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    Case studies
    CS032 Multi Seal Integrity

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

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    Case studies
    CS030 Horizontal Flow

    Challenge Producing gas from low-permeability reservoirs is always challenging, and making the correct field development decisions is crucial to success. Operators have to consider issues such as well type and configuration, and wellbore length for each geological or reservoir setting. Accurate gas production profiles from early wells help operators make the right field development choices.   Decisions made in the early stages of field development can have a huge impact on asset economics and longevity. In this case, the operators faced a particular challenge, as obtaining accurate production profiles in horizontal wells with uncemented slotted liners is extremely challenging for conventional PLT spinners. This is because of the complex gas flow regimes in the wellbore and the potential for the reservoir flow to be substantially different from the wellbore flow. Quantifying flow dynamics in horizontal well systems and accessing accurate reservoir flow profiles is fundamental to managing well and reservoir assets. Horizontal Flow with Cascade3 is designed to help Production and Reservoir Engineers complete daily tasks with greater certainty and confidence. Whether its locating water/gas breakthrough, understanding the influence of fractures, or maintaining an accurate reservoir model, Horizontal Flow delivers reliable flow profiles in a wide range of completion scenarios. Equipped with the right information, asset teams can take direct action to keep well and reservoir performance on track. Solution TGT’s new Horizontal Flow diagnostics, powered by Cascade3, overcomes many of the challenges that hamper conventional production logs. It delivers a more reliable and complete assessment of flow dynamics in horizontal wells across a wide range of completion scenarios, thereby enabling petroleum engineers and asset managers to keep well and reservoir performance on track.   The Cascade3 flow analysis platform is purpose-built for horizontal wells and incorporates the industry’s most advanced thermodynamic and hydrodynamic modelling codes. These enable Horizontal Flow to transform temperature and other well-system data into continuous reservoir flow profiles. These reflect flow activity both into and out of the reservoir, thereby delivering the most accurate picture of reservoir behaviour and downhole inflow and outflow. In this case, Horizontal Flow diagnostics enabled the field operator to evaluate the production profile and verify that it was consistent with the expected permeability distribution, that is, it matched the known reservoir properties and the current dynamic reservoir model. The Horizontal Flow survey confirmed that the production profile in this gas producer was consistent with the expected permeability distribution. In terms of total flow contribution from each zone, there is good agreement between Horizontal Flow with Cascade3 (14%, 24%, 62%) and standard PLT results (13%, 25%, 62%), but only Horizontal Flow showed the true reservoir flow profile from each layer. Relying on PLT results alone could have led to suboptimal field development decisions. Result Horizontal Flow diagnostics with Cascade3 and Chorus delivered an accurate gas-production profile for a horizontal well that had been drilled in a low-permeability, gas-bearing formation. The subject well was completed using a slotted liner across three zones separated by swellable packers. The contribution of each active permeable unit was accurately quantified with a continuous flow profile. The survey defined production contributions from each of the reservoir subunits, thereby improving the hydrodynamic reservoir model and making it possible to optimise subsequent wells in the ongoing field-development programme.   The Horizontal Flow survey confirmed that the target formations and the toe of the well would make economically viable contributions to production. The toe of the well is the main zone of concern for horizontal gas producers, and operators need to know whether production from that zone will overcome pressure drop and friction to contribute as effectively as the heel part of the well. The results of this survey showed no significant production loss for the well towards the toe. This supported expectations based on reservoir properties and confirmed that horizontal wells are a good option for developing this field.   Horizontal Flow diagnostics with Cascade3 justified the drilling of horizontal wellbores in this low-permeability clastic reservoir and gave the operator confidence to proceed with the existing field development plan. Building on the results of this survey, the operator is planning further horizontal gas producers in this and similar fields.

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    Harts E&P Magazine – Diagnosing flow downhole

