"Horizontal wells can be both challenging and rewarding." Article featured in Oil Review Middle East (article link)   Managing their performance is a complex task for petroleum engineers and asset teams. But, with the right strategies in place, a horizontal well will usually deliver much higher levels of productivity than could be achieved with a vertical well. TGT’s new Horizontal Flow diagnostics technology has been designed to assess flow in horizontal wells and to deliver a clearer picture of well-system behaviour.     Flow inside the wellbore of a horizontal well can be challenging to decipher, but flow outside is even more complex, and way beyond the reach of conventional production logging (PL) surveys. For years, petroleum engineers have been searching for better survey options in horizontal wells and for systems that could deliver continuous flow profiles across different completion and reservoir scenarios. TGT has addressed these needs with its Horizontal Flow product, an advanced flow-diagnostics resource powered by Cascade3 technology.     This innovative technology features a powerful modelling and simulation engine that predicts the hydrodynamic and thermodynamic behaviour of fluids and their surroundings as those fluids flow through the well-reservoir system. Horizontal Flow is specifically designed for use in horizontal wells and, using the industry’s most advanced hydrodynamic and thermodynamic modelling technologies, it can translate temperature, pressure, and other well-system data into continuous reservoir flow profiles.     These profiles deliver a true picture of inflow and outflow even in challenging wells, such as those with natural or hydraulically induced fractures. The new technology evaluates the common types of flow pattern encountered in horizontal well systems (radial, spherical and linear/fracture), thereby making it possible to assess the linear flow occurring in fractures and to determine fracture contribution. This is particularly useful when combined with the Chorus acoustic sensing system that identifies fracture locations.     Horizontal Flow helps asset teams: • establish reliable, continuous flow profiles • locate water or gas breakthroughs • reduce carbon per barrel • maintain a more accurate reservoir model • measure effective pay length • make more accurate reserves assessments • reveal crossflow problems • evaluate the performance of inflow control devices and packers • assess fractures • make more accurate production forecasts • optimise completion designs.     Production engineers, reservoir engineers and the wider asset team need to ensure that each well system performs to expectations by achieving production targets and maximising recovery. Effective management of horizontal wells can deliver huge production benefits. TGT’s new Horizontal Flow diagnostics technology offers clearer insights and helps keep well and reservoir performance on track.

Challenge Multistage fracturing is a highly effective development strategy for ultralow- to low-permeability reservoirs. However, in uncemented completions with fracturing sleeves and packers, it can be challenging to identify fracture initiation points and confirm the number of fractures initiated in each treatment.   A lateral wellbore in a horizontal gas producer was completed with more than 3,000 ft of open hole (OH) section across five fracturing stages in a high-temperature and high-pressure tight-gas interval. This well presented several key challenges.   With OH intervals ranging from 200 to almost 1,000 ft, the operator could not be sure how many fractures had been created or where precisely these fractures were located. The initial stage plan was not sufficient to guide packer placement. Placement had to be decided in conjunction with the caliper log and gauged hole analysis. Interstage communication owing to packer bypass or ball failure is a common problem in completions of this kind. This can be caused by higher differential pressure being exerted on the packers during fracturing. Figure 1: Active frac ports and fracture distribution across all stages and three bypassed packers. Solution Fracture Flow is delivered by TGT’s analysts and engineers using the True Flow system with Chorus and Cascade platforms. Integrating insights from a Chorus acoustic survey and Cascade temperature and flow modelling with the production logs, OH logs and calculated rock mechanical properties provides a better understanding of the fracturing process, completion performance and production performance in an OH multistage fracturing completion.   Chorus acoustics and Cascade flow modelling provided a quantitative assessment of flowing fractures and stagewise production from the reservoir behind the liner.   Multi-array production logging results quantified the flow and flow profile inside the horizontal liner. The integration of datasets was conducted in a single deployment to deliver a comprehensive understanding of well completion and production, including clear identification of water-producing intervals. Figure 2: Flow geometry and contribution across the horizontal section. Result The Fracture Flow diagnostic programme evaluated the active fracture ports and fracture contribution in each stage. It also enabled the team to assess the packers, completion integrity, and production distribution behind the liner (Figure 1). Multi-array production logging was used to investigate the flow profile entering the liner.   The survey results identified 34 active fractures and showed that some flow was bypassing several packers. Figure 2 shows the reservoir flow profile provided by Cascade and the True Flow system. Most fractures were clustered around Stage 4 and Stage 5, and this had a major impact on production. Survey results revealed good completion integrity overall, with only three bypassed hydraulic packers. The dual packer isolation systems were shown to prevent communication between contributing stages.   Based on the comprehensive analysis result the water being produced from all fracture entry ports except Stage 5, where water contribution was minimal. Engineering work decreased the water–gas ratio to 5%.

