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.

Sandbar is a joint solution with Tendeka that delivers precise, reliable and effective downhole sand remediation.Background Sand production from oil and gas reservoirs is a serious issue. It can decimate productivity and erode the integrity of well completions and surface assets. Often, the first indication of sanding issues downhole are the detrimental effects that can occur at surface, such as fill in separators or erosional damage to pipework.   Thru-tubing remediation typically involves an interval approach for a problem which may be localised. Historically, this is because there is a duality of issues in the ability to accurately identify the location of sand ingress and to target a localised fix. Surface monitoring can detect when sand is being produced, but locating the source and dynamics of sand inflow downhole is essential to protecting integrity and maintaining production.   Tendeka and TGT’s combined “Sandbar” sand remediation solution addresses all of these issues to offer a more precise, reliable and effective intervention-based solution. It follows a simple process flow of "Find, Fix, Confirm". Technology in Action TGT’s Sand Flow product precisely locates sand entry to the wellbore and provides a quantitative sand count, whilst Tendeka’s Filtrex remedial sand control system is precisely targeted to repair the damage. Crucially, Sand Flow is then redeployed to confirm the repair.   Find Sand Flow diagnostics are delivered using TGT’s “True Flow” system and the “Chorus” acoustic sensing platform. Chorus is deployed on wireline, capturing and decoding the acoustic signature generated by sand particles entering the wellbore and impacting the tool. It analyses the acoustic time-domain data to discriminate between sand flow and fluid flow, thus locating the sand entry points and quantifying the sand rate.   Fix Tendeka’s Filtrex is deployed into the well on coiled tubing and positioned across the target area. Dropping a ball in to the string allows pressure to be applied in two stages, firstly to set the anchor, and secondly to release the compressions sleeve. Upon removal of the compression sleeve, the matrix polymer expands to contact the wellbore and the deployment string can be retrieved from the well.   Confirm The same diagnostics are run in the “Find” scenario, but this time deployed through the internal diameter of the Filtrex system to confirm that no sand is entering at that depth. Value to your business One-stop diagnose, fix, verify solution Restore integrity and productivity Reduce intervention time Improve resource efficiency, lowering emissions Reliable and cost-effective sand control Sandbar brochureSandbar Tech brief Sandbar - joint sand remediation solution with Tendeka Tendeka's Filtrex solution

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 Solid particles can be transported from the reservoir into the wellbore when an oil or gas well is flowing. These particles may be natural solids such as sand grains or proppants that were injected into the reservoir during hydraulic fracturing. Identifying the sources of solids entering a well is a vital first step to controlling the problem.   This well is a deviated producer in a giant natural gas field in the South China Sea. Drilled and put on production during 2010, the well was found to be producing sand at about 120 cm3/hr in 2017, which resulted in the well being shut in. The operator wanted to identify and eliminate the sources of sand and resume production. Well sketch shows a range of scenarios where sand is entering the well, that Sand Flow can evaluate. Solution The integrated programme and method used to assess fluid and sand inflows, combined high-sensitivity spectral acoustic logging and high-precision temperature measurements. The operator selected TGT’s Sand Flow product to characterise sand production. Sand Flow is designed to identify the locations where sand enters the wellbore and to provide a qualitative assessment of sand count. It is delivered by the True Flow diagnostic system using the Chorus acoustic platform together with high-precision temperature measurement.   Chorus locates sand production intervals by detecting the signals generated by solid particles striking the housing of the acoustic logging tool. The acoustic data was analysed in a time domain and the specific signals associated with primary strikes of solid particles (sand grains) against the tool housing were identified.   The programme and method for acquiring data required two different steady state production regimes: with the choke 40/64 in. (flowing regime 1) and 26/64 in. (flowing regime 2) to find the optimum well operating regime. Acoustic data output, used for detecting the sand production source Result The highest number of high-energy sand grain strikes against the tool housing was registered opposite the zone 3 perforation interval during the flowing 1 regime (See logplot). Strikes across this interval reached 60 grains/s and the volume of sand produced at surface varied from 40 to 90 cm3/h. Reducing the pressure drawdown (switching to the flowing 2 regime) reduced the number of primary sand grain strikes at zone 3 to 40 grains/s.   Some (secondary) sand grain strikes were caused by sand grains in a turbulent gas-water flow along the wellbore and not by lateral sand production flow from the reservoir. Their energy and number are much lower than those of strikes recorded at zone 3. These are shown as blue points on the sand energy panel.   Based on the spectral analysis of the Chorus acoustic data, it was determined that zone 1 and zone 2 were the main contributors of gas production, but these intervals were not found to be the sources of sand production to the surface. Zone 3 was found to be the only sand producing interval knowing the sand entry location at different well operating regimes, the operator was able to determine and implement an optimum well operating regime that minimised the impact of sand production.