    Production logging is an essential resource for managing well and reservoir performance, but traditional methods only see half the picture. In this article, we look at a new approach that looks further to reveal the true flow picture. Article featured in Harts E&P   The last few decades have brought impressive advances in ‘production logging’ technology, especially in the context of new sensor designs and diagnosing complex flow downhole. Fibre optics are also playing an increasing role in production surveillance. However, the fundamental technique of using wellbore-confined production logging tools (PLT’s) to infer total well and reservoir flow performance still dominates the industry.   Basically, PLT measurements are used to monitor fluid properties and flow dynamics in the wellbore and importantly, to determine production and injection ‘flow profiles’ where fluids enter or exit the wellbore, such as via perforations or inflow control devices. These measured and calculated flow profiles are used to assess the production and injection performance of the entire well system.   However, the validity and accuracy of this approach depends on many factors, and chief amongst them is the ‘integrity of communication’ between the wellbore and reservoir formations at the entry/exit points. Analysts and operators using PLT’s must assume that fluids entering or exiting the wellbore are flowing radially from or to the formations directly behind the entry/exit points. And unfortunately, this is often not the case. Flowpaths can exist through annular cement channels, formation packers or natural fissures, and fluid will always find the path of least resistance. From a compliance, environmental and performance perspective, these unwanted flowpaths are bad news. Decisions made assuming wellbore flow correlates directly to target reservoir flow can lead to complex reservoir and field management issues, and compromised asset performance. From a diagnostics perspective, it’s clear that analysts and operators can’t rely on PLT’s alone to diagnose and manage well system performance – a more powerful diagnostic approach is needed. Seeing further The challenge of behind-casing ‘cross-flow’ is not new and the industry has made several attempts over the decades to diagnose this insidious phenomenon. Some of the early techniques used nuclear activation, chemical tracers and noise logging to try to detect and map flow behind pipe, but these methods generally lacked the precision demanded of modern-day diagnostics and were, at best, qualitative. However, fueled by an increased operator focus on compliance, the need for better asset performance, and pure ingenuity, a new diagnostic capability has emerged that is rapidly becoming the new industry standard for diagnosing flow downhole. True Flow system Understanding the dynamics and connectivity of wellbore and reservoir flow downhole with any degree of precision and accuracy is a highly complex task that extends beyond the capabilities of conventional ‘logging’.   Which is why ‘True Flow diagnostics’ utilises a more powerful ‘system-based’ approach. The True Flow system combines experience and expertise with proprietary technology and an industry proven workflow to deliver a more complete picture of well system flow dynamics, and enable better informed well, reservoir and field management decisions (Figure 1). Programmes and methods The first ingredient and stage in the workflow is ‘Programmes & methods’. Following an initial customer consultation, analysis of well performance history, completion design, reservoir and fluid properties and assessment of diagnostic objectives, analysts customise a survey programme that will effectively ‘stress-test’ the well system to expose its flow dynamics in a number of scenarios. This can be likened to a heart specialist exercising a patient on different treadmill settings whilst scanning physiological parameters such as heart-rate, blood pressure and electro-cardio signals. Typical programmes will include a precisely-timed sequence of flowing and non-flowing surveys that allow the entire well system to warm-up and cool-down between surveys. Tools and measurements The second stage and ingredient is the application of high-fidelity ‘Tools & measurements’ by engineers that survey the well according to the diagnostic programme. The measurements come from basic and advanced PLT-type wellbore probes, and a combination of proprietary acoustic and high-precision temperature sensors. Fluids flowing throughout the well system generate acoustic signals encoded with flow information. The acoustic sensing technology used by the True Flow system captures this information in the form of sound pressure across a wide frequency and amplitude range. Importantly, the remarkable dynamic range of this technology means it can sample absolute sound levels from deafeningly loud to imperceptibly quiet without losing clarity or detail. This means that a wide variety of flow scenarios can be located and characterised throughout the well system, from the wellbore to several metres into the reservoir formation. The temperature sensor in itself is unremarkable, being an industry standard fast-response, high-precision type capable of resolving to decimals of degrees. However, correlating temperature changes observed during the diagnostic programme and combining it with the acoustic data, wellbore flow measurements and other well and reservoir information is the key to quantifying flow by the next ingredient of the system – ‘Processing & modeling’. Processing and modeling During the processing and modeling stage, data acquired during the survey programme are enhanced further by analysts using a proprietary digital workspace and a number of processing and modeling ‘plug-ins’. High-resolution acoustic data are transformed into an ‘Acoustic Power Spectrum’ to reveal the characteristic signatures of different types of flow. Analysts can select from a catalogue of digitally enhanced spectra to illuminate particular aspects of the flow and extract maximum information from the acoustic signals.   The subsequent flow modeling is integral to the entire True Flow system and represents another significant advancement in flow diagnostics. Precision temperature measurements acquired during all stages of the diagnostic programme are assimilated together with all other data to derive ‘reservoir flow profiles’. These are distinct from conventional PLT-derived wellbore flow profiles because they quantify flow exiting or entering formation layers whether or not casing or perforations are present. Built on more than a decade of R&E and commercially proven in thousands of wells, the flow modeling engine solves complex thermohydrodynamic physics by matching simulated and measured temperature and other responses in the flow scenarios created during the diagnostic programme. The result is ‘quantified reservoir flow’ that together with wellbore flow measurements complete the total flow picture. Analysis and interpretation The previous True Flow stages are curated under the watchful eye of analysts who also administer the final important stage of the workflow – ‘Analysis & interpretation’. Armed with all available well data, processed and modeled results, and an expert knowledge of true flow applications, the analyst will derive and compile the diagnostic result. Whilst more complex scenarios can take a number of days to complete, the final result is a more comprehensive and accurate diagnostic of reservoir and wellbore flow that ultimately leads to better well management decisions and improved asset performance.   The True Flow system is used to provide a range of diagnostic answer products that address most flow-related applications. These products include ‘Total Flow’, which combines both wellbore and reservoir flow (Figure 2), ‘Sand Flow’ for sand management applications, ‘Fracture Flow’ to optimise fracturing programmes, ‘Stimulate Flow’, ‘Horizontal Flow’, and many more. FIGURE 2. A typical Total Flow answer product derived using the True Flow system is depicted. The PLT-derived wellbore flow profile (left) shows oil and water entering the wellbore at P2 only, suggesting the source of production is from the target reservoir at the same depth. However, the True Flow system reveals that several other formation layers are contributing to this flow, including that the main oil production is coming from the upper and lower sections of the A1 formation, and the water is emanating from deeper layers. By seeing the total flow picture, the operator has a more accurate and complete understanding of well and reservoir behavior and is able to target appropriate remediation. A bright future The old thinking cannot answer today’s new challenges. As well systems become more complex and older, managing performance will remain a priority and continue to task the industry. Wells are built to connect the right fluids to the right places, safely and productively, but forces, materials and age conspire to undermine this perfect balance. Traditional production logging will continue to play an important role in managing production, but it’s clear that we need to look beyond the wellbore, to the reservoir itself, in order to see the true picture.

