Dubai, U.A.E – 21 June 2023   TGT Diagnostics today announced the launch of its latest acoustic platform, ChorusX, a new diagnostic resource specifically designed to locate and characterise flow in oil and gas wells. This all-new acoustic array platform enables energy companies to find and map fluid flow throughout the well-reservoir system with greater ease and precision, helping them to keep wells safe, clean, and productive.   Ken Feather, TGT’s chief marketing officer, commented, “Understanding flow dynamics in the well system is the key to unlocking better well and reservoir performance, and acoustic techniques have become an indispensable means of achieving that goal. ChorusX is the result of two decades of intensive research, innovation, and extensive field experience in applying the power of sound to flow diagnostics in thousands of wells. Eight high-definition array sensors, extreme dynamic range recording and a unique phase analysis engine work in concert to deliver uncompromising levels of clarity, precision, and certainty to analysts and well operators.”   At the heart of ChorusX is a compact array of eight nano-synchronised sensors that record high-resolution flow sounds across an extreme dynamic range of intensities and frequencies. A unique phase analysis workflow combines specialised acoustic field modelling with a sophisticated waveform-matching algorithm. This combination delivers an important new dimension to acoustics and flow diagnosis – radial distance. In combination, these advances underpin four new complementary answer products that enable TGT analysts to easily and accurately locate and map flow throughout the well system.   Ken continued, “ChorusX has been redesigned from the ground up to excel in three important areas: extending spatial and audible reach to record the lightest, quietest, and furthest flows; recognising different types of flows; and pinpointing flow sources with unmatched accuracy in depth, and radially. Flow events are displayed more clearly in high definition, enabling operators to plan actions with greater confidence and implement them efficiently with precision.”   TGT has been advancing the use of acoustics to locate and characterise flow for more than two decades, and ChorusX is available to all TGT Diagnostics customers through a range of True Flow and True Integrity/Seal Integrity products.

Challenge The operator of a deep high-pressure low-permeability gas field wanted to assess the feasibility and effectiveness of completing a horizontal well with an uncemented liner that had 10 sliding sleeve valves/ports but, unusually, no isolation packers.   Completed in the standard way, this well would require 10 packers, adding significant cost and complexity to the completion. A successful strategy for packer removal would lower completion costs, increase installation efficiency, and reduce future maintenance challenges. These savings and efficiencies would multiply substantially for field-wide application.   The chief concerns about the new strategy were that lack of isolation during fracturing might prevent sufficient fracture force being focused on each target zone and whether the result would be one large fracture rather than multiple distributed fractures. Another challenge was to evaluate the success of the strategy by identifying and locating the fractures to establish their extent along the wellbore and assess the performance of each fracture group.   Conventional production diagnostics could only assess flow entering the wellbore at each port and would, therefore, not reveal fracture location or distribution or even distinguish reservoir flow from port flow. A sophisticated post-fracture assessment was needed to determine whether the technique had been successful and to fine-tune future operations. New ChorusX answers transform the professional workflow, enabling analysts to diagnose well systems flows with greater ease and confidence. In this complex scenario, the Phase Map and Radial Map reveal the location of active fractures directly behind the frac ports. Conventional diagnostics would be unable to deliver this level of clarity and certainty. Solution TGT’s Fracture Flow diagnostics product is used to evaluate the effectiveness of hydraulic fracturing operations. In this well, the new ChorusX acoustic array platform was included in the survey programme to bring a wide range of additional benefits and fracture performance insights.   Using ChorusX, analysts located the precise depth and distribution of induced fractures and evaluated the relative contribution from each fracture along the entire reservoir section. ChorusX can distinguish between flow from fractures and flow through the sliding sleeve valves, even when the fractures are located at the same depth interval as the valves. This breakthrough enables the operator to distinguish between port flow and fracture flow, thus giving greater clarity and certainty to evaluations. Analysts can call on new ChorusX answers to resolve even the most complex flow scenarios. The Phase Map and Radial Map bring valuable insights that complement other measurements, leading to a more confident diagnosis. The top section of this ChorusX answer product identifies and locates active fractures, whereas the lower section confirms that no active fractures are present. Result TGT analysts used ChorusX data to identify and precisely locate fractures right along the reservoir section. The survey also provided an accurate flow geometry that displays the relative contribution that each fracture makes to production.   The Acoustic Radial Map serves as a highresolution, near–far indicator for flow and can distinguish between port flow and reservoir fractures in the immediate vicinity of the ports. These innovative features are unavailable in even the most advanced single-sensor acoustics systems.   The Fracture Flow product with ChorusX technology proved the effectiveness and viability of the new, ultra-efficient completion technique in this geological setting. The results provided the operator with valuable insights that will enable them to optimise the fracturing parameters and the completion design for field-wide roll out. This will deliver enormous savings in time, cost and resources, thereby helping operators access ‘hard to recover’ reserves in a more efficient and economic way.

