13 Search Results for “ Rock”

Refine search results

  • dot
    Case studies
    CS035 Fracture Flow

    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%.

  • dot
    Go with the flow

    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.

  • dot
    Rising to the Challenge of Flow Assessment in Horizontal Wells

    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.

  • dot
    Safe and Sound P&A. Decommissioning wells using acoustics

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

  • dot
    Harts E&P’s 40 Under Forty Award

    Artem Khasanov, TGT’s QHSE & Testing Laboratory Team Leader is an honoree in Hart Energy’s E&P 2021 “40 Under Forty” recognition program Article featured in Harts E&P Magazine   From an early age, Artem Khasanov was interested in learning how the world works, so he started studying physics and technology. Khasanov studied physics at Kazan Federal University, where he was first engaged in semiconductors research and then, in collaboration with the Kazan Institute of Chemical Technology, was engaged in research of silicone rubbers.   “I am 107% sure (this is an accurately measured value) that the main quality of a researcher and developer is the ability to be a good observer,” he said. “Many secrets of the world are revealed if you are thoughtful enough.”   In 2013 Khasanov started working with TGT as a laboratory assistant, and he became a research engineer a year later. He added, “Once I realized that there is an industry where people who are passionate about technology and research are rewarded well—the oil industry—there was no stopping me!”   In 2019 Khasanov became the head of the testing laboratory. He devoted a significant part of his work to the study and application of ‘acoustics’ in oil and gas wells, as a means to locate and characterize fluid flow. Acoustic technology is a key ingredient in TGT’s diagnostic systems—used by its customers globally to keep wells safe, clean and productive. Career goals “When I started my career, I met so many competent and talented people who strive to innovate and develop new technologies. My first task was to catch up with my peers in terms of competence and knowledge. Now I am studying international quality standards to ensure that our diagnostic systems and products continue to set and exceed industry standards.” Memorable technology projects “I have led several projects that have helped the company advance diagnostic methods and technology. For example, I designed and manufactured laboratory models for researching and developing sophisticated multisensor acoustic devices. I also developed systems to study the acoustic signature of fluids flowing through rocks and barrier leaks, as well as apparatus to study the acoustics of sand production; and automatic testing devices for our diagnostic systems. All of these projects ultimately help our customers make better-informed decisions.” Motivation from within “After a certain age, a person needs to stop looking for a mentor and become one. All the necessary information is available; you should just lend a hand. You don’t need a mentor to make history. All you need is purpose, motivation, and health. And believe it or not, your best advisor is – yourself! One of my guiding principles is, ‘If you are in doubt about what to do, just do what is right.’” Formative experience “The most important thing in any business is to control emotions and direct personal energy to an ultimate goal. Therefore, among the many educational programs I’ve undertaken, one of the most useful was all about emotional intelligence.” Sustainability & decarbonization “Whilst renewable energy sources are gradually increasing, more than 50% of the world’s energy supply still comes from hydrocarbon resources – so the extraction of oil and gas is a necessity. Our mission at TGT is to help the industry keep oil and gas wells safe, clean and productive. We are helping our customers to decarbonize and reduce harmful emissions. I’m motivated by the fact that the diagnostic systems and products that we create make it possible to use the planet’s resources more sustainably.” Industry’s future “I believe that the ultimate goal of any industry is to make our lives healthier, happier and more sustainable. Collectively, we need to find the right balance between maintaining human existence and protecting the planet and other species that live beside us. We need to keep in mind the countless scientists, engineers, analysts and other oilfield workers who dedicate their lives to advancing this vital industry. Digitalization and automation will be important enablers of our future, together with the use of predictive diagnostics to improve the safety and integrity of well systems. “One day, after a couple of hundred years, our great-grandchildren, roasting marshmallows by the fire on Mars, will remember us with gratitude.”   Artem Khasanov, TGT’s QHSE & Testing Laboratory Team Leader

