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Majors Step Up Low-Carbon Initiatives
The Oil and Gas Carbon Initiative (OGCI), the CEO-led enterprise formed to drive the industry response to climate change, has launched a new effort to unlock large-scale investment in carbon capture, use, and storage (CCUS) as a crucial tool to help achieve net zero emissions. The CCUS initiative is designed to help decarbonize multiple industrial hubs around the world.
The goal of the initiative, according to OGCI, is to double the amount of CO2 that is currently being stored globally before 2030 while building a pipeline of potential future hubs to bring the fledgling CCUS industry to scale. To achieve this goal, OGCI says it will start by building on the work of many others to jointly put five emerging hubs into operation in the US, the UK, Norway, The Netherlands, and China.
In parallel, OGCI announced it has launched a joint CCUS Acceleration Framework with the 11 countries supporting the Clean Energy Ministerial CCUS Initiative, a high-level global forum working to create a global, commercial CCUS industry at the scale needed to meet the Paris Climate Agreement goals.
BP Appraisal Well Proves “World-scale Gas Resource” Offshore Senegal
The BP-operated Yakaar-2 appraisal well off Senegal encountered 30 m of net gas pay in a similar high-quality Cenomanian reservoir as the Yakaar-1 discovery well drilled in 2017, partner Kosmos Energy said 23 September.
Yakaar-2 was drilled 9 km from Yakaar-1 and proved up the southern extension of the field. Kosmos said the results underpin its view that the Yakaar-Teranga resource base is “world-scale” and could support an LNG project to supply domestic and export gas markets.
The previous Yakaar and Teranga discoveries on the Cayar Offshore Profond block confirmed that a prolific inboard gas fairway extends 200 km from Mauritania through the Greater Tortue area on the maritime boundary of Senegal and Mauritania, according to Kosmos’ website. The Teranga-1 discovery well was drilled in 2016. Development of Yakaar-Teranga is expected in a phased approach with Phase 1 providing domestic gas and data to optimize the development of future phases.
Chevron, Schlumberger, Microsoft Team To Improve Digital, Petrotechnical Work Flows
Chevron, Schlumberger, and Microsoft will combine their capabilities to create better digital, cloud-enabled work flows.
The companies will build for Chevron applications in Schlumberger’s DELFI cognitive exploration and production (E&P) environment that will be native to Microsoft’s Azure cloud computing platform. DELFI is a scalable and open cloud-based environment providing E&P software technology across the exploration, development, production, and midstream segments.
The combination of digital technologies will enable Chevron—and, eventually, other companies—to process, visualize, interpret, and glean insights from multiple data sources, the companies said.
Summer of Funding: These Oil and Gas Startups Raised More Than $70 Million
The oil and gas industry’s appetite for emerging innovations grew by at least $70 million over the past few months as investment arms of several large producers and upstream venture firms completed funding rounds for startups. The influx of cash into young firms is considered a major component of the upstream industry’s drive toward digital transformation.
The companies attracting investor attention tilt toward the North American shale sector, which has been turning to new technologies to unravel the complexities of tight reservoir development. Others apply more broadly to unconventional and conventional field development.
Study of DUCs Concludes Better Later than Never
Delaying a completion by as many as 4 years has “little effect” on the initial production level, according to a new study by US Energy Information Administration (EIA).
The study tested the assumption that long-delayed completions mean a well is not worth the cost.
“Some people say you cannot fracture a well drilled more than a year ago,” but the data says otherwise, said Jozef Lieskovsky, a senior analyst for the EIA who coauthored the report.
The study looked at Bakken wells dating back to 2014, when the oil price crash caused a surge in drilled but uncompleted wells (DUCs) as companies slashed spending. What the EIA found was that the average initial production for the oldest wells (3–4 years old) peaked at a slightly higher level that the youngest ones (1–2 years old).
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE-191779-18ERM-MS, “A Fast-Paced Work Flow for Well Spacing and Completions Design Optimization in Unconventional Reservoirs,” by Hoss Belyadi, SPE, and Malcolm Smith, EQT Corporation, prepared for the 2018 SPE Eastern Regional Meeting, Pittsburgh, Pennsylvania, USA, 7–11 October. The paper has not been peer reviewed.
