools and sensorThrough barrier diagnostics Champions of this approach include a Houston-based operator that recently drilled such a well at the Wolfcamp. The completion included a lateral section of more than 17,900 ft running through the Spaberry formation. The completed well had a total measured depth exceeding 24,500 ft with a customised completion design and fracking treatment. The completion included more than 50-stages and sand was pumped along more than 2,200 ft of reservoir to increase the well productivity. These extended laterals have been engineered to optimise production performance and leverage improvements in drilling, fracking treatments and completion designs. The operators have overcome the number of well construction challenges and have quickly moved up a steep learning curve. Like the challenges encountered with well construction, the Permian basin faces its own challenges. Following such an extensive multistage hydraulic fracturing programme, the wells are brought onstream at high initial production rates. But most of these extended-lateral producers tend to decline dramatically over a very short period. To help combat this challenge, and many others, TGT has developed a number of application-specific diagnostic products using its ‘True Flow System’ to quantitively evaluate flow dynamics throughout the entire well system – from reservoir to the wellbore, and the dynamic interplay between the two. When talking about a hydraulic fracturing job, we all know the importance of the programme design prior to execution. During this phase, sophisticated software is utilised to model and optimise the fracturing programme, taking into consideration multiple variables. These variables include formation properties, lithology, depth, mechanical stresses and other parameters that can affect the final outcome. Another important consideration is the formulation of the hydraulic fracturing fluid. This fluid is normally comprised of sand (or proppant), gels (foam or sleek-water) and additives that are pumped downhole following the job design to prop open the induced fractures and maximise the extension of the fracture in terms of length, height and aperture as well as the integrity of the fractured conduit itself, so hydrocarbons can flow unabated. TGT’s diagnostic ‘Fracture Flow’ product is able to locate and evaluate fracture inflows and quantify inflow profiles in hydraulically fractured wells. The product is delivered by our analysts using the ‘True Flow System’, which combines several technology platforms – Chorus (acoustic), Cascade (thermal), Indigo (multisense) and Maxim (digital workspace), to acquire, interrogate and analyse the acoustic spectra and temperature changes generated by the hydrocarbons or any other fluid flowing from the reservoir through active fractures and into the completion. This diagnostic capability goes beyond conventional flow measurement techniques that generally stop sensing at the wellbore and are therefore unable to quantify flow within the reservoir itself. The Fracture Flow product extract shown in figure-1 represents the diagnosis of a hydraulically fractured oil producer with >80 degrees deviation. The reservoir has a gross thickness of approximately 1,200 ft and is fully cased. ‘Fracture Flow’ diagnostics compare fractured intervals [blue] to main producing intervals [green] at different choke sizes in order to evaluate the true effectiveness of hydraulic fracturing programmes and maximise well performance. The operator’s objectives in this case were to evaluate the post-fracture performance of three zones, and in particular: Compare the effectiveness of fractured stages by assessing the production contribution from each fractured interval Identify crossflow or behind-casing communication Increase production efficiency by identifying the optimum production choke for this well system. The results revealed by the Fracture Flow analysis clearly revealed that the fractured intervals (figure-1 – blue coding) were not contributing fully to production in their entirety. Furthermore, it identified exactly the active zones and where the main production was coming from (figure-1 green coding). Fracture Flow revealed that only 62%, 59% and 56% of each zone was actually producing at the outset. The Fracture Flow analysis also indicated that there were no crossflows among the three zones which was another key finding from an integrity perspective. Thirdly, the Fracture Flow diagnostic programme helped to determine the optimal choke size required to ensure that the fractured zones were contributing at maximum rate. TGT work in close collaboration with operators using Fracture Flow to help them reach their frac evaluation objectives; locate effective fracture inflows; quantify inflow profiles; and assess the effectiveness of fracture programmes, helping to optimise future programmes and maximise return on investment. TGT is an international diagnostics company that specialises in ‘through-barrier diagnostics’ for the oilfield. Our Houston-based operation provides unique ‘True Flow’ and ‘True Integrity’ diagnostics to operators throughout the United States, including the Permian. We are also working actively in deep water Gulf of Mexico, Latin America and other major basins around the globe.
Challenges Waterflooding contributes approx. 45% of the total production in the Sirikit field and will continue to play a key role in the future. Improvements in waterflood performance would have a positive impact on financial performance, but waterflood optimisation requires a clear understanding of the injection profile with the water distribution in the reservoir. Well sketch shows a range of typical behind casing flow scenarios – that Reservoir Flow can locate and quantify. Solution The operator selected TGT’s Reservoir Flow product to evaluate injection profiles and identify active layers. Delivered by the True Flow diagnostic system, using the Chorus acoustic platform and the Cascade thermal platform; Reservoir Flow product provides the information operators require to make informed decisions to enhance waterflood performance—that may involve zonal isolation or recompletion. Reservoir Flow complements conventional production logging diagnostics by evaluating flow profiles behind casing at the well-to-reservoir interface. The Chorus diagnostic programme involved acquiring data during injection and shut-in conditions. The data was used to reveal active layers, and temperature simulations were used to calculate the injection profiles. Chorus data indicated the presence of high-amplitude acoustic signals that correlate with the permeability profile. These acoustic signals are generated by injection water being absorbed in the reservoirs. The Cascade platform’s advanced thermal simulation enabled quantitative interpretation of logging data. The simulation-based profile is shown in the Reservoir Injection Profile column. Results The injector under investigation was designed to inject into two sections of a multi-layer reservoir, that were separated by a packer. The lower injected zone was below the tubing shoe, whereas the upper injected zone was controlled via a Sliding Sleeve Door (SSD) (Figure 1). The distribution of water behind casing in the reservoir was substantially different to the data obtained by conventional production logging techniques. In the upper section, conventional techniques only showed the injected water exiting from the wellbore through the SSD. However, Chorus acoustic data and temperature simulation was able to additionally define the distribution of the injected water in the reservoir. In the lower reservoir section, the injected water was meant to advance laterally from the well to the reservoir through perforations. However, the Chorus acoustic data and temperature simulations, together with conventional production logging data, showed that the injected water flowed through the perforation across the L1.1 reservoir, passing through a cement channel and moving into the more permeable L2.1 and L3 reservoirs. The diagnostic results made it possible for the operator to plan a more suitable workover to improve waterflooding performance and increase recovery.