  • dot
    Harts E&P Article – Rolling out a vaccine for oil and gas wells

    Predictive modeling using digital technologies and data analytics will help reduce carbon emissions Article featured in Harts E&P Magazine   If only we could inoculate subsurface wells against future integrity or flow issues it would be a dream come true. But there are many ways to proactively diagnose and keep them healthy and immune from unexpected “disease.”   Never has health been more in the spotlight—the health of our communities and the health of our planet. The pandemic has elevated the world’s focus on the environment and on driving down carbon emissions.   The energy sector has come under intense scrutiny as the world strives to tackle climate change. A major challenge is striking the balance between the continued need for fossil fuels, as part of a wider energy portfolio, while offsetting the associated carbon emissions. Energy outlook The DNV 2020 Energy Transition Outlook estimates that by 2050 oil and gas will account for 74% of the world’s energy-related CO2 emissions (Figure 1) and more than 80% emissions including CO2 equivalents. Emissions from the entire oil and gas value chain is on course to fall one-third by 2050.   The oil and gas sector is not alone in its endeavor; many major world economies have set ambitious goals to reach net-zero emissions by 2050, some even sooner. It is no longer a solitary cause. FIGURE 1. DNV GL predicts that oil and gas will still play key roles in the energy mix in 2050 when their value chains will account for most energy-related emissions. Proactive and predictive diagnostics We are constantly reminded that it is important to visit the doctor for routine checkups to ward off potential issues and/or treat issues early. We all know that prevention is better than treatment. Staying healthy does not only apply to humans or businesses, but also to wells that produce, inject or store hydrocarbons.   The road to net zero has many paths, but keeping wells healthy through proactive monitoring, diagnosing and subsequent remedial work is not only a duty, it’s good business. Furthermore, it would drastically reduce environmental fallouts as well as unplanned costs or reputational damage.   Well diagnostic companies, like TGT, can help. Application-led diagnostic products provide operators with the right information to act in advance and thus reduce potential emissions. A proactively diagnosed well has the best chance of staying healthy versus a well that is only diagnosed when problems start to appear. Optimizing resources But it’s not only about catching leaks and holes, it is also about optimizing resources that can have a detrimental effect on the environment. An activity that has a huge potential for improvement is fluid injection into a well system to enhance reservoir pressure and hydrocarbon recovery. Thousands of barrels of water are injected daily, but is the flow going where it should? On numerous occasions, TGT’s diagnostics have revealed the actual path and volume of injected water is different to the expectation or the plan—and this is sometimes after years of operating. With these findings, operators can reduce the amount of wasted water, cut down on water transportation and treatment, and ultimately reduce their energy intensity and drive down their emissions.   Equally important are idle wells—wells that are either abandoned or neglected. Routinely diagnosing the integrity of these wells to provide assurance they are “quiet” is highly advisable. More often than not, there are signs of subsurface activity. These wells represent a potential emission source that may prove difficult to remedy if neglected further.   A focus in the pursuit of net zero is carbon capture and storage (CCS)—capturing CO2 at the source, compressing it for transportation and then injecting it deep into a rock formation, where it is permanently stored. Routinely diagnosing the integrity of this storage facility to provide assurance that the plug is holding tight and that the CO2 is not migrating to water reservoirs or the surface will become essential, if not a legal requirement. Data are gold Pursuing routine diagnostics of subsurface wells to detect potential issues before they escalate is common sense, but what’s next?   Like many sectors, data are gold. With a wealth of diagnostic data at our fingertips, we can employ digital technologies and methodologies that predict when a diagnosis is needed or when a failure is imminent. With sufficient field or reservoir diagnostic data, we will be able to predict its behavior and failure modes with acceptable accuracy. Predictive modeling using digital technologies and data analytics will help reduce carbon emissions by boosting the energy efficiency of production.   It’s good for the environment and for business to stay healthy. To do this, we need to have a bold and visionary mindset that encourages proactive well diagnostics and soon makes use of predictive diagnostics. “Pursuing routine diagnostics of subsurface wells to detect potential issues before they escalate is common sense, but what’s next?”   Mohamed Hegazi, CEO

