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

Challenge 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.

Challenge The gas-lift producer in this case study had been shut-in due to sustained annulus pressure (200 bar) and excessive volumes of H2S that could not be handled by the production facilities. The operator wanted to assess primary barrier integrity and guide a workover programme. Traditional diagnostics methods, such as production logging tools (PLT) and temperature logs, were deemed inefficient because they could scan only the production tubing and were unable to confirm the integrity of the packer and production casing. Identifying and shutting off the source of the water with high H2S content would protect the environment and deliver a production gain of 2,050 barrels of oil per day (BPD). Eliminating the production of highly toxic H2S and ensuring its containment within the well system would also deliver important environmental and safety benefits. Figure 1: Failures in the gas-lift mandrels (or gas-lift valves) were indicated by Chorus spectral acoustic diagnostics. Conventional production logging tools failed to identify any of these leaks. Solution TGT’s True Integrity system with Chorus technology uses spectral acoustic methods to assess barrier sealing performance. The system offers a large scanning radius and the sensitivity to detect even small leaks. The ability to indicate failures in the tubing, in the casing behind the tubing, and in key completion components such as the production packer and gas-lift mandrels makes this technology highly effective at establishing the best approach for remediation when barrier failures occur.   High precision surveys across the reservoir zone characterised the flow and its content, thereby guiding operations for shutting off the water zone with high H2S content. Traditional PLT methods would not have been enough to make this identification as the water source may be above or below the perforated interval. The diagnostics also revealed the effectiveness of cement sealing across the reservoir zones. Figure 2: Reservoir crossflow under shut-in and bleed-off conditions. The zone at 13,440 ft shows flow upwards and downwards and charges the wellbore with water. This zone was isolated using a straddle packer. Result The Multi Seal Integrity product with Chorus technology revealed leaks in all four of the well’s gas-lift mandrels (Figure 1). Having confirmed that the failures were only in the mandrels, the operator changed them using the slickline, thereby eliminating the issue of sustained annulus pressure. Traditional sensors, such as spinner, resistivity and capacitance had not identified an issue in the mandrels, which indicates that the leaks were below their detection thresholds.   TGT’s diagnostics solution also identified an active crossflow between the perforated intervals in this well (Figure 2). The direction and content of the crossflow were determined, indicating which zone had to be isolated. Verifying cement integrity behind the casing enabled the operator to select a cost-effective isolation programme that involved running straddle packers across the interval that was producing the water containing H2S.   After the workover, the well returned to H2S-free production with oil rate increased by 2,050 BPD and reduction in water cut from 96 to 80%. Increased oil production at a reduced water cut boosts recovery efficiency, enabling the operator to extract hydrocarbons in a shorter time period, and to reduce energy consumption and carbon- per-barrel over the life of field. In addition, having less water to manage and treat at surface reduces the energy requirement and emissions associated with these processes.

Challenge High water cut in producing wells leads to unnecessarily high carbon dioxide emissions and increased carbon-per-barrel rates. Managing, treating, and reinjecting or disposing of excess water requires large amounts of energy, making water cut reduction a key area for performance improvement. Well OP-1 was completed in 1971 as a vertical oil producer and it features a large number of perforated zones from numerous campaigns over the course of its operational history. The oil production rate was approximately 100 bpd, which was considered uneconomic, and the operators decided to switch the completion zone to boost production and enhance recovery from the field.   Following a workover in December 2018, the well was put back on production from the new completion zone (B2), but unexpected water production was observed. The total liquid rate was more than twice the projected level and the water cut was about 80%. The production gas–oil ratio at the separator was lower than expected when compared with a PVT analysis of the B2 zone in a nearby well. Furthermore, water analysis results for well OP-1 were close to the existing results from other completion zones, which indicated substantial water entry from an unknown source. Figure 1: Pre-workover diagnostics survey reveals that the main source of water is non- perforated water-bearing Zone B1. Solution Conventional production logging tools such as spinner and multiphase sensors can provide a production profile inside the wellbore, but cannot identify behind-casing communication with water-bearing formations or crossflow.   The field operator selected TGT’s Total Flow diagnostics to determine whether behind-casing crossflow was the cause of high water cut in well OP-1 and to locate the water source. The combination of TGT’s Chorus spectral acoustic survey with standard production logging tools enabled the survey team to identify behind-casing flow (Figure 1). TGT’s Indigo and Cascade technology was also used to quantify the low flow rates. Figure 2: Post-workover survey confirms the effectiveness of the remedial work and the elimination of water entry from Zone B1. Result Analysis of the survey results indicated that the crossflow from the previously isolated perforated zones was less than 1% of the total. About 30% of the liquid inflow was coming from the targeted perforated interval (Zone B2). The main unwanted production (approximately 69%) was coming from the non-perforated water-bearing Zone B1 and was the result of behind-casing crossflow (Figure 2). A remedial workover was conducted in September 2019 to address the crossflow issue. A cement evaluation log showed that the cement condition above the Zone B2 perforation interval was improved and a successful pressure test (3,000 psig) against Zone B2 was performed. The productive Zone B2 was stimulated once more using a revised procedure.   A flowback test conducted before the second survey showed that there had been a significant decrease in water production with time, and water cut was 0% in the post-workover survey. Both Chorus and Indigo data analysis confirmed that inflow was from only the targeted interval with no evidence of behind-casing communication with Zone B1 (Figure 3).   TGT’s True Flow enabled the field operator to identify the water source and shut it off, thereby increasing oil production, lowering carbon intensity and improving well economics