Well spacing optimization is one of the more important considerations in unconventional field development. The essence of field development and optimization is to use completions design and well spacing to optimize the net present value (NPV) of the field on the basis of current commodity pricing, capital expenditure (CAPEX), operating cost, cycle time, and net revenue interest. A substantial variation in any of these essential factors must be studied to make sure the appropriate changes are accounted for in field development and optimization. A fast-paced and dynamic work flow has been developed that can be applied in different shale reservoirs to maximize the NPV of these assets. This paper describes the work flow, starting with a fracture model, then coupled with a production model using numerical simulation to obtain a calibrated model, and, finally, a detailed economic and sensitivity analysis to obtain the well spacing and completions design that will yield the highest NPV of the field.
When well spacing systems (interlateral spacing) for various unconventional basins were developed, commodity pricing was much higher and completions job sizes were smaller than they are today. The majority of wells were completed with less than 1,300 lbm/ft of proppant. As operators increased job sizes and seized the benefit of higher production performance, discussions regarding increasing well spacing also took place.
After 2014, operators sought ways to stay economical at lower commodity pricing and began to consider feasible ways to reduce operational costs, improve well productivity, raise NPV/acre, automate processes and work flows, use machine learning (ML) to improve predictability, and optimize workforce efficiency. Optimal well spacing for any unconventional well depends on many factors, including gas price, capital and operating expense, acreage position and inventory, completions design, production performance, and lateral length. There is no one-size-fits-all well spacing for various completions designs. Performing a full analysis, therefore, is crucial to finding the optimal well spacing for each area, either analytically or numerically.
Factors such as geology, engineering, and economic analysis must be considered. For instance, optimal well spacing and completions design for a geologically noisy and complex reservoir will be invalid in a discreet and quiet area. Similarly, if well spacing and completions design were developed for a high-commodity-pricing environment, performing the same work flow and evaluation at lower commodity pricing would yield an increase in well spacing. The work flow described in the complete paper addresses all these factors and uses modeling, numerical simulation, ML, and linear programming to optimize NPV.
Measured-pressure approaches (drilling, cementing, and completions) have offered much promise for some time but have been slow to reach widespread application. A spate of technical developments, deployments, trials, and applications, however, recently has pushed measured-pressure drilling (MPD) and its nuanced variants to their full potential as viable well-construction methods. Development of fully integrated drilling, control, and management systems, along with surveillance and data-processing enhancements, have brought the idea of fully functional real-time measured-pressure management to reality. Increasing experience, design feed-back, validation, and enhancements are making a number of derivatives of the approach widely applicable. As well as the drilling operations themselves, experience has increased to include all aspects of the well-construction process, including both cementing and completion running operations. Increasing equipment automation and surveillance and control systems is now providing confidence and accuracy with well-calibrated models of in-situ behavior. Additionally, the real-time management of operations creates a feedback loop that allows continuous improvement to be at the heart of execution and learning.
As broader industry experience and case history volume increases, the ability to deploy and use these approaches will provide additional flexibility to operators as they develop increasingly challenging formations and tight or complex pore-pressure fracture-gradient profiles and windows. Measured-pressure techniques and variants now appear to be coming of age, and wider application will continue to enhance and enrich their functionality. Continued automation, data management, and personnel training and experience will support the continued and increasing deployment of these approaches.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE/IADC 194538 The Business Case for Use of Applied-Backpressure Managed-Pressure Drilling in Deepwater Gulf of Mexico by Sharief Moghazy, Shell, et al.
SPE/IADC 194541 Acoustic Telemetry Network Provides Real-Time Downhole Data Transmission During Drilling, Cementing, and Completion Installation for Use in Depleted Reservoirs and During Managed-Pressure Operations by Andy Hawthorn, Baker Hughes, a GE company, et al.
SPE/IADC 194554 Using Managed-Pressure Drilling and Early Kick/Loss Detection System To Execute a Challenging Deepwater Completions Job in the Gulf of Mexico by Julian Hernandez, Weatherford, et al.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190277, “Mechanistic Study for the Applicability of CO2-EOR in Unconventional Liquids-Rich Reservoirs,” by Dheiaa Alfarge, SPE, Iraqi Ministry of Oil and Missouri University of Science and Technology, and Mingzhen Wei and Baojun Bai, Missouri University of Science and Technology, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed.