  • dot
    Harts E&P Article – 2021 Hydraulic Fracturing Technology Showcase

    Exert from Harts E&P's showcase on the latest hydraulic fracturing technologies and how they aim to address operator challenges. Diagnostics locate flow before or after fracturing TGT’s Fracture Flow evaluates the effectiveness of a fracturing program. It uses the Chorus acoustic platform to record and analyze the acoustic wave propagation in the wellbore and rocks, plus well design information, to determine the location of the acoustic source energy produced by fluid flow in the fractures. When used during pre- and post-fracturing, it can analyze the reservoir flow profiles, qualify flow to or from the fracture network, reveal fracture density and identify unwanted fracture components that impact product. The technique can identify the location and determine the distance of the acoustic signal from the receiver. Combined, these insights offer operators the diagnostics they need to improve their fracturing program, so it can be targeted and optimized to deliver maximum time and cost efficiencies. The logplot shows a horizontal tight sand gas condensate producer, completed with a non-cemented multistage ball-activated application. Stage separation was achieved by a dual hydraulic-activated packer. The results identified the presence of 22 active fractures, 17 were offset from flow ports and five could be aligned with the flow ports producing a unique signature covering a wide frequency range. The fracture distribution varied between stages with an average of three active fractures per stage.

  • dot
    Case studies
    CS018 Fracture Flow

    Challenge Multistage fracturing is an effective stimulation technique for heterogeneous, low-permeability oil reservoirs. However, after a fracturing campaign, there may be a risk of increased communication between the water-bearing formation, which may cause a high water cut in the stimulated well.   In this case from the Volga-Ural region of Russia, the operator wanted to identify unexpected water sources in a horizontal well in a low-permeability carbonate reservoir. The well had been subjected to a multistage acid fracturing job and it was necessary to determine the most effective strategy for a workover to shut off the water producing zones. Well sketch shows flow scenarios before and after fracturing that Fracture Flow can evaluate. Fracture Flow provides the clarity and insight needed to manage well system performance more effectively. Solution The operator selected TGT’s Fracture Flow product to understand the flow dynamics of the well system and identify the water sources. Fracture Flow is delivered by the True Flow diagnostic system. TGT’s diagnostic systems combine several proprietary technology platforms that share a common structure and workflow comprising programs and methods; tools and measurements; processing and modeling; and analysis and interpretation.   The Chorus (acoustic) platform records and analyses the acoustic energy produced by fluid flow; its role in this case was to help pinpoint unexpected flow activity behind casing. The Fracture Flow product uses a multi-sensor tool, adopts a unique data acquisition programme and utilises a processing and modelling software plugin which varies from the other True Flow products.   In combination, the technique is able to identify the location and determine the distance of the acoustic signal from the receiver. It is therefore able to distinguish reservoir flows from those generated by completion leaks. Integrated logging suite results: Acoustic signal source identification Result An acoustic signal was recorded in a narrow interval above the target reservoir. This signal had a broadband spectrum that could have been generated by reservoir flow or by a completion leak (see Line A in Figure 1).   Taking into consideration the well design and the acoustic wave propagation in the wellbore and rocks, TGT’s Chorus diagnostics determined that the location of the acoustic source extended beyond the wellbore. It was deduced that the signal was generated by turbulent flow from an unexpected fracture above the target reservoir. The inflow fluid from this unwanted fracture flowed back down the well completion, entering the wellbore through the topmost perforation. It was this rogue fracture that was the cause of water in the well production.   Thanks to Fracture Flow’s diagnostic results, the operator changed the hydraulic fracturing design programme, to optimise production while preventing the reoccurrence of rogue fractures in the future.