Go with the flow Article featured in Oilfield Technology's 2022 summer magazine (pages 42-45)   As the global energy mix transitions to low-carbon sources, there may be fewer opportunities for new oil and gas field developments. As a result, many operators will shift their focus towards recovering more from existing reservoirs, and this strategy includes improving the management and performance of their Horizontal wells.   Horizontal wells generally deliver much higher levels of productivity than their vertical counterparts, but this performance can often come at a cost. Understanding the interactions between a horizontal well and the reservoir can be extremely challenging. The combination of variable well angles, extended reservoir contacts, the presence of fluid mixtures and segregated flows, formation changes, fractures and intricate completions presents a formidable challenge for analysis using conventional production-logging tools (Figure 1).   Standard production-logging technology may, under some conditions, be able to map the multiphase flows encountered in a horizontal wellbore, but it cannot quantify flows for fluids exiting or entering the reservoir behind the completion. This means that wellbore production logs do not provide a complete picture of flow dynamics across the well system. Asset teams that base development, production or remediation plans on an incomplete partial flow diagnosis may be risking lower productivity, reduced asset performance, and higher carbon overhead.   A new beginning Reservoir and production engineers have been looking to overcome the drawbacks of conventional production surveys in horizontal wells for many years. Their key requirement has been a system that could deliver continuous flow profiles across different completion and reservoir scenarios, and would also be effective in reservoirs with fractured formations.   TGT Diagnostics has been working on addressing these needs for several years and, in February 2022, launched the Horizontal Flow diagnostics product with Cascade3 technology. Specifically designed for horizontal wells, this system offers more realistic flow modelling and accurate continuous flow profiles in a wide variety of completion and reservoir settings. The insights gained from this have the potential to help companies reduce operating costs and energy consumption while increasing ultimate recovery.   The new technology uses an advanced modelling simulation engine to predict the hydrodynamic and thermodynamic behaviour of fluids and their surroundings as they flow through the well-reservoir system. This translates temperature, pressure and other well-system data into continuous reservoir flow profiles. These profiles deliver a true picture of inflow and outflow, and this is the case even for challenging wells and those that feature natural or hydraulically induced fractures.   The ability to assess flow in fractured reservoirs is important because, although fractures can boost hydrocarbon production, they can also provide pathways for early water or gas breakthrough. The new diagnostics technology can evaluate the radial, spherical and linear/fracture flow patterns commonly encountered in horizontal well systems (Figure 2). This provides an accurate assessment of linear flow occurring in the fractures and makes it possible to determine the fracture contribution. This is particularly useful when combined with the Chorus acoustic sensing system that identifies fracture locations along the wellbore.   Applications and benefits Operating companies want to maximise hydrocarbon recovery in the safest, cleanest and most economical way possible. Having an accurate picture of fluid flow in the wellbore and the immediately surrounding reservoir rock gives asset teams greater confidence in their decisions and makes it easier to enhance production, maximise recovery and rectify well problems.   The new diagnostics system provides useful input in key areas such as reservoir, well and resource management, and can even help companies enhance their environmental performance and reduce the carbon footprint of production operations.   Insights for reservoir management Effective reservoir management is a key objective for oil and gas operating companies. The development of any hydrocarbon reservoir disturbs a natural balance of rocks and fluids that may have existed for millions of years. Understanding how a reservoir will behave as new wells are drilled and fluids are extracted or injected is a daunting task. Reservoir engineers deal with huge uncertainties in their quest to maximise hydrocarbon recovery, reduce operating costs and extend the economic life of the reservoir.   At the heart of the reservoir-management process is the dynamic reservoir model, which provides a basis for all field development and hydrocarbon recovery decisions, infrastructure investments and reserves estimations. The robustness and accuracy of the model is critical to successful reservoir management, and any inaccuracies may lead to poor decisions and substantial losses.   As more data is collected, the dynamic reservoir model is updated by the reservoir engineering team using a process known as history matching. Insights from this new diagnostic system can play a critical role in history-matching, thus helping to reduce the uncertainty envelope and improve the model. A continuous flow profile provides a clear and direct quantification of the flow performance of the reservoir as it feeds the well system. In contrast to standard wellbore production surveys, which can be hindered by completion or reservoir integrity issues, Horizontal Flow can deliver a true flow profile. The continuous nature and sensitivity to low flow rates help provide a more accurate measurement of effective pay length, a key metric for making production forecasts and reserves estimates.   The new system is also effective in the presence of fractures. Predicting and preventing water or gas breakthrough is one of the most important and challenging tasks faced by reservoir engineers. Having a deeper understanding of downhole flow dynamics can help provide an early warning of locations where water or unwanted gas may be reaching the well.   