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    Case studies
    CS015a Reservoir Flow (Producer)

    Challenges Waterflooding involves injecting water into a reservoir, usually to increase pressure and thus stimulate production. However, when this action is being performed in a multi-layer reservoir it requires constant monitoring to identify the potential for water breakthroughs and target intervals not flowing, that may affect fluid production. The operator’s main goal was to gain a quantitative assessment of the flow contributions from each layer in the producer well, particularly in the undersaturated reservoir areas which hold free gas behind the tubing and casing. Solution The operator selected TGT’s Reservoir Flow product which is delivered by the True Flow diagnostic system, using Chorus (acoustic) and Cascade (thermal) technology. Reservoir Flow complements conventional Wellbore Flow (conventional production logging) diagnostics by evaluating flow profiles behind casing.   The diagnostic programme for data acquisition involved two passes for flowing and shut in surveys. The Chorus surveys revealed the flow contribution from each layer, which is a significant advantage over conventional production logging (PLT). True Flow system uses a combination of Chorus, Cascade and PLT to reveal phase segregation and downhole contributions in this producer. Results The producer under investigation was completed for separate production from two sections of the multi-layer reservoir, with the upper section gathering production through the sliding sleeve door (SSD).   The diagnostics were performed across the target reservoir (Figure 1). Chorus (acoustic) platform captured multiple high-amplitude, broadband, depth-specific acoustic signals across the most permeable layers in both the flowing and shut-in regimes showing the fluid flow through the reservoir layers. The acoustic signals observed in the long shut-in regime indicated the presence of multiple wellbore crossflows, due to formation pressure differences between the layers and the heterogeneity of the oil displacement. Cascade platform made it possible to estimate the production profiles across both sections of the multi-layer reservoir, including the one behind the tubing, which was not possible by using PLT data alone.   The diagnostic results provided the answers the operator needed to plan an effective workover. Plan included the zonal isolation of water filled layers and a well recompletion that would improve waterflooding performance and increase recovery.

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    Unconventional diagnostics for unconventional wells

