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.

Challenge Hydraulic fracturing creates a system of fractures by applying a high differential pressure to the formation. The proppant used to keep the induced fractures open may flow back into the well or to other parts of the well system. The ability to monitor proppant flow gives operators a clearer understanding of well behaviour and helps them to optimise the design of hydraulic fracturing operations elsewhere in the field.   Until now diagnostics have not been able to locate solid particle inflow intervals. The focus of this project was to devise and deploy acoustic technology that would deliver reliable results and identification of proppant backflow zones. Sand Flow precisely locates sand entry to the wellbore and provides a qualitative sand count, clearly identifying problem zones, even in turbulent flow conditions. Solution TGT’s Sand Flow product is designed to identify the locations where solid particles are entering the wellbore and to provide a assessment of solid particle count. Sand Flow is delivered by the True Flow diagnostic system using Chorus technology. Using time-domain not frequency-domain, the Chorus diagnostic system approach is entirely different for Sand Flow versus other Flow products.   The Chorus platform acquires acoustic signals associated with the impact of solid particles on the body of the tool. It uses a neural network to analyse this acoustic signal and thus to identify proppant backflow intervals. This well had an interval of possible proppant backflow where a hydraulic fracturing job had been performed in one out of three zones. This case was a field test to determine TGT’s ability to detect solid particles in flow. Chorus platform confirmed that Zone 1 and Zone 2 were producing fluid, but no solid particles (proppant). Whereas, Zone 3, which had been previously hydraulic fractured, was producing a little fluid but a large volume of proppant. Result Analysis of the time-domain Chorus data conducted in TGT’s Maxim digital workspace pinpointed the proppant inflow interval in Zone 3 (See logplot) and provided a qualitative solid particle count. The case also used the Total Flow product which indicated there was fluid inflow at zones 1 and 2, but not at zone 3.   Proppant backflow was identified exactly where the operator had conducted hydraulic fracturing, which is a clear indication that the fracture was not working as per the design intent. Hence the hydraulic fracturing needed complete reassessment and re-design.   Combining the assessment of solid particle flow intervals with the determination of the fluid inflow profile will greatly improve hydraulic fracturing.

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.

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.

Challenge In commingled injection schemes, it is essential to determine the distribution of injection rates among the different layers. This is traditionally achieved using conventional production logging surveys. Cost is also an issue, as operators have to cover the costs of the survey and the mobilisation of crew and equipment to the wellsite. In addition, conventional surveys have a small associated health, safety and environment risk because production logging tools have to be run inside the wellbore during active injection. Consequently, the industry is always seeking accurate and cost-effective injection profiling methods that reduce health, safety and environmental risks and utilise existing resources. Fibre Flow is commonly used to diagnose unexpected or undesirable well system behaviour, but it can also be used proactively to ensure the well system is working optimally. Solution Flow profiles can be determined by interpreting temperature data acquired from a permanently installed downhole fibre-optic cable but, until now, accuracy has been a limiting factor. This technique, referred to as distributed temperature sensing (DTS), is an effective alternative to conventional production logging methods. After initial installation, permanently installed DTS systems have no associated mobilisation costs and eliminate the risks of well interventions.   The well in this example is a vertical water injector in the Middle East. It was drilled and completed as a cased-hole perforated injector and had an optical fibre permanently installed on the outside of the casing. Water is injected into three sandstone layers, each with different permeabilities, that are interbedded with shale units. Petroleum Development Oman selected TGT’s Fibre Flow product to quantify the flow profiles in the well system through temperature modelling of DTS data. Fibre Flow is delivered by the True Flow diagnostic system using Cascade flow modelling technology. TGT’s Fibre Flow product revealed that most of the injected water entered the bottom zone (A3) and identified a downward crossflow from A1 and A2 into A3 under shut-in conditions. Result TGT’s Fibre Flow product delivered accurate, quantified injection rates for three different zones (A1, A2 and A3) in the subject well.  It also revealed the presence of downward wellbore crossflow under shut-in from zones A1 and A2 into A3. The crossflow was identified by studying the ‘warm-back’ effect in the DTS shut-in temperature as it shifted towards the average near-wellbore temperature. The Fibre Flow results were seen to be in good agreement with a conventional production logging survey that had previously been run in the well.   Fibre Flow has the potential to unlock the value of fibre-optic systems that are already installed in thousands of wells. Using existing built-in monitoring systems means the operator is maximising available resources and installation investment. Also, avoiding an intervention significantly reduces the carbon-footprint of the survey. In this case, Fibre Flow helped the operator to make better use of the fibre-optic systems already installed in the well and enabled it to assess important well performance criteria, including validating correct water injection.