The new workflow can also be used to estimate or validate other key parameters such as reservoir pressure, permeability and skin factor. This independent verification can help reservoir engineers to resolve uncertainties, improve history matching and optimise the dynamic reservoir model. Figure 1. Horziontal Flow leverages Cascade3 and the True Flow system to deliver the truest picture of inflow and outflow downhole, even in the most challenging wells. Figure 2. Flow inside the wellbore of a horizontal well can be challenging to decipher, but flow in the surrounding reservoir is equally complex. New technologies can help resolve all three primary flow patterns that surround the well system - radial, spherical and linear flow in fractures - and combines thermodynamic and hydrodynamic science in an immersive 3D fine grid modelling architecture. The result is accurate reservoir flow profiles and unique insights that help asset teams keep performance on track. A diagnostic approach to well management Horizontal wells are designed to provide optimum contact with the reservoir and so tap hydrocarbon reserves with maximum efficiency. Production engineers in the wider asset team are responsible for the well system and ensuring that it performs to expectations, thereby maintaining production targets and maximising recovery.   Well performance depends under dynamic relationship between the well completion and the reservoir surrounding it. This, in turn, depends on the performance and behaviour of completion components and the reservoir itself. To achieve their technical and business aims, production engineers need full visibility of fluids and flow dynamics downhole from the reservoir sandface to the wellbore and at all points in between. The Horizontal Flow diagnostic system helps to deliver this visibility.   Measuring real production or injection performance in the presence of complex multicomponent completions is a major challenge for production engineers. Integrity issues and zonal isolation or component failures can lead to discrepancies between the profile of fluids entering or exiting the wellbore and the profile of fluids exiting or entering the reservoir. In these situations, standard production logs could give false or misleading results. The new diagnostics system overcomes this by providing a definitive flow profile regardless of completion, integrity or zonal isolation issues. Furthermore, by identifying these issues, it can help guide maintenance or workover interventions. Vicious fluids, fluid segregation and low flow rates can also be problematic for standard production-logging sensors, leading to a false picture of flow. Horizontal Flow incorporates temperature and acoustic measurements that respond to all types of meaningful flow, thereby helping to overcome this limitation.   The new approach can also be used to assess injection compliance and the performance of completion elements such as flow control devices and swell packers. The information gained from these analysis can be used to target repairs and guide potential improvements in completion designs.   Enabling effective resource management Operating companies want to maximise ultimate recovery while minimising operating costs, thereby reducing cost per barrel produced. Horizontal Flow diagnostics can help on both sides of this equation.   Developing a field with horizontal wells represents a significant investment in time, energy and capital. Diagnostics play a key role in tracking well and reservoir performance, and steering asset team decisions. Horizontal Flow diagnostics can reveal well system inefficiencies, guide asset teams to problem areas in the completion or the reservoir, and help them act with greater certainty to achieve a positive outcome.   Horizontal well interventions can be expensive and time-consuming, and often require specialised equipment, such as coiled tubing or tractors, for well access. Diagnostic deployments of the new system can provide a complete and accurate downhole assessment and information that reduces uncertainty and quickly establishes whether remedial work is required. When a workover is deemed necessary, the ability to plan and target it with a greater precision helps save time, reduce costs and deliver better outcomes.   Reducing your environmental impact Operating companies around the world are aiming to cut their carbon-per-barrel overhead. Developing and producing oil and gas consumes enormous amounts of energy from diesel engines or gas turbines, both of which produce significant volumes of carbon dioxide (CO2). Flaring of unwanted associated gas is another major source of emissions. Combined CO2 emissions from global upstream operations are estimated at about 1 Gt CO2 per year and methane emissions at around 1.9 Gt CO2 per year. New diagnostics technology can help operators identify inefficiencies in energy-intensive operations, reduce associated gas flaring and improve the efficiency of energy-intensive intervention operations.   Water injection accounts for approximately 40% of total CO2 emissions in a typical oilfield. Operators can now assess how much of the injected water is reaching its target and identify thief zones. These diagnostic surveys often lead to a reduction in pumped water volumes and emissions, and increased field production. Water production is another source of emissions, as produced water must be managed and treated at the surface. This process requires energy, and increased water production typically means less oil, thus reducing ultimate recovery and increasing carbon per barrel.   Gas flaring is estimated to release 310 MT CO2 per year, which is about 30% of all upstream CO2 emissions. Continuous flow profiles can be used to identify sources of unwanted gas downhole and guide remediation plans, thereby reducing the need to flare.   Workovers and diagnostic interventions in horizontal wells can also have a significant carbon overhead. New diagnostics technology can minimise this overhead on two fronts when compared with the conventional approach.   Firstly, it can easily identify the crossflows, fractures and integrity failures that often confuse conventional surveys. Having this information minimises the risk of incomplete or inaccurate assessments and improves the efficiency of decision-making. Secondly, when equipped with reliable information, the asset team can plan and target its workover programmes with precision. This means equipment and operations can be optimised and executed with higher efficiency and success rates, leading to better technical outcomes and lower emissions.   Conclusion Horizontal wells are powerful tools for hydrocarbon production and represent a significant resource investment for field operators. Production engineers, reservoir engineers and the wider asset team face complex challenges in their drive to ensure that each well system performs to expectations. A new approach to flow analysis in horizontal wells could help to solve key challenges in this area, making it easier for wells and reservoirs to reach their full potential.