Challenge Leaks observed in an active well in the Netherlands forced the operator to suspend the well. An initial examination indicated that the integrity breach could be located in the tubing, casing or any of the completion elements within or beyond the A-annulus envelope. A pressure test confirmed that the leak rate was small, just 0.25 bar per day, but this was sufficient to pose a health, safety and environmental risk and trigger the suspension of the well.   Leaks in the well system are a serious issue, and well integrity engineers want to understand precisely how and where the leaks originate so they can be repaired. The combination of many potential leak points spanning the length of the completion coupled with a small leak rate made this a challenge to investigate. The operator needed diagnostics technology that had a large radial reach and was both sensitive and accurate enough to scan for leak points and help steer a repair programme. Multi Seal Integrity example well. 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 operator selected TGT’s Multi Seal Integrity answer product, upgraded with the new ChorusX acoustic array platform to meet the three-part challenge of sensitivity, accuracy and reach. ChorusX combines an array of eight nano-synchronised acoustic sensors with advanced processing to deliver a dynamic recording range that is ten times wider than in previous Chorus technology, specifically at the ‘quiet’ low-amplitude end of the Acoustic Power Spectrum.   The higher-resolution measurements from the ChorusX array reveal flow activity with increased definition and clarity, and TGT’s unique ‘near–far’ phase shift processing helps analysts distinguish between flow events near the wellbore, in the completion, and far from the wellbore, in the reservoir. This enables operators to target remedial actions with greater precision and implement them with higher confidence. The operator also chose to include Chorus9 technology in the survey programme to make a technical comparison between the two platforms. Multi Seal Integrity answer product using ChorusX. The Chorus9 acoustic power spectrum (left) indicates the approximate depth of the leak, but multiple indicators from ChorusX (right) combine to indicate the type, depth, radial proximity and extent of the integrity breach with much greater precision and clarity. Result The Multi Seal Integrity survey was performed while applying pressure in the A-annulus and observing a pressure drop of 0.25 bar per day, confirming the very low leak-rate. The Chorus9 and ChorusX platforms both recorded acoustic signals at X378 m, but the Acoustic Power Spectrum (APS) of ChorusX was far more detailed and informative (Figure 1).   The sharp change in polarity of the phase shift data, as seen in the Acoustic Phase Map, indicated a localised ‘singular’ leak point and its precise depth. The location and character of the data signature in the ‘near’ panel of the Acoustic Radial Map indicated that the source of flow was near the wellbore within the completion, and not in the reservoir. The precise nature of the radial map data signature further confirmed the exact depth of the leak source.   The combination of independent acoustic indicators enabled analysts and the operator to isolate the integrity breach to a single location in terms of depth, extent and radial distance from the wellbore. This enabled a highly targeted approach to remediation planning and implementation.

Challenge The operator of this North African oil producer was planning a workover to replace a leaking production string. As part of the work process, the client wanted to locate and eliminate the sustained annulus pressure (SAP) in the B-annulus between the 7-in. and 9⅝-in. casings. SAP indicates an underlying integrity problem. In this case, pressure was building to approximately 100 psi over a period of 10 hours, indicating a progressive annular leak that could become worse over time.   Accessing the B-annulus and making repairs, such as cement squeeze operations, is much easier when the tubing has been removed. The main challenge was accurately identifying the leak source and flow path associated with the SAP. Conventional temperature measurements can indicate flow behind casing but they lack precision, especially when the source is in an outer annulus and the sensor is located inside the tubing. Accurately determining the source of the SAP would be the first step to planning and implementing a successful remediation. 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 operator selected TGT’s Multi Seal Integrity solution to evaluate the well and locate the source of B-annulus pressure. TGT engineers and analysts used the True Integrity system to locate leaks and validate seals throughout the well.   The True Integrity system combines Chorus acoustic sensing and analysis technology with high-precision temperature surveys provided by Indigo. The Chorus Acoustic Power Spectrum (APS) can reveal flow activity in and around the well system, particularly fluid flow through restrictions or between zones that have high differential pressure. For example, it can identify fluid movement into or out of permeable formations and characterise fluid movement within the well completion.   The well was surveyed under both shut-in and B-annulus bleed-off conditions. The survey was designed to reveal flow dynamics and fluid flow occurring in the B-annulus, which would identify the source of SAP along the wellbore and the flow paths between active formations and the B-annulus. Multi Seal Integrity diagnostics located the source and traced the flow path of the fluid that was causing sustained pressure in the B-annulus. Result The Chorus APS revealed flow activity opposite the perforations during the shut-in survey. This suggested the presence of active crossflow in the formation layers at that depth. The Indigo temperature survey also confirmed flow activity at the depth of the target reservoir during the shut-in survey.   During the B-annulus bleed-off survey, additional flow was observed from the target reservoir towards the surface. The low-frequency content of this acoustic signal is characteristic of cement channel flow (Figure 1). The Multi Seal Integrity survey identified the source of the SAP as the target reservoir, with the flow path extending through cement channels in the B-annulus.   Using this information, the operator was able to conduct an effective cement repair and recomplete the well, bringing it back to safe, clean and productive operation.

