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Summary Distributed temperature sensing (DTS) is a valuable tool to diagnose multistage hydraulic fracture treatments. When a stage interval is shut in, the clusters that take more fluid during pumping warm up more slowly. Therefore, the fluid volume injected into each cluster can be quantitatively interpreted by numerical inversion of the warm-back temperature behavior. This general concept assumes that the different warm-back behavior is controlled by only the injected fluid volume; however, recent observations of DTS data indicate that completion configurations significantly influence the warm-back behavior. This paper investigates the completion effects on the DTS interpretation. In ideal conditions, when a stage is fractured, the upstream stage intervals should show an almost uniform temperature that is close to the injected fluid temperature. This is due to the high fluid velocity of injected fluid in the wellbore, and the upstream intervals have not been perforated (noncommunicating intervals), so the only heat transfer is heat conduction between the wellbore fluid and the surrounding reservoir. But the field DTS data show considerably irregular variations in temperature along the upstream stage intervals. These variations are caused by the completion effects. The nonuniform temperature profile is caused by different heat transfer behavior induced by completion hardware along the production casing string, such as joints, clamps, and blast protectors, and by the sensing cable location in the cement, as well as the cement quality. Because the varying heat transfer behavior impacts the warm-back behavior as well as the temperature profile, the completion effects need to be considered in DTS interpretation. A method of DTS interpretation considering the completion effects to diagnose multistage fracture treatments was developed. Because the heat transfer between a wellbore and a reservoir depends on the overall heat transfer coefficient describing heat conduction through the completion in a forward model, this parameter needs to be tuned all along the wellbore. To calibrate the completion effect, the temperature inversion is conducted using the temperature measured at a stage interval that is upstream of a stage interval currently being treated. Because the interpreted stage interval is not perforated at that time, the thermal behavior at the noncommunicating interval is governed by only the heat conduction through the completion environment. Once the effective values of the overall heat transfer coefficient are estimated along the interpreted stage interval, they can be assumed to be constant physical parameters. Then, the fluid volume distribution is interpreted by using the effective overall heat transfer coefficient profile along each interval. This study provides a field application of the developed interpretation method. The new interpretation method provides more accurate diagnosis of fracture treatments by DTS interpretation.
Abstract Distributed temperature sensing (DTS) is a valuable tool to diagnose multistage hydraulic fracture treatments. When a stage interval is shut-in, the clusters which take more fluid during pumping warm up more slowly. Therefore, the fluid volume injected into each cluster can be quantitatively interpreted by numerical inversion of the warm-back temperature behavior. This general concept assumes that the different warm-back behavior is controlled by only the injected fluid volume, however, recent observations of DTS data indicate that completion configurations significantly influence the warm-back behavior. This paper investigates the completion effects on the DTS interpretation. In ideal conditions, when a stage is fractured, the upstream stage intervals should show an almost uniform temperature that is close to the injected fluid temperature. This is due to the high fluid velocity of injected fluid in the wellbore, and the upstream intervals have not been perforated (non-communicating intervals). Thus, the only heat transfer is heat conduction between the wellbore fluid and the surrounding reservoir. But the field DTS data show considerably irregular variations in temperature along the upstream stage intervals. These variations are caused by the completion effects. The non-uniform temperature profile is caused by different heat transfer behavior induced by completion hardware along the production casing string such as joints, clamps, and blast protectors, and by the sensing cable location in the cement, as well as the cement quality. Since the heat transfer behavior impacts the warm-back behavior as well as the temperature profile, the completion effects need to be considered in DTS interpretation. A method of DTS interpretation considering the completion effects to diagnose multistage fracture treatments was developed. Since the heat transfer between a wellbore and a reservoir depends on the overall heat transfer coefficient describing heat conduction through the completion in a forward model, this parameter needs to be tuned along the entire wellbore. To calibrate the completion effect, the temperature inversion is conducted using the temperature measured at a stage interval that is upstream of a stage interval currently being treated. Since the interpreted stage interval is not perforated at that time, the thermal behavior at the non-communicating interval is governed by only the heat conduction through the completion environment. Once the effective values of the overall heat transfer coefficient are estimated along the interpreted stage interval, they can be assumed to be constant physical parameters. Then, the fluid volume distribution is interpreted by using the effective overall heat transfer coefficient profile along each interval. The interpretation method developed in this study was demonstrated using field data, and it was concluded that the new DTS interpretation method provides more accurate diagnosis of fracture treatments.