    New fracture flow diagnostics help operators elevate fracture performance (in the Permian) Article featured in Harts E&P   In recent years, the Permian basin is been the most prolific shale play in the US. Production in this area increased to 3.8 million barrels by 2019, representing almost 70% of the whole US production growth from 2011 to 2019 according to International Energy Agency (IEA). The impressive aspect of this achievement is that the growth has not stopped. On the contrary, the Permian is expected to continue growing and is estimated to achieve up to 5.8 million barrels by the end of 2023.   Such impressive growth doesn’t come easy. Significant advances in drilling, completing and multi-stage fracturing will continue to drive production increases. But evaluating the performance of fracturing programmes and the wells they deliver is key to optimising resources and ensuring maximum return on investment. Conventional diagnostics [such as production logging tools or ‘PLT’s’] can’t provide all the insights required to ensure the operator is achieving the best returns. This article focuses on the challenges faced when assessing unconventional reservoirs in terms of production, and features a new diagnostic capability introduced by TGT to evaluate the flow performance of hydraulically fractured wells, stage-by-stage. The new diagnostic product is aptly called ‘Fracture Flow’.   Operators have been drilling aggressively and pushing the boundaries of hydraulic fracturing beyond conventional standards compared to other plays. The drilled length of lateral sections has been constantly boosted, adding more footage as well as more production stages. The ultimate objective is to penetrate deep into the target formation increasing the area of contact with the specific reservoir or formation making the well, its completion and the reservoir one dynamic production system. Piezo crystals used in the Chorus tools and sensorThrough barrier diagnostics Champions of this approach include a Houston-based operator that recently drilled such a well at the Wolfcamp. The completion included a lateral section of more than 17,900 ft running through the Spaberry formation. The completed well had a total measured depth exceeding 24,500 ft with a customised completion design and fracking treatment. The completion included more than 50-stages and sand was pumped along more than 2,200 ft of reservoir to increase the well productivity.   These extended laterals have been engineered to optimise production performance and leverage improvements in drilling, fracking treatments and completion designs. The operators have overcome the number of well construction challenges and have quickly moved up a steep learning curve.   Like the challenges encountered with well construction, the Permian basin faces its own challenges. Following such an extensive multistage hydraulic fracturing programme, the wells are brought onstream at high initial production rates. But most of these extended-lateral producers tend to decline dramatically over a very short period. To help combat this challenge, and many others, TGT has developed a number of application-specific diagnostic products using its ‘True Flow System’ to quantitively evaluate flow dynamics throughout the entire well system – from reservoir to the wellbore, and the dynamic interplay between the two.   When talking about a hydraulic fracturing job, we all know the importance of the programme design prior to execution. During this phase, sophisticated software is utilised to model and optimise the fracturing programme, taking into consideration multiple variables. These variables include formation properties, lithology, depth, mechanical stresses and other parameters that can affect the final outcome. Another important consideration is the formulation of the hydraulic fracturing fluid. This fluid is normally comprised of sand (or proppant), gels (foam or sleek-water) and additives that are pumped downhole following the job design to prop open the induced fractures and maximise the extension of the fracture in terms of length, height and aperture as well as the integrity of the fractured conduit itself, so hydrocarbons can flow unabated.   TGT’s diagnostic ‘Fracture Flow’ product is able to locate and evaluate fracture inflows and quantify inflow profiles in hydraulically fractured wells. The product is delivered by our analysts using the ‘True Flow System’, which combines several technology platforms – Chorus (acoustic), Cascade (thermal), Indigo (multisense) and Maxim (digital workspace), to acquire, interrogate and analyse the acoustic spectra and temperature changes generated by the hydrocarbons or any other fluid flowing from the reservoir through active fractures and into the completion. This diagnostic capability goes beyond conventional flow measurement techniques that generally stop sensing at the wellbore and are therefore unable to quantify flow within the reservoir itself.   The Fracture Flow product extract shown in figure-1 represents the diagnosis of a hydraulically fractured oil producer with >80 degrees deviation. The reservoir has a gross thickness of approximately 1,200 ft and is fully cased. ‘Fracture Flow’ diagnostics compare fractured intervals [blue] to main producing intervals [green] at different choke sizes in order to evaluate the true effectiveness of hydraulic fracturing programmes and maximise well performance. The operator’s objectives in this case were to evaluate the post-fracture performance of three zones, and in particular: Compare the effectiveness of fractured stages by assessing the production contribution from each fractured interval Identify crossflow or behind-casing communication Increase production efficiency by identifying the optimum production choke for this well system.   The results revealed by the Fracture Flow analysis clearly revealed that the fractured intervals (figure-1 – blue coding) were not contributing fully to production in their entirety. Furthermore, it identified exactly the active zones and where the main production was coming from (figure-1 green coding). Fracture Flow revealed that only 62%, 59% and 56% of each zone was actually producing at the outset.   The Fracture Flow analysis also indicated that there were no crossflows among the three zones which was another key finding from an integrity perspective.   Thirdly, the Fracture Flow diagnostic programme helped to determine the optimal choke size required to ensure that the fractured zones were contributing at maximum rate.   TGT work in close collaboration with operators using Fracture Flow to help them reach their frac evaluation objectives; locate effective fracture inflows; quantify inflow profiles; and assess the effectiveness of fracture programmes, helping to optimise future programmes and maximise return on investment. TGT is an international diagnostics company that specialises in ‘through-barrier diagnostics’ for the oilfield. Our Houston-based operation provides unique ‘True Flow’ and ‘True Integrity’ diagnostics to operators throughout the United States, including the Permian. We are also working actively in deep water Gulf of Mexico, Latin America and other major basins around the globe.

  • True Flow Products
    Stimulate Flow

    Locate and quantify flow before and after stimulation Acidising a well is a complex procedure that requires meticulous planning and precisely targeted resources. Operators need the right information to ensure acid stimulation delivers maximum impact with minimal risk.   Stimulate Flow provides that information. Used pre- and post-stimulation, Stimulate Flow evaluates reservoir flow performance before and after acidising, so that stimulation programs can be optimised and then assessed to evaluate impact.   Delivered by our True Flow system using the Chorus (acoustic) platform and the Cascade (thermal) platform; Stimulate Flow provides the clarity and insight needed to manage stimulation resources more effectively.   Stimulate Flow is becoming a standard part of acid stimulation programmes as operators realise the benefits of True Flow diagnostics. Challenges Evaluate flow profiles in stimulated well systems Pre- and Post-stimulation assessment Optimising stimulation programme Unexpected post-stimulation performance PLT not matching expectations Benefits Understand the true source of production and quantify flow profiles accurately Optimise stimulation programme for improved effectiveness Ensure zonal isolation prior to stimulation Evaluate effectiveness of stimulation Better well and reservoir management decisions, precisely targeted Improve well system performance and extend productive life of asset Resources Product flyers(22) Case studies(36) Product animations(21) Platform flyers(8) System flyers(2) More(183) Hardware specifications(7) Technical papers(128) Intellectual property(48) White papers(0) Resources Related Systems & Platforms True Flow System Well systems connect reservoirs to the surface so injectors and producers can flow to and from the right place. LEARN MORE Platforms Chorus Cascade Indigo Maxim MediaStimulate Flow provides the clarity and insight needed to manage well system performance more effectively.Well sketch shows a range of flow scenarios before and after stimulation that Stimulate Flow can evaluate.Indicative logplot for Stimulate Flow Pre-stimulation Chorus data revealed zones with zero contribution and poor performing zones—low amplitude zones, minor temperature deflection. Post-stimulation Chorus data shows improved performance of hill-zone— high amplitude, high frequency signals on Chorus data, clearly indicating additional pay fractures after acid stimulation.