Improved oil recovery (IOR) methods for shale-oil reservoirs are considered relatively new concepts compared with IOR for conventional oil reservoirs. Different IOR methods—including CO2, surfactant, natural gas, and water injection—have been investigated for unconventional reservoirs using laboratory experiments, numerical simulation studies, and limited pilot tests. For a variety of reasons, CO2 injection is the most-investigated option. In this paper, numerical simulation methods of compositional models were incorporated with logarithmically spaced, locally refined, and dual-permeability reservoir models and local grid refinement (LGR) of hydraulic-fracture conditions to investigate the feasibility of CO2 injection in shale oil reservoirs.
Advancements in horizontal drilling and hydraulic fracturing enabled unconventional liquids-rich reservoirs (ULRs), such as shale and source-rock formations and very tight reservoirs, to change the oil industry. ULRs are characterized by pore throats of micro- to nanomillimeters and an ultralow permeability. Although different studies re-ported that these ULRs contain billions of recoverable oil barrels in place, it is estimated that less than 7% of the original oil in place can be recovered during the primary depletion stage. Production sustainability is the main problem behind the low oil recovery in these unconventional reservoirs. Oil wells in ULRs typically start with a high production rate, but show a steep decline rate in the first 3–5 years of production life because of the rapid depletion in the natural fractures combined with a slow recharge from the rock matrix.
The logical steps of academic research such as experimental investigation, simulation studies, and pilot tests for examining the applicability of different unconventional IOR methods have just begun in the past decade. Applying one of the feasible IOR methods in most oil and gas reservoirs should be mandatory to increase the oil-recovery factor. However, the mechanisms of IOR methods in unconventional reservoirs are not necessarily the same as those in conventional reservoirs. The primary characteristics of unconventional reservoirs that might impair performing IOR operations are low porosity and ultralow permeability. As a result, finding IOR methods that are insensitive to these very small pore throats is a priority.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190323, “Gas Injection for EOR in Organic-Rich Shale: Part I—Operational Philosophy,” and paper URTeC 2903026, “Gas Injection for EOR in Organic-Rich Shale: Part II—Mechanisms of Recovery,” by Francisco D. Tovar, SPE, Maria A. Barrufet, SPE, and David S. Schechter, SPE, Texas A&M University. Paper SPE 190323 was prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April; paper URTeC 2903026 was prepared for the 2018 Unconventional Resources Technology Conference, Houston, 23–25 July. The papers have not been peer reviewed.
This synopsis contains elements of two papers. In the first, the authors describe their comprehensive experimental evaluation of gas injection for enhanced oil recovery (EOR) in organic-rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic-rich shale reservoirs, whereas tests in resaturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slimtube minimum miscibility pressure (MMP) on recovery. In the second paper, the authors focus on the effect of fluid transport in organic-rich shale on recovery mechanisms under gas injection, and provide the rationale behind the proposed operational philosophy.
Part I—Operational Philosophy
Background. The notion that industry experience in the implementation of gas-injection methods in conventional reservoirs can be applied to unconventional reservoirs is a problematic one. A lack of understanding exists regarding the effect of contrast in mechanisms at the pore scale on the implementation of a gas-injection process. Experimental research so far, though encouraging, suffers from serious limitations. Also, there still is a significant lack of understanding of the mechanisms of recovery under gas injection for enhanced recovery in organic-rich shales.
In this paper, the authors base their investigation on experimental observations made in core plugs extracted from the reservoir interval, and show the development of a coreholder configuration that enables the physical simulation of the injection of gas through a hydraulic fracture in the laboratory. Then, this configuration is used to perform coreflooding experiments at the pressure and temperature conditions seen in the reservoir. Detailed descriptions and results of the experimental work are provided in the complete paper.
Summary. The authors begin by demonstrating that direct gas injection through an organic-rich shale matrix is not possible in a reasonable time frame. That discovery triggered the construction of specialized equipment and the development of a novel injection technique that resembles that of injection through hydraulic fractures. Using that technique,
nine experiments injecting CO2 in preserved organic-rich shale cores were performed. Only three of those experiments recovered a significant volume of oil, and the recovery factor was estimated to be between 18 and 62% of the initial crude-oil volume in the cores.