  • dot
    20th Anniversary

    Kazan, Russia, 2018: TGT Oilfield Services, the market leader in through-barrier diagnostic systems, celebrated 20-years of Research and Development and technological advancements.   Mohamed Hegazi, Chief Executive Officer, said: “We are delighted to have reached this milestone, especially in an increasingly competitive market place and at a challenging time in our industry. We enjoyed our celebration with valued employees, partners, and customers from around the world. This achievement is a testament to the uniqueness and strength of TGT ‘s technologies, Geoscience expertise and best in class service delivery”.   “The past 20-years have been an incredibly exciting time for us. We have continuously outpaced the market growth, expanded our geographical footprint and continue to be actively engaged in industry forums and publications. TGT uniquely designs, develops, manufactures and patents its own hardware and software”.   TGT has grown from a small office with a handful of employees, to a company with 12 offices globally, operating in more than 20 countries for more than 40 customers. Mohamed Hegazi, CEO, TGTBringing global colleagues together to celebrateArthur Aslanyan, Founder, TGTTraditional Russian dance To celebrate, TGT invited employees, customers, and business partners to an evening which relived the company’s scientific breakthroughs using acoustic, thermal and electromagnetic energy to reveal unique answers within and beyond the well bore.   Dr. Arthur Aslanyan, TGT’s Co-Founder commented, “It gave me great pride to attend the event and celebrate the company's 20th anniversary. We have come a long way since we first started the business. We are very excited about our future as the company continues to thrive”.   The event was attended by Saad Bargach, TGT Chairman and LimeRock Partners -private equity investors.   Hegazi continued, “Looking to our future, TGT is releasing several lines of new technologies and applications in coming months to further cement our position as pioneers of Through-Barrier Diagnostics. Our patent technology developments coupled with our unrivalled Geoscience organisation and global footprint, provide unique and reliable diagnostic services to our customers. This has been key in maintaining our fast growth trend and industry reputation. I am confident this foundation along with our excellent teams, will continue to fuel our growth for many years to come.

  • dot
    TGT News – Drilling & Completion (Feb 2018)