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    Elevate well performance with “Through-barrier Diagnostics”

    Creating reservoir flow profiles can enable better well and field management decisions Article featured in Harts E&P   A completed well is a sophisticated industrial-scale plumbing system, designed to transport fluids between subsurface reservoirs and the surface safely, productively and profitably. Injectors transport fluids one way, and producers transport more valuable fluids the other. Well system fusion Before the insertion of this grand plumbing scheme into the earth, the targeted subsurface reservoir and the fluids contained within it existed for millennia in a state of relative equilibrium. However, when the human-made tubulars, cement sheath and other well completion elements were “fused” with the subsurface by the well construction processes, this stasis was dramatically transformed into a complex and turbulent dynamic state.   This fusion between the human-made materials of the well completion and the natural materials of the earth, together with the dynamic interplay that now exists between the two, is what TGT Oilfield Services calls the “total well system.”   The well system includes that previously elusive volume of earth that exists beyond the wellbore, in the outer periphery of the well completion and the cement sheath that surrounds it—the so-called “well-to-reservoir interface.” Understanding the behavior of fluids here, and specifically the “flow” of fluids, is crucial to understanding the productive behavior of the entire well system. This is one reason why TGT Oilfield Services developed through-barrier diagnostics, which reveal flow behavior throughout the well system, from the wellbore through the completion and to its outer extremities where it connects intimately with the reservoir. An imperfect world In a perfect world, the well completion behaves according to its design and transports the right fluids to and from the right place in the subsurface. Moreover, in the same perfect world, the reservoir surrenders or receives the right fluids, and the total well system delivers safely, productively and profitably according to plan.   However, imperfections corrupt this ideal relationship and forces conspire to undermine the system. Imperfect cement seals, degraded packers, worn out valves, corroded pipe, near wellbore fractures and other barrier failures collude to open unwanted flow paths throughout the well system. As a result, essential fluids are diverted, sustained annulus pressures can dangerously manifest and, ultimately, producers or injectors will not behave as expected or underperform. Water destination A classic example of this occurs in injector wells. Petroleum and reservoir engineers determine that if water is injected at a particular pressure, then subsurface target zones will receive a certain volume of water over time. If the predicted flow rate is not observed, then either something is wrong with the assumptions and calculations or something is wrong with the well system—or both. Even worse, the predicted flow rate might be within range, but the water might not be reaching the target. The latter scenario is particularly insidious because it may be weeks, months or longer before an alarm is raised.   TGT has diagnosed thousands of injector wells and, in the majority of cases, has revealed unwanted flow paths behind the production casing, under- and overperforming target zones, and “thief zones” that effectively “steal” water from its intended destination.   Consider the injection well case shown in Figure 1. Conventional borehole flow diagnostics using production logging techniques (PLTs) tell the operator that most of the injected water is reaching the top half of the target reservoir unit (A3), and the rest is entering the lower half (far right track labeled “borehole flow profile”). Injection well case However, through-barrier spectral diagnostics by TGT reveal the true picture of what is happening with the well system. In reality, only 25% of the injected water is entering the target reservoir unit. The rest is channeling upward to a shallower unit (A2) from 210.3 m (690 ft) to 158.5 m (520 ft), probably though an imperfect cement sheath behind casing. A smaller amount is channeling downward.   This is a serious issue from both a well and reservoir management perspective. Not only is the target reservoir not receiving enough water to fulfill the field injection strategy, but 75% of the injected water is being wasted and potentially causing water breakthrough issues at other wells, compounding the loss. This essential information directly impacts well performance and potentially fieldwide management decisions. Harnessing acoustic and thermal energy TGT’s spectral diagnostics harness acoustic and thermal energy to locate and quantify fluid flow behind well barriers, thereby providing a complete picture of flow dynamics and pathways throughout the well system. High-fidelity sound recordings and processing technology deployed downhole locate flow activity by capturing and analyzing the characteristics of sound energy generated by pressurized fluid passing through well system restrictions, such as cement channels and reservoir entry points.   The position and relative intensity of the resulting spectral signature indicate the precise locations of flow activity (see the middle track of Figure 1 labeled “spectral injection”). This information is then used together with other well system data to guide a powerful and unique flow modeling engine that transforms precise thermal profiles into flow rates. The result is a behind-casing reservoir flow profile, which can be used in combination with the borehole flow profile to enable better well management and field management decisions (see right-hand track labeled “reservoir flow profile”).   Well barrier imperfections exist in all well types, so similar “unwanted flow path” scenarios exist in production wells too. Water source The case shown in Figure 2 is a deviated production well exhibiting a very high water cut of greater than 90%. Identifying the source of high water cut is one of the most urgent priorities for petroleum and reservoir engineers to resolve.   Whereas the PLT-derived borehole flow profile can only measure flow entering the wellbore in front of the perforated interval (A2), the spectral signature map indicates significant flow activity behind casing at several other producing intervals, namely A3, A4 and A5, and to a lesser extent at A1. Given that these intervals are known to be water-filled, the operator can confidently conclude that more than 60% of the produced water is coming from these zones. Knowing the exact locations of the source, the operator can take appropriate action to seal off the unwanted flow paths. Deviated production well exhibiting a very high water cut of greater than 90% Good bond, bad seal In the case study, the operator concluded that water from these zones was channeling through an imperfect cement sheath. Even though the azimuthal cement map and cement bond log indicated that the cement sheath had good mechanical coverage and a good bond with the casing, the cement was not providing a hydraulic seal. This specific aspect underlines the importance of verifying both barrier condition and barrier sealing performance when deciphering flow dynamics around the well system and eliminating unwanted flow. Completing the picture Conventional technology, such as PLTs, helps operators understand flow dynamics within the wellbore. However, this information does not always align with what is happening beyond the wellbore—beyond casing and cement at the reservoir interface. Evaluating the well system with through-barrier diagnostics is the only way to understand what is happening in the well system. Armed with a complete picture, the operator can confidently make better decisions to ensure the well system delivers the right fluids to the right place, safely and profitably for the entire productive life of the well.