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.

A new flow-diagnostics resource delivers continuous flow profiles across a variety of completion and reservoir scenarios, including fractured formations. Article featured in Harts E&P Magazine   Horizontal wells offer increased reservoir contact and generally deliver much higher levels of productivity than their vertical counterparts, but these performance gains come at a cost. Managing horizontal wells and understanding their interactions with the reservoir are extremely complex challenges for petroleum engineers and asset management teams. New diagnostics technology from TGT, specifically designed to assess flow in horizontal wells, can deliver a much clearer picture of well system behavior.   Operating companies want to maximize hydrocarbon recovery in the safest, cleanest and most economical way possible. To do this, they need reliable information on fluid behavior within the well system, that is, the wellbore and the immediately surrounding reservoir rocks. Having an accurate picture of fluid flow in these areas gives teams greater confidence in the decisions they take to enhance production, maximize recovery and rectify well problems.   Flow analysis in horizontal wells is notoriously challenging. Variations in well angle and the extended reservoir contact as well as the presence of mixed fluids and segregated flow, formation changes, fractures and intricate completions all add to the complexity. Conventional production logging tools designed for flow assessment in vertical wells often struggle to deliver what is required.   Under favorable conditions, production logging technology may be able to map the multiphase flows encountered in a horizontal wellbore, but it cannot quantify the flow of fluids exiting or entering the reservoir behind the completion. This means that teams that rely exclusively on flow profiles from wellbore production logs are not seeing the true flow dynamics across the well system. Basing development, production or remediation plans on an incomplete or incorrect flow diagnosis may lead to flawed decisions, lower productivity and reduced asset performance.   More accurate horizontal flow diagnostics  For many years, petroleum engineers have been looking for ways to overcome the drawbacks of conventional production surveys in horizontal wells. Specifically, they wanted a system that could deliver continuous flow profiles across a variety of completion and reservoir scenarios, including fractured formations. The team at TGT has addressed these needs by creating the Horizontal Flow product, which is a new flow-diagnostics resource powered by Cascade3 technology. 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. The basis of this new technology is an advanced modeling and simulation engine that predicts the hydrodynamic and thermodynamic behavior of fluids and their surroundings as those fluids flow through the well reservoir system. Purpose-built for horizontal wells, it combines advanced hydrodynamic (fluid motion) and thermodynamic (heat and energy transfer) modeling technologies to translate temperature, pressure and other well system data into continuous reservoir flow profiles.   Crucially, the flow profiles produced reflect flow into and out of the reservoir, thereby delivering a true picture of inflow and outflow in even the most challenging wells, including those with natural or hydraulically induced fractures. This is important because, although fractures can boost the performance of a well or reservoir, they can also provide pathways for water or gas breakthrough. The new technology evaluates all three common types of flow pattern (radial, spherical and linear/fracture) encountered in horizontal well systems. This makes it possible to provide an accurate assessment of the linear flow that is occurring in fractures and to determine fracture contribution. This is particularly useful when combined with the Chorus acoustic sensing system that identifies fracture locations along the wellbore.   Armed with detailed insights into the complex flow regimes in well systems, asset teams can manage well and reservoir performance much more effectively. The new approach enables them to Establish reliable flow profiles; Locate water or gas breakthroughs; Reduce carbon footprint; Maintain a more accurate reservoir model; Measure effective pay length; Make more accurate reserves assessments; Reveal crossflows; Assess inflow control devices and packers; Assess fractures; Make more accurate production forecasts; and Optimize completion designs.   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 of key parameters can help reservoir engineers to resolve uncertainties, improve history matching and optimize their dynamic reservoir model.   Horizontal wells represent a significant resource investment. Production engineers, reservoir engineers and the wider asset team need to ensure that each well system performs to expectations by achieving production targets and maximizing recovery. TGT’s new Horizontal Flow diagnostics technology solves key challenges and helps keep well and reservoir performance on track.