This demonstrated CO2 can be used to extract the naturally occurring oil in core plugs with extremely low permeability, where gas cannot be injected directly. Also, by coupling the coreflooding equipment developed in-house to a computed-tomography (CT)-scanner, this technology proved able to track the changes in density resulting from the mass exchange between CO2 and crude oil.
In my last two Technology Focus columns, I discussed CO2-enhanced oil recovery (EOR) and the challenges it faces in conventional oil reservoirs. In this entry, my focus is on its applications in unconventional reservoirs.
Oil and gas production from unconventional resources has changed the dynamics of the world oil supply, particularly in the US. This has changed the US from a declining oil producer to one of the highest oil producers in the world. Oil production from unconventional reservoirs is still a challenge and depends on a number of factors, including brute force, for drilling and hydraulic fracturing. Production from these reservoirs declines rapidly, and more wells have to be drilled to keep production at reasonable levels. Recovery, by some estimates, can be less (sometimes much less) than 10%. Currently, the number of wells drilled in unconventional reservoirs exceeds 100,000, and many are producing just a trickle of hydrocarbons.
In recent years, some effort has been made to use EOR techniques, particularly CO2 injection, to extract additional oil and gas from unconventional resources. This is by no means a trivial feat. It has the potential to change the dynamics (again) of oil production from these tight and difficult reservoirs.
Considerable research and laboratory studies have been conducted addressing the use and potential of CO2 in extracting hydrocarbons from unconventional reservoirs. Estimates of oil recovery range from an additional 10% up to more than 50%. Very few field trials have been conducted, but the use of CO2 in these reservoirs is promising.
The recommended papers that follow present examples of laboratory studies, taking the results to the field, and mechanistic studies that elucidate some of the factors to consider and the pros and cons of CO2-EOR in unconventionals. They are meant to be a starting point for better understanding and further research. What the industry needs at this stage is more-daring EOR field trials reminiscent of the risks taken by the pioneers of unconventional resources at the beginning of this century.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 191780 Enhanced Oil Recovery in Eagle Ford: Opportunities Using Huff ’n’ Puff Technique in Unconventional Reservoirs by Piyush Pankaj, Schlumberger, et al.
OTC 28973 Recent Advances in Enhanced-Oil-Recovery Technologies for Unconventional Oil Reservoirs by S. Balasubramanian, University of Houston, et al.
SPE 192734 Miscibility Effects on Performance of Cyclic CO2 Injection in Hysteretic Tight Oil Reservoirs by Yasaman Assef, University of Calgary, et al.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2890074, “Laboratory Investigation of EOR Techniques for Organic-Rich Shales in the Permian Basin,” by Shunhua Liu, SPE, Vinay Sahni, and Jiasen Tan, SPE, Occidental Oil and Gas, and Derek Beckett and Tuan Vo, CoreLab, prepared for presentation at the 2018 Unconventional Resources Technology Conference, Houston, 23–25 July. The paper has not been peer reviewed.
Commercial production from light oil, organic-rich shales in the Permian Basin has largely come from a solution-gas-drive recovery mechanism as a result of horizontal drilling and multistage hydraulic fracturing. These onshore, capital-intensive developments feature steep production declines and low expected ultimate recoveries. This paper involved laboratory experiments introducing miscible gases into core samples to investigate enhanced oil recovery (EOR) mechanisms for Permian Basin shales to provide information to design field tests for a huff ’n’ puff (HNP) recovery process.
The average recovery factor in the un-conventional resources is typically less than 10% with very steep decline rates, indicating enormous potential for EOR. In recent years, research efforts and field pilots of unconventional EOR have targeted the Bakken and Eagle Ford shales. Most focused on miscible-gas (either CO2 or produced gas) injection, while others investigated water-based chemical injection. This paper provides EOR fluid and core analyses in Permian Basin organic-rich shale, an unconventional hydrocarbon growth play with different geological, rock, and fluid properties from those of the Bakken and Eagle Ford plays. The experimental results from this paper were used to calibrate the operator’s unconventional EOR reservoir simulation and field pilot design.