Hill, A. D. (Texas A&M University) | Laprea-Bigott, M. (Texas A&M University) | Zhu, D. (Texas A&M University) | Moridis, G. (Texas A&M University) | Schechter, D. S. (Texas A&M University) | Datta-Gupta, A. (Texas A&M University) | Abedi, S. (Texas A&M University) | Correa, J. (Lawrence Berkeley National Laboratory) | Birkholzer, J. (Lawrence Berkeley National Laboratory) | Friefeld, B. M. (Class VI Solutions, Inc.) | Zoback, M. D. (Stanford University) | Rasouli, F. (Stanford University) | Cheng, F. (Rice University) | Ajo-Franklin, J. (Rice University / Lawrence Berkeley National Laboratory) | Renk, J. (Department of Energy) | Ogunsola, O. (Department of Energy) | Selvan, K. (INPEX Eagle Ford LLC)
Abstract The Eagle Ford Shale Laboratory is a DOE and industry-sponsored multi-disciplinary field experiment aimed at applying advanced diagnostic methods to map hydraulic fractures, proppant distribution, and the stimulated reservoir volume. The field site is an Inpex Eagle Ford, LLC lease in LaSalle county, Texas that has a legacy Eagle Ford producing well and that will be developed with 5 new producers. Utilizing newly-developed monitoring technologies, the project team will deliver unprecedented comprehensive high-quality field data to improve scientific knowledge of three important processes in unconventional oil production from shales: (1) a re-fracturing treatment in which the previously fractured legacy well will be re-stimulated for improved production, (2) a new stimulation stage where the most advanced hydraulic fracturing and geosteering technology will be applied during zipper-fracturing of 3 new producers, and (3) a Gas-Injection Enhanced Oil Recovery (EOR) Phase where one of the wells will be later tested for the efficiency of Huff and Puff gas injection as an EOR method. Field monitoring is being complemented with laboratory testing on cores and drill cuttings, and coupled modeling for design, prediction, calibration, optimization, and code validation. The multi-disciplinary team consists of researchers from Texas A&M University, Lawrence Berkeley National Laboratory, Stanford University, Rice University, and Inpex Eagle Ford, LLC. The ultimate objective of the Eagle Ford Shale Laboratory Project is to help improve the effectiveness of shale oil production by providing new scientific knowledge and new monitoring technology for both initial stimulation/production as well as enhanced recovery via re-fracturing and EOR. The main scientific/technical objectives of the project are: Build and test active seismic monitoring with fiber optics in an observation well to conduct: (1) real-time monitoring of fracture propagation and stimulated volume, and (2) 4D seismic monitoring of reservoir changes during initial production and during an EOR pilot. Test distributed temperature sensing (DTS), distributed acoustic sensing (DAS) and distributed strain sensing (DSS) with fiber optic technology and develop protocols for field application. Assess spatially and temporally resolved production characteristics and explore relationships with stimulated fracture characteristics by open hole logging, cased hole logging, production logging, and tracer technology. Understand rock mechanical properties and reservoir fluid properties and their effect of stimulation efficiency through coring and core analysis. Evaluate suitability of re-fracturing to achieve dramatic improvements in stimulated volume and per well resource recovery. Develop understanding of gas-based EOR Huff and Puff methods to increase per well resource recovery by lab tests and field test.
Abstract Using planar fracture models to match treatment pressure and improve understanding of the fracture geometry generation is not a new concept. Knowledge gained from this exercise has historically been used to improve engineered fracture completions and production, and maximize net present value (NPV); however, at some point during the progression from vertical to horizontal wellbores, many within the industry have forgotten about the learnings that can still be gained from current fracture models. Engineered completions have been largely replaced by spreadsheet efficiencies relevant to operations rather than production in too many cases. Some images of unconventional well stimulation treatments portray fractures growing in every direction, forming patterns that resemble shattered windshields, and have often excluded the known physics related to rock geomechanics, reservoir properties, and geology. Excuses to dismiss modeling are numerous and are gaining the reasoning of conformists. Unconventional resource plays might or might not contain large numbers of natural fractures; but, current fracture models can still be used to gain insight into the fracture geometries being generated. While the development of complex fracture models continues to evolve, the industry can still gain insight to fracture geometry and resulting production using current planar fracture modeling. Caveats to this process are that it requires: Valid measured data to establish model constraints. The engineer to understand the basic physics of how fractures are generated and when (and when not) to twist the "knobs" in the model. The engineer to understand which "knobs" should be used based on real diagnostics information. The actual single well production to be an integral part of the process. This paper demonstrates the results of honoring data measurements from a multitude of potential sources, including downhole microseismic data, downhole deformation tiltmeters, offset pressure monitoring, DTS, DAS, diagnostic fracture injection test (DFIT) analysis, injection as well as production data with bottomhole pressure measurements, etc., and the resulting observations and conclusions. Several industry examples are discussed to help frame the vast amount of information possible to help engineers do a better job of including more diagnostics into routine operations to provide additional insight and ultimately result in improved models and completion designs. This paper is not intended to merely demonstrate the results of the work but to spark an interest in bringing more intense engineering back to fracture stimulation modeling for horizontal completions.