  • TGT News – Elevate Well Performance With Through-barrier Diagnostics (Jan 2018)

    Creating reservoir flow profiles can enable better well and field management decisions. A completed well is a sophisticated industrial-scale plumbing system, designed to transport fluids between subsurface reservoirs and the surface safely, productively and profitably. Injectors transport fluids one way, and producers transport more valuable fluids the other. Well system fusion Before the insertion of this grand plumbing scheme into the earth, the targeted subsurface reservoir and the fluids contained within it existed for millennia in a state of relative equilibrium. However, when the human-made tubulars, cement sheath and other well completion elements were “fused” with the subsurface by the well construction processes, this stasis was dramatically transformed into a complex and turbulent dynamic state.   This fusion between the human-made materials of the well completion and the natural materials of the earth, together with the dynamic interplay that now exists between the two, is what TGT Oilfield Services calls the “total well system.”   The well system includes that previously elusive volume of earth that exists beyond the wellbore, in the outer periphery of the well completion and the cement sheath that surrounds it—the so-called “well-to-reservoir interface.” Understanding the behavior of fluids here, and specifically the “flow” of fluids, is crucial to understanding the productive behavior of the entire well system. This is one reason why TGT Oilfield Services developed through-barrier diagnostics, which reveal flow behavior throughout the well system, from the wellbore through the completion and to its outer extremities where it connects intimately with the reservoir. An imperfect world In a perfect world, the well completion behaves according to its design and transports the right fluids to and from the right place in the subsurface. Moreover, in the same perfect world, the reservoir surrenders or receives the right fluids, and the total well system delivers safely, productively and profitably according to plan.   However, imperfections corrupt this ideal relationship and forces conspire to undermine the system. Imperfect cement seals, degraded packers, worn out valves, corroded pipe, near wellbore fractures and other barrier failures collude to open unwanted flow paths throughout the well system. As a result, essential fluids are diverted, sustained annulus pressures can dangerously manifest and, ultimately, producers or injectors will not behave as expected or underperform. Water destination A classic example of this occurs in injector wells. Petroleum and reservoir engineers determine that if water is injected at a particular pressure, then subsurface target zones will receive a certain volume of water over time. If the predicted flow rate is not observed, then either something is wrong with the assumptions and calculations or something is wrong with the well system—or both. Even worse, the predicted flow rate might be within range, but the water might not be reaching the target. The latter scenario is particularly insidious because it may be weeks, months or longer before an alarm is raised.   TGT has diagnosed thousands of injector wells and, in the majority of cases, has revealed unwanted flow paths behind the production casing, under- and overperforming target zones, and “thief zones” that effectively “steal” water from its intended destination.   Consider the injection well case shown in Figure 1. Conventional borehole flow diagnostics using production logging techniques (PLTs) tell the operator that most of the injected water is reaching the top half of the target reservoir unit (A3), and the rest is entering the lower half (far right track labeled “borehole flow profile”). Injection well case However, through-barrier spectral diagnostics by TGT reveal the true picture of what is happening with the well system. In reality, only 25% of the injected water is entering the target reservoir unit. The rest is channeling upward to a shallower unit (A2) from 210.3 m (690 ft) to 158.5 m (520 ft), probably though an imperfect cement sheath behind casing. A smaller amount is channeling downward.   This is a serious issue from both a well and reservoir management perspective. Not only is the target reservoir not receiving enough water to fulfill the field injection strategy, but 75% of the injected water is being wasted and potentially causing water breakthrough issues at other wells, compounding the loss. This essential information directly impacts well performance and potentially fieldwide management decisions. Harnessing acoustic, thermal energy TGT’s spectral diagnostics harness acoustic and thermal energy to locate and quantify fluid flow behind well barriers, thereby providing a complete picture of flow dynamics and pathways throughout the well system. High-fidelity sound recordings and processing technology deployed downhole locate flow activity by capturing and analyzing the characteristics of sound energy generated by pressurized fluid passing through well system restrictions, such as cement channels and reservoir entry points.   The position and relative intensity of the resulting spectral signature indicate the precise locations of flow activity (see the middle track of Figure 1 labeled “spectral injection”). This information is then used together with other well system data to guide a powerful and unique flow modeling engine that transforms precise thermal profiles into flow rates. The result is a behind-casing reservoir flow profile, which can be used in combination with the borehole flow profile to enable better well management and field management decisions (see right-hand track labeled “reservoir flow profile”).   Well barrier imperfections exist in all well types, so similar “unwanted flow path” scenarios exist in production wells too. Water source  The case shown in Figure 2 is a deviated production well exhibiting a very high water cut of greater than 90%. Identifying the source of high water cut is one of the most urgent priorities for petroleum and reservoir engineers to resolve.   Whereas the PLT-derived borehole flow profile can only measure flow entering the wellbore in front of the perforated interval (A2), the spectral signature map indicates significant flow activity behind casing at several other producing intervals, namely A3, A4 and A5, and to a lesser extent at A1. Given that these intervals are known to be water-filled, the operator can confidently conclude that more than 60% of the produced water is coming from these zones. Knowing the exact locations of the source, the operator can take appropriate action to seal off the unwanted flow paths. Deviated production well exhibiting a very high water cut of greater than 90% Good bond, bad seal In the case study, the operator concluded that water from these zones was channeling through an imperfect cement sheath. Even though the azimuthal cement map and cement bond log indicated that the cement sheath had good mechanical coverage and a good bond with the casing, the cement was not providing a hydraulic seal. This specific aspect underlines the importance of verifying both barrier condition and barrier sealing performance when deciphering flow dynamics around the well system and eliminating unwanted flow. Completing the picture Conventional technology, such as PLTs, helps operators understand flow dynamics within the wellbore. However, this information does not always align with what is happening beyond the wellbore—beyond casing and cement at the reservoir interface. Evaluating the well system with through-barrier diagnostics is the only way to understand what is happening in the well system. Armed with a complete picture, the operator can confidently make better decisions to ensure the well system delivers the right fluids to the right place, safely and profitably for the entire productive life of the well.