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.

Dubai, U.A.E – 22 February 2022   TGT’s Horizontal Flow diagnostics powered by the all new Cascade3 technology delivers accurate assessments of flow dynamics in horizontal wells, thereby enabling asset teams to manage well and reservoir performance more effectively.    TGT Diagnostics announced today the launch of ‘Horizontal Flow’ diagnostics with Cascade3 technology. This powerful new system, specifically designed for horizontal wells, provides asset teams with more realistic flow modelling and accurate continuous flow profiles in a wide variety of completion and reservoir settings, including fractured formations.    Horizontal Flow diagnostics underpinned by the all-new Cascade3 flow analysis platform is a purpose-built system incorporating the industry’s most advanced thermodynamic and hydrodynamic modelling codes to transform temperature and other well system data into continuous reservoir flow profiles. Crucially, these flow profiles reflect flow both in and out of the reservoir and thus deliver the most accurate and detailed picture of well–reservoir flow behaviour.    Commenting on the technology, Mohammed Hegazi, TGT’s Chief Executive Officer, said, “Understanding the flow dynamics in a well system is the key to unlocking better well and reservoir performance. This is especially true for horizontal wells where fluid flow can be incredibly complex. Horizontal Flow is the most powerful flow analysis product ever created for horizontal well systems. It overcomes many of the challenges faced with conventional production logs and enables operators to maximise hydrocarbon recovery while operating in the safest, cleanest and most economical way possible.”    Improved understanding provides a much-needed opportunity to optimise performance, as Ken Feather, TGT’s Chief Marketing Officer, explains: ‘’The transition towards cleaner energy and declining opportunities for new field developments means that operators are shifting investments towards recovering more from existing assets. Horizontal wells promise enormous efficiency and economic gains but are notoriously challenging to manage. Horizontal Flow with Cascade3 solves many of the diagnostic challenges faced by Reservoir and Production Engineers, providing them with the insights they need to reduce operating costs and energy consumption, and increase ultimate recovery.’’    The complete and accurate downhole assessment Horizontal Flow with Cascade3 offers means that diagnostic deployments can provide a wealth of information from a single programme, thereby reducing uncertainty and avoiding the need for subsequent deployments. Yulia Fesina, Cascade project manager, said “The Cascade3 workflow can also be used to estimate or validate other key parameters that reservoir and production engineers may find extremely valuable, including reservoir pressure, permeability and skin factor. This independent verification of key parameters can help reservoir engineers to resolve uncertainties and improve history matching and dynamic reservoir models.”    Horizontal Flow diagnostics are now available to upstream operators through TGT’s comprehensive range of True Flow answer products. 

Challenge The subject well was not reaching its planned gas production rate, so the field operator wanted to investigate the issue and identify the root cause. The assumption was that both the hydraulically fractured reservoir zones were contributing to production, thus the first task was to assess the relative contributions of gas from each layer. Water production was also an issue and can be a critical problem in a gas well. The second challenge was, therefore, to identify where water was entering the well in order to plan a workover operation.    The tubing installed in this gas producer well extends below the bottom perforation interval, which means that conventional production logging tool surveys cannot help with evaluation. 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 subsurface team of reservoir and petroleum engineers at AGL Energy Ltd selected TGT’s Total Flow product to locate and quantify wellbore and reservoir flow and reveal the relationship between the two. Delivered by the True Flow system with Chorus and Cascade technology, Total Flow provides the clarity and insight operators need to manage well-system performance more effectively. Total Flow is commonly used to diagnose unexpected or undesirable well-system behaviour, but it can also be used proactively to ensure that a well system is working properly.   In this case, the combination of Cascade flow modelling and Chorus acoustic sensing enabled TGT analysts to generate an accurate multiphase flow profile for the well and provide the operator with a clear picture of what was happening behind the casing and below the survey interval. The maximum survey depth during the flowing regime was X204 m, which means that the bottom perforated interval (X207–X209 m) was not surveyed. The TFM curve shown in the TEMPERATURE track is the modelled flowing temperature profile. It is matched with TEMP_F1D1 down to the maximum surveyed depth and shows the assumed temperature behaviour below this depth. Result The temperature simulation and flow modelling results from TGT’s Cascade platform identified the main inflow zones and showed that 48% of total gas and 44% of total water were entering the well from the bottom perforated interval. This indicated that about 93% of the total gas flow rate and 100% of the water was from the bottom-zone Wallabella Sandstone Formation. The upper fractured zone (the Tinowon reservoir) was not making a significant contribution to gas production, thus the well could not reach its planned production performance.   The operators can apply these insights to develop an effective plan for future workover and stimulation tasks.   The small volume of gas produced from the Lower Tinowon Sandstone Formation is the result of behind-casing channelling, which would not have been identified by conventional production logging tools.