Abstract To maintain open and conductive fractures in tight-rock shale formations, shale/water interactions should be controlled through chemical or brine treatments. Adequate treatment of an unconventional formation can mitigate or reduce the damaging effects induced by shale (swelling, sloughing, fines migration) or proppant (proppant embedment, breakage, fines migration), which leads to maximized conductivity. This study characterizes shale behaviors with various treatment fluids applied under simulated downhole conditions. Four source rock shale samples, Barnett, Eagle Ford, Mancos, and Marcellus, were characterized and evaluated in contact with chemical and brine treatments to determine the extent of swelling and mechanical stability imparted by each treatment. Conductivity measurements were taken on proppant packs between shale wafers under closure stresses from 2,000 to 10,000 psi. The wafers used during those tests were then analyzed using computed tomography (CT) imaging. Quantification and classification of the damage were used to evaluate the shale formations after application of fresh water and two chemical treatments—a small cationic oligomer and a large cationic polymer additive. Results suggested that chemical and brine treatments do not provide an all-inclusive mechanism to prevent damage for all shale samples, and total clay content or clay type was not the best predictor of water sensitivity. Barnett shale samples contained the most clay, had the highest conductivity, and were most resistant to fluid-induced damage using a small cationic oligomer additive. Conductivity loss for the other three shale formations was primarily attributed to fluid-induced formation damage. In each of these three shales, the mechanism for formation damage resulted from different causes. Clay-induced swelling for Mancos shale resulted in the most significant proppant embedment and was most effectively remedied using a large molecular weight polymer stabilizer treatment. Eagle Ford and Marcellus shales showed pockets of proppant embedment and significant fines migration. Generation of migrating fragment causality was different for these two shales; one contained migrating clays in its mineralogy, while the other was more mechanically brittle and prone to stress-induced fragmentation. The differing mechanism changed the effectiveness of the chemical treatments; Eagle Ford shales were most responsive to large molecular weight polymer stabilizers, whereas Marcellus shales did not change significantly with the chemical treatments evaluated. Selecting the optimal chemical treatment for each formation depends on the mechanism and type of damage. Each reservoir is unique, and improving production begins with customizing treatments to protect the formation materials against the specific damage mechanisms, thus minimizing the negative impact on propped fracture conductivity. Understanding the exact needs of each shale formation allows the treatment fluid to be tailored specifically for the formation as part of the fracturing treatment design, thereby optimizing the treatment effectiveness and cost.
Abstract Understanding the mechanisms driving proppant, fluid, and formation interactions, especially in shale reservoirs, provides many advantages, including helping design new treatment methods for stabilizing faces of shale fractures, mitigating proppant embedment, controlling clay and fines migration, and ultimately improving well production. This paper describes new imaging tools and processing methods used to demonstrate the impact of treatment fluids applied during hydraulic fracturing in shale formations. Results are correlated to provide guidance for selecting appropriate clay stabilizers to enhance propped fracture conductivity. Four types of outcrop shale formation samples (Mancos, Barnett, Eagle Ford, and Marcellus) were studied after conductivity tests were performed using fresh water. The workflow involves the following: (1) perform a computed tomography (CT) scan on the shale wafers; (2) process and segment the image to separate proppant, void space, and formation material; (3) calculate proppant embedment depths on both sides of the shale wafers; (4) calculate proppant-induced fracture widths and extract fracture patterns; (5) determine the percentage of void space and broken proppants; and (6) correlate these measures. Fluid interactions with shale materials were manifested in the presence of proppant under closure stress through proppant embedment, effective propped fracture width, proppant-induced fractures, void space, and broken proppant percentage. By performing comparisons between Eagle Ford shale samples with fresh water or certain treatment fluids, proppant embedment depths were observed to be shallower under treatment conditions. While the number of proppant-induced fractures increased, their widths were observed to be narrower in treated shale samples, which is consistent with the trend. This reflects the importance of the treatment fluids, which help reduce the impact of proppant embedment to maintain the effective propped fracture width. The proppant-induced fracture pattern became more complicated in shale samples that were exposed to treatment fluid, resulting in a significant increase in surface area for hydrocarbon desorption. The proppant bed void space was shown to increase significantly after treatment. In addition, broken proppant amounts were reduced in the shale samples after treatment with the fluid, which reaffirms its positive effects. Overall, quantitative comparisons between samples treated with fresh water and certain treatment fluids substantiated the positive impact of clay stabilization for providing protection for various formations. The results provide guidance for selecting appropriate treatment fluids for certain reservoirs and help reduce formation damage risks and costs. Applying novel digital rock techniques to study the interactions between fluid, proppant, and rock samples provides the most straightforward method to visualize and quantify changes. The developed nondestructive workflow proved to be useful for selecting the proper fluid system for treating certain reservoir formations and thus enhancing production. Quantifying proppant-rock interactions enables operators to determine the effects of the fluid system more accurately compared to using current conventional methods.