Fluid properties such as equation-of-state (EOS) and minimum miscibility pressure (MMP) are extremely important because they are the fundamental designing parameters for any gas EOR project. In this study, oil and gas samples were collected in the well from perforations inside the Wolfcamp formation of the Permian organic-rich shale. A gas/oil ratio (GOR) of 1230 scf/bbl was chosen to recombine the separator oil and gas on the basis of observed solution GOR values before any increase caused by the flowing bottomhole pressure falling below the bubblepoint pressure.
The pressure/volume/ temperature (PVT) laboratory-testing program consisted of a constant-composition-expansion (CCE) test and a series of swelling tests with CO2. Using the recombined reservoir fluid (with a GOR of 1230 scf/bbl), a CCE test was performed at the reservoir temperature of 162°F to measure the bubblepoint pressure, single-phase oil density, and compressibility. The swelling test results were performed to tune an EOS to be used to calculate oil properties with increasing CO2 concentration during a CO2 flood.
An EOS model was generated to match the CCE data, viscosity data, and CO2 swelling-test data. To use this EOS for CO2 reservoir simulation, the reported system components were grouped, but the CO2 component was left ungrouped. Otherwise, it would be grouped with component C2. The minor component N2 was grouped with C1. All C4s and C5 were grouped together, as were the C6s. The C7+ components were divided into three pseudocomponents.
The charge of a JPT Technology Focus reviewer is not only to select the best SPE papers encountered over the past year but also to identify potential ways in which these papers, and the technology contained therein, can assist the growth of industry professionals. While all of JPT’s feature topics are of great importance to the industry, the technical attention and economic importance attached to unconventional plays in recent years stresses a need for appropriately unconventional thinking. For this year’s feature, the selected papers provide innovative work flows that assist in determining productivity, reduce the effect of uncertainty conditions, and spark rejuvenation.
The first of these, paper SPE 190860, emphasizes the importance of an effective lateral-landing strategy in enhancing long-term reservoir productivity and provides a work flow that uses a suite of integrated data to achieve consistent results that can aid in field management and ultimate recovery estimates.
Paper SPE 191272 uses a case study from the Vaca Muerta Shale in Argentina to demonstrate the efficacy of a work flow that uses a simulation-based approach combined with high-speed computing to improve investor confidence. The authors stress in particular the need to characterize the correct variables and to establish the range of their uncertainty.
Finally, paper SPE 191457 introduces an integrated work flow that couples geomechanical effects and reservoir-simulation modeling in the effort to rejuvenate unconventional plays, stressing interpretation of the variables that can affect the development of the simulated reservoir volume.
These three innovative papers represent, as always, the skill and vision of industry professionals like yourself as we continue to learn from, and add to, the body of technical knowledge that SPE represents. I hope that you enjoy the papers.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 191923 Alleviating the Solids Issue in Surat Basin in Coal-Seam-Gas Wells by Daniel Kalinin, Schlumberger, et al.
SPE 192010 Optimizing Horizontal Coal-Seam-Gas Wells by Combining Reservoir Simulation and Transient Well Modeling by Turaj Nuralishahi, APLNG, et al.
SPE 192694 First Global Successful Large-Diameter Pressurized Coring Application Using High-Performance Water-Based Mud: Kuwait Case History by Robin Stewart, Halliburton, et al.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 191272, “Optimization Under Uncertainty for Reliable Unconventional Play Evaluation: A Case Study in Vaca Muerta Shale Gas Blocks, Argentina,” by Reza Mehranfar, Leonardo Marquez, SPE, Raphael Altman, SPE, Hassan Kolivand, Rodrigo Orantes, and Oswaldo Espinola, SPE, Schlumberger, prepared for the 2018 SPE Trinidad and Tobago Section Energy Resources Conference, Port of Spain, Trinidad and Tobago, 25–26 June. The paper has not been peer reviewed.
Asset evaluation embraces the integrated analysis of a hydrocarbon-bearing field, and the identification of suitable strategies for its future development, to add incremental value for the investor(s). Optimizing the evaluation process under uncertainty is important particularly in unconventional reservoirs, which hold large quantities of oil and gas resources but also exhibit large degrees of uncertainty. This paper describes a comprehensive optimization-under-uncertainty work flow that combines a simulation-based approach with semiautomatic work flows and high-speed computers to facilitate the process of decision-making for investors, using data from the Vaca Muerta Formation in Argentina as an example.