Challenge Setting surface plugs in offshore wells requires multistage cutting and pulling out of well casings. The milling process may last between a day and a week, depending on the well structure and the depth of the cutting window. The aim is to define the cutting interval so it contains the smallest volume of metal to be processed. The presence of collars, centralisers and welded fins can also substantially increase cutting time.   A multistage ultrasound survey is the conventional method for locating zones of minimal total wall thickness in the tubulars and determining the completion elements. This approach requires well preparations and logging after each stage of the retrieval process. The time spent on well preparation activities such as cleanout, pressure logging and interpretation is active rig time and a target for optimisation. Figure 1: Results from the TGT Pulse platform survey enabled the operator to adjust the depth of cutting/milling to avoid the risk of cutting the welded fins on the 20-in. casing. Solution Multi-tube scanning using TGT’s Pulse (electromagnetic) platform can identify and characterise completion elements in up to four concentric metal barriers. The electromagnetic response from the barriers is not affected by the presence of scale or fluids and does not require the tubing to be pulled out of the hole. As a result, the Pulse system enables rigless scanning of tubulars to prepare cut and pull out operations, thereby minimising the time required for these operations. The cutting windows can be determined precisely, enabling the selection of a location with no completion elements and where the total nominal thickness is minimal. The electromagnetic scanning survey can be perfomed riglessly or in a single run at the beginning of the plug and abandonment process. By enabling lighter or rigless interventions, TGT helps minimise carbon footprint. Figure 2: Casings retrieved during the plugging and abandonment operations at Cormorant field show precise milling of four tubulars and avoidance of elements such as welded fins on the 20-in. casing. Result In this case study, the Pulse survey was conducted on the rig timeline with real- time decisions being made from the results. This called for rapid interpretation, and the average delivery time for results was set at 3–4 hours after the tools rigged down. In each of the four logged wells, all the completion elements were located, described and the cutting window determined. In some cases, the window was adjusted by several feet from the initial plan (Figure 1). All cut and pull out operations went smoothly and using the Pulse system in this way saved more than 100 hours of rig time and resources. Rigs and surface equipment are powered by diesel engines or gas turbines that emit carbon dioxide when fuel is burned. A typical jack-up rig emits around 70t of carbon dioxide per day, and so a 100-hour reduction in rig time translates into substantial energy consumption and emissions savings.   The survey showed that the Pulse platform could detect fins, collars and other completion elements in the third or fourth concentric metal barrier with casing outer diameters of up to 20 in (Figure 2). This means it is possible to determine the exact position for well barrier cutting and enable effective pull out operations, even in situations where the detailed well barrier schematics are unavailable.