Summary Since the late 1990s, coalbed methane (CBM) has grown to be a significant part of the economy of the State of Queensland, Australia, building alongside world-scale coal-export operations. Environmental regulation in Queensland over the same period has evolved, with petroleum activities following a unified mineral rights/land tenure and environmental permitting process, particularly in respect to the impacts related to the spatial extent of CBM-basin developments. Following the announcements in 2008 of a number of multibillion-dollar liquefied-natural-gas-export projects, with industry estimates approaching 30,000 wells, attention by interest groups and the public at large gave rise to increased scrutiny by regulators of the scope of prevailing rules. In respect to the application of hydraulic fracturing, the CBM sector has indicated a likelihood of fracturing up to 40% of wells. A number of shale resources and tight gas basins are also under exploration in Queensland, with horizontal completions. Thus, the State can expect a significant rise in the application of stimulation technology. The unconventional-resources sector in Australia is somewhat different from that in North America, with the absence of a third-party pipeline sector, the result being few major producers with their own pipeline networks and speculative minors. As a result of this industry structure of relatively few operators, permitting has been project-based rather than sector-based, resulting in older approvals having conditions inconsistent with modern expectations. The State Government has moved to amend this position by developing more-performance-focused codes in respect to new hydraulic-fracturing programs. It has also moved toward greater emphasis on compliance activities. This paper examines a wide range of environmental issues related to hydraulic fracturing, including those potentially affecting groundwaters, surface waters, landforms and geology, biodiversity, the atmosphere, and community, drawing examples from Queensland and elsewhere. In respect to environmental regulation of hydraulic fracturing, a single, risk-based comprehensive code is proposed that encompasses the use of stimulation across all energy sources and fluid systems—conventional oil and gas, CBM, unconventional oil and gas, and geothermal. Fundamental to the approach is a comprehensive risk assessment, considering a wide range of issues at local and regional scales. Permit conditions will target pre-event disclosure requirements, engineering constraints, environmental-protection measures, product accreditation, process monitoring, and post-event reporting. Disclosure of products is required under petroleum and gas legislation, but this new approach will require product accreditation under an international standard that encompasses contaminant-concentration limits, human toxicology, and ecotoxicology. Evidence supporting code development includes consideration of environmental issues in Queensland, detailed review of hydraulic-fracturing studies, and reviews of petroleum-engineering risks. A detailed legislative review was completed that considers rules from 55 jurisdictions (including Australia, the US, Canada, Brazil, the UK and Scotland, France, and South Africa) across 59 identified regulatory matters. The following general principles and practices have been proposed to underpin the revised code to minimize the likelihood of adverse impacts from hydraulic fracturing: Detailed understanding of the local stratigraphy, including aquifers, faults, linear features, hydraulic conductivity, porosity, seismic risk, and groundwater-dependent assets Detailed engineering understanding of the impacts of applied stresses, including aquifer drawdown, on connectivity to aquifers above and below the fractured zone subsequent to the hydraulic-fracturing activity To require the presence of vertically impermeable formations between the fractured zone and other aquifers To require installation of a multibarrier casing string that isolates aquifers from hydrocarbon-bearing formations and, with current certification, demonstrates internal and external mechanical integrity To ensure injected fluids have low toxicity, contain no persistent bioaccumulating constituents, and are accredited for use under an international standard For the operator to apply advanced process control that incorporates real-time analysis, fracture modeling, and formation understanding by use of techniques such as microseismic measurements, as required, to assist in the early development of the resource and to address identified environmental risk over the life of the project To initiate and maintain a high level of meaningful communication with adjacent groundwater users, near neighbors, government, and the public in general This paper presents information supporting the chain of evidence leading to a revision of the Queensland regulations that is expected to be completed and approved in 2015, following industry and public consultation.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 25-27 August 2014. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper without the written consent of URTeC is prohibited. Summary Microseismic monitoring has proven to be an important tool for understanding and optimizing hydraulic fracturing, well completions, and field development in unconventional reservoirs. The microseismic distributions can be used as a proxy to estimate fracture length, azimuth, height, asymmetry, overall complexity, and general stage behavior. However, this technology has a number of limitations for fully understanding the behavior of the hydraulic fracture because it is unclear as to the direct relationship between the microseismic source and the tensile hydraulic fracturing process itself. The integration of other diagnostic technologies with microseismicity is needed to extract more detailed information about the fracturing process, the completion scheme, staging, and other relevant development details. In particular, surface tiltmeters, downhole tiltmeters embedded in microseismic arrays, distributed temperature sensing (DTS), distributed acoustic sensing (DAS), and more conventional diagnostics are used to enhance the understanding of the microseismicity in field applications. A combination of field data, theoretical analyses, and simulations demonstrate how such information can be extremely valuable in optimizing stimulations. The application of these technologies is geared toward unconventional reservoirs where multistage hydraulic fracturing in horizontal wells is the preferred development approach, although application in vertical wells is also useful. These additional technologies are shown to be helpful in evaluating complexity, fracture height growth, staging, cluster effectiveness, and horizontal fracturing in some of the highly tectonic areas, monitoring diversion, assessing isolation, and many other factors in a wide variety of field development cases. Introduction The exploitation of unconventional reservoirs, and particularly shale source-rock reservoirs, requires a systems engineering approach to development, with the system comprised of the reservoir, the wellbore, the completion approach, the stimulations, the clean-up and flowback methodology, artificial lift when required, and production.
Abstract Shale resource development technology is being improved and optimized over the last decade as the industry has seen a sharp rise in production and IP rates in North America and most recently from Europe and Australia while initial activities are on the rise in Latin America, Middle East and China. Despite such improvements, if one takes a closer look at the performance of the wells, one will find that not all wells are producing commercially and for that matter even wells that are producing commercially not all hydraulic fracture stages are contributing. This scenario is further compounded with the fact that unconventional resource development has a narrow profit margin for the E&P operators and in turn for the service industry. The industry needs to focus on the balance between efficient deployment of fit-for-purpose technology with strict economics in mind. This conundrum potentially suggests that when dealing with shale resource one is faced with sweet spot identification in a basin / field and at the same time moving away from geometric (say every 250 ft.) selection of hydraulic fracture stages and placing stages where appropriate from a productivity point of view. This paper documents certain well defined criterion used to identify the sweet spot location within a field / basin for the optimal well placement. We further document the vital formation / zone characteristic related information that can define the placement for hydraulic fracture stages and thus move away from the arbitrary geometric placement. Such an optimized plan can allow placement of productive wells and frac stages and thereby enhancing productivity and reducing well drilling and stimulation expenses. The key is effective cost reduction. The paper illustrates the well placement optimization process through a combination of seismic attribute analysis combined with petrophysical and geochemical analysis via core and geophysical log measurements. The hydraulic fracture stage placement relies on the need to understand existing natural fracture system through geophysical log measurements and the interaction between the created hydraulic bi-wing tensile fracture and the surrounding shear fractures. The paper concludes by presenting examples from three basins demonstrating the practical application of the methodology.
Abstract Microseismic monitoring of hydraulic fracturing has provided great value for understanding hydraulic fracturing in unconventional reservoirs, including measurement of fracture geometry and optimization of stimulations, completions, and field development. Nevertheless, microseismic monitoring is a complex endeavor and many issues of fielding, analysis, uncertainty, and geophysics should be carefully assessed. The geomechanics of the generation of microseismicity are still being investigated, as well as the source mechanisms and how it all relates to the fracturing process. Besides the value for field development and resource recovery, microseismic monitoring has also proved useful for evaluating environmental and safety issues. Data from thousands of fractures show that the levels of induced seismicity in typical relaxed sedimentary basins are well below any levels that would be of concern for safety or damage. Similarly, data from thousands of fractures show that hydraulic fractures in shale reservoirs do not propagate into aquifers.