An asset evaluation depends on many input parameters, some of which are partially known, partly analyzed, or un-available. Yet a go/no-go decision must be made, frequently within short time frames, because of competition, changing conditions, or the chance to take advantage of the business opportunity. The decision usually is based on preliminary assumptions and a conscientious analysis of several possible outcomes. Identifying the suitable future development strategies and the estimation of un-certainties in the input variables is crucial. Knowing the possible variability of the input and how the field mechanisms function will allow probabilistic forecasts of parameters such as production, costs, prices, and revenues. In the case of unconventional reservoirs with very limited history and high development costs, optimization under uncertainty plays a significant role in maximizing profit, reducing investment risk, and facilitating the decision-making process.
The authors summarize the optimization-under-uncertainty work flow that was implemented for this study. The starting point is the development of a base-case, single-well, matched simulation model, and, where available, an extended model with history-matched offset wells. This is followed by sensitivity analysis to identify the most-influential parameters; uncertainty analysis and proxy modeling for developing probabilistic forecasting profiles (type wells); and optimization of key parameters under existing uncertainty, which is the final objective of this paper. The model and the uncertainty and optimization work flows have been built in the Petrel platform and all the simulations have been executed in the Eclipse compositional reservoir simulator, using published Vaca Muerta data.
Base-Case Single-Gas-Well Model
A critical element of any single-well simulation study is developing a base-case simulation model that correctly captures all the fluid-flow mechanisms that take place during the life of the well, while running as fast as possible. The characteristics of the base-case single-well simulation model and the mechanisms that were considered are discussed briefly, because the main objective of this work was to focus on probabilistic forecasting and optimization.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191457, “Coupling Geomechanical Effects and Reservoir Dynamics for Modeling Rejuvenation in Unconventional Plays,” by R. Dutta, SPE, Drilling Info; R. Pinto, Sciences Po University; and J.C. Flores, S.M. Stolyarov, SPE, and J. Yang, Baker Hughes, a GE Company, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed.
An integrated understanding of geomechanical effects, fracture propagation, and reservoir dynamics is critical in the efficient and cost-effective application of rejuvenation technologies for unconventional plays. While various reservoir models depicting the hydraulic-fracturing process are available in the industry, many tend to be simplified or do not capture the numerous parameters that affect both the initial and restimulation processes. This work takes a further step toward building a more-realistic picture of fracturing in unconventional plays.
A common assumption in reservoir simulation is that the proppant-fluid mixture is present in the hydraulic fracture before flowback and production. The quantity of water assumed to be present in the hydraulic fractures is a conjecture and is calibrated generally with production-logging tools. These assumptions may skew the results of hydrocarbon recovery.
A method of incorporating geomechanical aspects of fracturing into the model involves the concept of pressure-dependent permeability variation in natural fractures that results in formation of pressure-dependent stimulated reservoir volume (SRV). Hysteretic permeability models employed in numerical modeling can offer a description of the SRV and also can be used in addressing longer-term geomechanical effects in a practical manner. While this concept has matured in the context of modeling hydraulic fracturing in reservoir simulation, it is being newly applied in modeling refracturing treatments.
Because the importance of capillary effect in low-permeability formations is recognized, the authors also incorporate capillary pressure in their model. In addition to pressure-dependent permeability variation, results explain how capillarity is significant in understanding fluid migration, the trapping of fluid in the matrix, and, consequently, restimulation.
The main challenge in selecting good candidate wells for this study was in finding wells that targeted the same formation, used varying refracturing technologies, and had sufficient data to build a reservoir-simulation model with input for the reservoir properties.
After studying a large number of wells, the authors focused on two horizontal gas wells producing from the Barnett Shale. One well was identified to be refractured with a selective zone-treatment method, while the other used a method of fluid diversion. The wells are located approximately 3 miles from each other and approximately 1,600 ft from neighboring wells. These wells have differing production signatures, but this is not indicative of a difference in the performance of two technologies. Understanding the difference in performance may be key to planning a successful refracturing operation.