    Total well system integrity and ‘the containment and prevention of the escape of fluids’ (ISO TS 16530-2) remains one of the biggest challenges Middle East operators face today. The Middle East has been the world’s most prolific oil-producing region for decades with one of the largest populations of ‘hard-working’ aging wells – many of which operate continuously in extreme environmental conditions. More than 70% of the ~800 Middle East platforms and associated well-stock are more than 25 years old.   Not surprisingly, Middle East operators are facing a constant challenge to manage corrosion and sustained annulus pressure [SAP] in their well systems, and are always on the lookout for new innovations to help. This article will provide examples of two such innovations – corrosion surveillance in chrome-based tubulars, and addressing SAP. To celebrate, TGT invited employees, customers, and business partners to an evening which relived the company’s scientific breakthroughs using acoustic, thermal and electromagnetic energy to reveal unique answers within and beyond the well bore.   Dr. Arthur Aslanyan, TGT’s Co-Founder commented, “It gave me great pride to attend the event and celebrate the company's 20th anniversary. We have come a long way since we first started the business. We are very excited about our future as the company continues to thrive”.   The event was attended by Saad Bargach, TGT Chairman and LimeRock Partners -private equity investors.   Hegazi continued, “Looking to our future, TGT is releasing several lines of new technologies and applications in coming months to further cement our position as pioneers of Through-Barrier Diagnostics. Our patent technology developments coupled with our unrivalled Geoscience organisation and global footprint, provide unique and reliable diagnostic services to our customers. This has been key in maintaining our fast growth trend and industry reputation. I am confident this foundation along with our excellent teams, will continue to fuel our growth for many years to come. Overcoming chrome As Middle East well conditions become more corrosive, so operators have looked to more corrosion resistant materials in the completion process, leading to a rise in chrome and nickel content in steel tubulars. However, one unintended side effect is the decrease in the effectiveness of ordinary electromagnetic [EM] well and pipe inspection systems and the tracking of corrosion in multiple barriers.   The increase in chrome and decrease in ferrous content causes EM signals to decay too quickly for such systems to be truly effective in monitoring corrosion and evaluating pipe thickness or metal loss in casing strings. So while corrosion resistance may have increased, there is now a potential information vacuum.   TGT, the market leader in through-barrier diagnostic systems, has developed a new multi-barrier integrity diagnostics system – EmPulse®. The system quantitatively determines individual wall thickness in up to four concentric tubulars, ensuring long-term well performance in the most challenging high-chromium production environments.   The EmPulse system incorporates ‘ultra-fast’ sensor technology, three independent sensors, and ‘time-domain’ measurement techniques to capture EM signals rapidly and accurately in a wide range of pipe materials before the signals decay.   In three recent Middle East deployments – an operator witnessed ‘yard test’ in 28% chrome pipe with built-in mechanical defects, and two live wells – the EmPulse system correctly identified man-made defects and quantitatively determined the individual tubular thickness.   This successful validation in high-chromium tubulars brings important reassurances for Middle East operators in protecting well system integrity – providing accurate corrosion information and addressing a crucial information gap. The case of sustained annulus pressure [SAP] Figure 2: Spectral diagnostics survey revealing source of SAP behind casing at X540m where the cement map indicates ‘good cement’. Another major challenge to Middle East well system integrity is that of SAP – pressure in any well annulus that rebuilds when bled down.   Reasons for SAP can vary but are often due to weaknesses in the cement during completion; cement degradation due to thermal and pressure loading; leaking tubing connections or wellhead seals; and corrosion. According to a 2013 SPE webinar on wellbore integrity [Paul Hopmans], out of ~1.8 million wells worldwide, a staggering 35% have SAP, with many Middle East fields facing varying levels.   Wells with SAP need to be carefully managed and production can be adversely affected or halted. SAP can also cause further damage to the well system, potentially resulting in the failure of the production casing or outer casing strings, and well blowouts.   While many operators are addressing SAP through new well designs and barriers, and better quality control over cementing – with existing wells they are having to rely on surface data – fluid sampling and bleed-off/build-up data, for example – to investigate the problem downhole.   There is also the challenge of being able to locate leaks and unwanted flowpaths behind multiple barriers, not clearly seen by conventional temperature and ordinary noise logs.   TGT’s spectral diagnostics technology locates leaks and flowpaths throughout the well system by tracking fluid movement behind pipes within several casing strings.   Spectral diagnostics utilise high-fidelity downhole sound recording systems to capture the frequency and amplitude of acoustic energy generated by liquids or gas moving through integrity breaches and restrictions such as cement channels, faulty seals and casing leaks. When coupled with surface data, the information can narrow down the range of remedial options available, and target leak repairs.   Spectral diagnostics include fast, high-precision temperature measurements to locate integrity breaches throughout the well system. High-precision temperature sensors respond more quickly than conventional sensors to the localised thermal changes caused by integrity failures, complementing acoustic measurements by providing a visual confirmation of leaks and flowpaths.   While conventional production logging measurements typically assess only high-rate first-barrier failures – the high-fidelity recording, sensitivity and clarity of spectral diagnostics enables the tracking of even low-rate leaks at very early stages behind multiple barriers, enabling timely intervention and prolonging well life. In the following example [figure 2], a water injector well experienced sustained B-annulus pressure, although the build-up rate did not exceed one bar a day – indicating a low-rate leak.   A cement bond survey indicated good cement bonding below X500m, and poor bonding above. Poor cement bonding is likely to provide flowpaths for fluid movement behind casing. Unfortunately, cement bond log indications of ‘good bonding’ don’t guarantee annulus integrity. Flowpaths can exist that remain unnoticed by the cement bond log.   A survey utilising TGT’s spectral diagnostics system was conducted and revealed fluid flow from the reservoir around X540m and channelling up the annulus through the ‘good bonding’ area.   The frequency spectrum pattern correlated with reservoir permeability and fluid-type profiles, suggesting gas being produced from these formations. The operator used the information to target a cement squeeze operation at the desired location in the well – restoring B-annulus integrity and eliminating the SAP. Evolving challenges, new technologies  As Middle East operators continue to face well integrity challenges, gaining a deeper insight into both well and reservoir dynamics is vital. Advanced well diagnostics systems are now available to allow this to be achieved.