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    TGT News – Unconventional diagnostics for unconventional wells (Nov 2019)

    New fracture flow diagnostics help operators elevate fracture performance  In recent years, the Permian basin is been the most prolific shale play in the US. Production in this area increased to 3.8 million barrels by 2019, representing almost 70% of the whole US production growth from 2011 to 2019 according to International Energy Agency (IEA). The impressive aspect of this achievement is that the growth has not stopped. On the contrary, the Permian is expected to continue growing and is estimated to achieve up to 5.8 million barrels by the end of 2023.   Such impressive growth doesn’t come easy. Significant advances in drilling, completing and multi-stage fracturing will continue to drive production increases. But evaluating the performance of fracturing programmes and the wells they deliver is key to optimising resources and ensuring maximum return on investment. Conventional diagnostics [such as production logging tools or ‘PLT’s’] can’t provide all the insights required to ensure the operator is achieving the best returns. This article focuses on the challenges faced when assessing unconventional reservoirs in terms of production, and features a new diagnostic capability introduced by TGT to evaluate the flow performance of hydraulically fractured wells, stage-by-stage. The new diagnostic product is aptly called ‘Fracture Flow’.   Operators have been drilling aggressively and pushing the boundaries of hydraulic fracturing beyond conventional standards compared to other plays. The drilled length of lateral sections has been constantly boosted, adding more footage as well as more production stages. The ultimate objective is to penetrate deep into the target formation increasing the area of contact with the specific reservoir or formation making the well, its completion and the reservoir one dynamic production system.   Champions of this approach include a Houston-based operator that recently drilled such a well at the Wolfcamp. The completion included a lateral section of more than 17,900 ft running through the Spaberry formation. The completed well had a total measured depth exceeding 24,500 ft with a customised completion design and fracking treatment. The completion included more than 50-stages and sand was pumped along more than 2,200 ft of reservoir to increase the well productivity.   These extended laterals have been engineered to optimise production performance and leverage improvements in drilling, fracking treatments and completion designs. The operators have overcome the number of well construction challenges and have quickly moved up a steep learning curve.   Like the challenges encountered with well construction, the Permian basin faces its own challenges. Following such an extensive multistage hydraulic fracturing programme, the wells are brought onstream at high initial production rates. But most of these extended-lateral producers tend to decline dramatically over a very short period. To help combat this challenge, and many others, TGT has developed a number of application-specific diagnostic products using its ‘True Flow System’ to quantitively evaluate flow dynamics throughout the entire well system – from reservoir to the wellbore, and the dynamic interplay between the two.   When talking about a hydraulic fracturing job, we all know the importance of the programme design prior to execution. During this phase, sophisticated software is utilised to model and optimise the fracturing programme, taking into consideration multiple variables. These variables include formation properties, lithology, depth, mechanical stresses and other parameters that can affect the final outcome. Another important consideration is the formulation of the hydraulic fracturing fluid. This fluid is normally comprised of sand (or proppant), gels (foam or sleek-water) and additives that are pumped downhole following the job design to prop open the induced fractures and maximise the extension of the fracture in terms of length, height and aperture as well as the integrity of the fractured conduit itself, so hydrocarbons can flow unabated.   TGT’s diagnostic ‘Fracture Flow’ product is able to locate and evaluate fracture inflows and quantify inflow profiles in hydraulically fractured wells. The product is delivered by our analysts using the ‘True Flow System’, which combines several technology platforms – Chorus (acoustic), Cascade (thermal), Indigo (multisense) and Maxim (digital workspace), to acquire, interrogate and analyse the acoustic spectra and temperature changes generated by the hydrocarbons or any other fluid flowing from the reservoir through active fractures and into the completion. This diagnostic capability goes beyond conventional flow measurement techniques that generally stop sensing at the wellbore and are therefore unable to quantify flow within the reservoir itself.   The Fracture Flow product extract shown in figure-1 represents the diagnosis of a hydraulically fractured oil producer with >80 degrees deviation. The reservoir has a gross thickness of approximately 1,200 ft and is fully cased. 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. Figure-1 ‘Fracture Flow’ diagnostics compare fractured intervals [blue] to main producing intervals [green] at different choke sizes in order to evaluate the true effectiveness of hydraulic fracturing programmes and maximise well performance The operator’s objectives in this case were to evaluate the post-fracture performance of three zones, and in particular:   - Compare the effectiveness of fractured stages by assessing the production contribution from each fractured interval - Identify crossflow or behind-casing communication - Increase production efficiency by identifying the optimum production choke for this well system.   The results revealed by the Fracture Flow analysis clearly revealed that the fractured intervals (figure-1 – blue coding) were not contributing fully to production in their entirety. Furthermore, it identified exactly the active zones and where the main production was coming from (figure-1 green coding). Fracture Flow revealed that only 62%, 59% and 56% of each zone was actually producing at the outset.   The Fracture Flow analysis also indicated that there were no crossflows among the three zones which was another key finding from an integrity perspective.   Thirdly, the Fracture Flow diagnostic programme helped to determine the optimal choke size required to ensure that the fractured zones were contributing at maximum rate.   TGT work in close collaboration with operators using Fracture Flow to help them reach their frac evaluation objectives; locate effective fracture inflows; quantify inflow profiles; and assess the effectiveness of fracture programmes, helping to optimise future programmes and maximise return on investment.   TGT is an international diagnostics company that specialises in ‘through-barrier diagnostics’ for the oilfield. Our Houston-based operation provides unique ‘True Flow’ and ‘True Integrity’ diagnostics to operators throughout the United States, including the Permian. We are also working actively in deep water Gulf of Mexico, Latin America and other major basins around the globe. Our diagnostics help operators make better decisions so they can manage wells safely, productively and profitably. tgtdiagnostics.com