Here are alternative solutions to improve P&A operations by reducing cost and increasing the reliability of E&P operations Article featured in Harts E&P Magazine   Today, more and more wells are reaching the end of their economic life and need to be decommissioned—a process often referred to as Plug and Abandonment (P&A). Many factors need to be considered when designing an effective P&A operation, especially those that relate to barrier integrity, such as cement bond quality, the presence of behind casing flow, and potential inflow zones.  Oil and gas producers are obligated to perform P&A operations in accordance with regulations and guidance typically developed in collaboration with government bodies to ensure that decommissioned wells and safe and secure.   The main objective of P&A is to restore previously penetrated natural barriers by securing potential barrier failures within the well system. These failures could be related to steel or cement barrier degradation during the operational phase of the well. Steps are taken to verify the sealing capacity of so-called external well barrier elements, including cement bonding, shale or formation creep, and baryte sediments. For offshore wells, re-entry of decommissioned wellbores becomes virtually impossible after a new lateral has already been drilled or when topsides have already been removed. Therefore, it is critical that the well is robustly and permanently sealed.   The resources required and cost of planning and performing a P&A operation are mainly driven by the complexity of the P&A, including whether it can be done riglessly or with a drilling rig. The operator has to strike a balance between meeting the required regulatory needs, deploying the required diagnostics tests, and optimising the time spent to prepare and execute the process. Fig.1: Example of the cost estimation of the onshore geothermal well P&A. Click image to view full report. This P&A cost is not an investment into future profit. It is an investment in protecting the environment and eliminating future hazards. In order to address all concerns, operators are seeking alternative solutions to improve the efficiency and effectiveness of P&A operations by reducing cost and at the same time increasing the reliability of operations.   Today, ‘P&A optimization’ is developing in two main areas: A transition towards ‘rigless’ mode, where P&A operations are performed using slickline, wireline or coil-tubing before the rig moves to the well. Rigless operations may include the abandonment of the reservoir, verification of the well barriers and gathering the input parameters for P&A sequence improvement. The key advantage here is to verify the existing well barriers when the tubing is still in the well. There are recent developments in tubing cement logging (spectral acoustics and through tubing ultrasound), enabling the evaluation of cement bond and seal with certain thresholds to determine barrier isolation. Utilization of alternative or natural barriers instead of conventional cement barriers. This allows P&A engineers to consider shale and formation creep, salt dome, squeezing bismuth and polymers to improve the sealing of the external well barriers and take the reliability of the barriers to the next level. The main advantage that operators see today is that shale, for example, may work as the best downhole barrier, because it does not degrade with time, has close to zero permeability, and may even seal potential future leaks or failures. In fact, simple calculations show that 30 m average cement barrier (as per NORSOK and U.K. P&A guideline) with permeability of 20 micro darcy will start to leak at a rate of 0.25 m3 gas a year if 1,000 psi pressure is applied. A similar leak rate for typical shale creeps permeability will only be observed in the presence of 2-5 m of well-bonded shale. The same 30 meters of shale will be almost impermeable (link to the presentation). Fig.2: Graph showing the optimization of the P&A process. Operators typically plan P&A processes years in advance and develop the strategies individually for each well, taking into account the construction of the well, lithology and the technologies available on the market today. Above all, the strategy should meet the requirements of the regulatory bodies of the country in which the operator abandons the wells, as well as the operators own policies.   The example below shows the experience of a North Sea operator in using ‘P&A optimization.’ To improve the P&A process and demonstrate the ability of natural barriers to withstand reservoir pressure, the operator performs a test of the shale barriers for future abandonment.   For a particular field on the Norwegian Continental Shelf, characterization of the overburden formations indicated that a simplified permanent P&A strategy is possible based on a concept with annular sealing from ‘creeping’ Green Clay and a buffering capacity in the underlying Balder formation. Leak scenario simulations with a fracture growth simulator concluded that such a permanent P&A strategy is robust against deep gas migrating, given that a sufficient stress contrast is present between the sealing Green Clay and the Balder. Estimates of the stress profile in the overburden derived from sonic logs indicated such a favorable stress profile is present. However, this stress profile had to be confirmed by dedicated stress tests. Consequently, ‘Extended Leak Off Tests’ (XLOT) were planned and performed during the P&A operations in both the Balder and Green Clay.   The XLOT in the Balder formation was performed through perforations in the intermediate casing. However, as the Balder interval consisted of varying degrees of poorly bonded cement, this introduced a risk of uncertainty with regards to depth control—where the fracture(s) propagate and if there is communication to above or below the Balder formation.   To mitigate this risk, the operator utilized TGT’s True Integrity system with Chorus acoustic technology, combined with downhole temperature and pressure sensors positioned close to the perforation depth. Chorus and its ‘Acoustic Power Spectrum’ was used to establish the injection/fracture point in the Balder during the XLOT and confirm the integrity of cemented casings above and below the Balder.   Fig.3(a): Advanced Extended Leak Off Test. Chorus tracks and classifies the flow behind 13 3/8” through tubing. Deployed riglessly and through tubing, the Chorus Acoustic Spectrum enabled the induced flow classification (no flow, channeling in cement, and fracture flow) in the Balder formation and revealed the fracture initiation points behind the casing. It also confirmed there are no issues with cement seal integrity with accuracy of 15 psi/day pressure failure or 10 ml/min of leak rate.   The XLOT test conducted by the operator showed the main test output list can be extended in cases where Chorus acoustic monitoring is implemented. This case proved that the integration of the downhole data acquisition can be performed with no interference in the traditional XLOT program.     Fig.3(b): Advanced Extended Leak Off Test. Chorus tracks and classifies the flow behind 13 3/8” through tubing. The Chorus Acoustic Power Spectrum visualizes active induced fractures and cement seal integrity behind the casing. The exact fracture depth can be determined and capacity analysis can be performed by monitoring the decay of the acoustic signal over time during the flowing-back stage. Cement sealing can be verified by interpretation of the acoustic signature recorded across the cement barrier.   The above-listed unique datasets can be used today by rock mechanics, well integrity, and well abandonment engineers.   With the right combination of technologies, good planning and execution, the operation was successful and results were confirmed, in addition to validating the sealing Green Clay intervals, a stress contrast of 11 points, and proving this new permanent P&A concept (details in SPE). This enabled the consideration of the shale barriers such as Balder for permanent P&A.   Decommissioning a well securely and permanently requires both an accurate P&A program and the use of alternative barriers to ensure long-term, sustainable integrity. It is essential to use proven verification techniques to inform the P&A program and validate the seal integrity of critical barriers.  

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.”

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.