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    Case studies
    CS004 Total Flow

    Challenge Petroleum and reservoir engineers determine that if water is injected at a particular pressure, then target reservoirs will receive a certain volume of water over time. If the predicted flow rate isn’t observed, then either something is wrong with the assumptions, or something is wrong with the well system—or both. Even worse, the predicted flow rate may be within range, but the water may not be reaching the target. The latter scenario is particularly insidious because it may be weeks, months or longer before an alarm is raised.   An operator was experiencing injection issues and needed to confirm whether the injected water was reaching the target reservoir. Total Flow locates and quantifies wellbore and reservoir flow, and reveals the relationship between the two. Solution TGT’s ‘Total Flow’ product was selected to explain the flow dynamics of the well system and uncover where the injected water was ultimately going. Total Flow is delivered by the ‘True Flow’ diagnostic system.   TGT’S diagnostic systems combine technology platforms that share a common structure and workflow, namely ‘programmes & methods’, ‘tools & measurements’, ‘processing & modeling’ and ‘analysis & interpretation’.   The True Flow diagnostic system uses four platforms: Chorus, Cascade, Indigo and Maxim, and each has a specific role. Chorus is used to record and analyse the acoustic energy produced by fluid flow throughout the well system. Its role in this case was to help analysts pinpoint flow activity behind casing. Cascade uses proprietary thermofluid modeling to calculate flow profiles throughout the well system, and Indigo provides a number of complementary measurements, including temperature and conventional production logging information [PLT]. Maxim is the digital workspace where analysts develop the pre-survey diagnostic programme and carry out post-survey processing, data integration, modeling and data analysis.   The diagnostic programme in this case called for the well system to be surveyed in flowing and non-flowing states in order to expose the active flowing zones. True Flow diagnostics in this injection well show that 75% of injected water was bypassing the target reservoir through behind-casing flowpaths. Result The diagnostic results revealed that only 25% of the injected water was reaching the target reservoir A3. The other 75% was flowing to four behind-casing formation layers in A2, and A4 respectively (See logplot).   The Chorus flowing spectrum clearly shows the injection flow activity in each of the five formations, and Cascade modeling has quantified the respective flow rates. Open hole data confirmed that formation layers above the target zone were water filled and the analyst concluded that the injected water was flowing through behind casing cement channels. This was supported by the continuous acoustic energy spectrum from A3 to the top of A2.   Equipped with an accurate and complete flow diagnostic of the well system, the operator was able to target an effective remediation plan.