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Abstract Over the past few years several authors have attempted to explain various non-linear pressure-time derivative behaviors observed in diagnostic fracture injection tests (DFIT's) using mathematical theories and application of conventional pressure transient theory. While based in solid math, these authors have, in some cases, ignored the physical processes that drive the observed pressure behavior. This paper seeks to explain the mechanical and physical processes that can occur during the fracture extension and closure process of a DFIT, with a minimum of equations or abstract mathematics. Two major sources of non-linear (non-ideal) leakoff behavior are addressed. They have been variously termed "pressure dependent leakoff" (PDL), and "variable compliance leakoff" (also known as height recession, transverse storage, variable storage, and by other names). Both of these pressure-time derivative signatures can be caused by multiple mechanisms, but really represent simple and fundamental changes in the rate of pressure decay during fracture closure. This paper explains the assumptions leading to the ideal linear derivative model, and the real processes that can lead to the observed deviations from this ideal model. It is hoped that an explanation of the physical mechanisms represented by these tests will lead to a better understanding of the failure conditions of the rock mass, and character of the induced fracture system. Correct interpretation of these tests is critical to design of effective stimulation treatments and to developing an understanding of the post-frac production characteristics of the well.
- Europe (0.93)
- North America > United States > Colorado (0.28)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract The benefits of hydraulic fracturing horizontal wells in unconventional reservoirs for production enhancement are evident; however, the best methods to truly increase recovery efficiency through these stimulations are still under examination. Analogous to how operators and service companies discovered that Barnett-style slickwater treatments were not successful in all reservoirs, companies are beginning to recognize the importance of engineered stimulations, specifically in regard to geomechanics. Rather than perforating for only production purposes, hydraulic fracturing design has now turned its focus to perforating for reservoir rock stimulation. Enhanced fracture network complexity through induced fractures greatly increases the contact area and reservoir drainage for maximum productivity. However, to accomplish the stimulation of both primary and secondary fracture networks, the coupled behaviors of geomechanics and fluid flow in response to the hydraulic fracturing operations must be considered. In this research study, development of a coupled geomechanics and fluid flow model for the purpose of hydraulic fracture design optimization through the evaluation of different stimulation patterns with primary focus on how the stress and strain distributions within the reservoir that affect porosity and permeability, ultimately influence flow has been discussed in detail. The patterns under consideration include the Zipper, Texas Two-Step, and Modified Zipper designs. Although the Texas Two-Step Pattern requires a special down-hole tool and as such is very difficult operationally to perform, it is being considered in this analysis for conceptual purposes concerning the stress behavior within a single lateral well. Furthermore within these patterns, the well locations and hydraulic fracture properties have been analyzed to determine the optimum design for a shale oil reservoir based on recovery efficiency and generated fracture complexity. The results of this study indicate that with the staggered fracture placement offered by the Modified Zipper Pattern, a highly conductive secondary complex fracture network is generated allowing for enhanced hydrocarbon recovery. In comparison to the Zipper and Texas Two-Step Patterns, the Modified Zipper Pattern reduces the stress anisotropy within the formation to a much greater extent, aiding in the fracture generation process to increase the flow area. This advantage coupled with its high oil recovery factor and potential for greater drilling density discerns the Modified Zipper as the ideal pattern for the development of an Eagle Ford-type shale oil reservoir.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.81)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
A Case Study of Completion Effectiveness in the Eagle Ford Shale Using DAS/DTS Observations and Hydraulic Fracture Modeling
Wheaton, B.. (Devon Energy Corporation) | Haustveit, K.. (Devon Energy Corporation) | Deeg, W.. (Devon Energy Corporation) | Miskimins, J.. (Barree & Associates, LLC) | Barree, R.. (Barree & Associates, LLC)
Abstract The objective of this study was to evaluate treatment distribution and fracture geometry in a multi-stage, multi-cluster fracture completion performed in a horizontal Eagle Ford well. Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) data were acquired on the subject well. The DAS/DTS-observed fracture treatment distributions were then modeled in a three-dimensional fracture model in an effort to visually represent resultant fracture geometries. This process was used to evaluate the impacts on the resulting treatment distributions that occurred as a result of stress-shadowing between fractures. The ultimate goal was to understand the influence that adjacent fractures within a stage and adjacent stages have on fracture distribution, fracture geometry, and completion effectiveness. DAS/DTS data suggest a high level of interference between adjacent fractures. Interference between adjacent fractures within a given stage, and from adjacent fracture stages, results in a consistent geometric predominance for fracture growth in the most heel-ward perforation cluster. DAS/DTS results also indicate that an excessive number of perforation clusters, spaced closely together, magnify the negative effects of stress shadowing, and potentially diminish completion effectiveness. Operationally, the DAS/DTS data showed that the surface pressure response originally attributed to downhole diversion from particulate diverters was in fact not due to diversion. Once a dominate fracture was established in a given stage, it remained dominate throughout the entire stage even though two diverter drops per stage were incorporated into the treatment. Finally, the DAS/DTS data indicated that a significant portion (71%) of the stages experienced intra-stage communication. The large majority of this communication was due to plug leakage.
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.50)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.41)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Cana Woodford Shale Formation (0.99)
Abstract One of the major uncertainties in the analysis of unconventional well productivity is the estimation of the hydraulic fracture height generated during stimulation operations. This study was carried out in a well located in the Neuquen Basin, Argentina with main focus on the development of unconventional shale oil. The strategy consisted in the application of two combined techniques based on different and independent physical principles for the estimation of the hydraulic fracture height. The initial technique consisted in the pumping of proppant which contains elements with great neutron absorption. Thereby, the presence of traced proppant is identified through the differences in the neutron absorption capacity before and after the stimulation at approximately 6 inches from the wellbore. The second technique is based on the characterization of the anisotropy on the shear wave obtained by the dipolar sonic curve in two perpendicular directions. This acquisition should be carried out before and after the stimulation and it is sensitive in the area close to the wellbore. (Between 5 and 40 in) Results from both techniques showed a reasonable good consistency in the results, thus allowing the validation of both methodologies. The results also allowed defining intervals that act as barriers of the hydraulic fracture vertical growth. This permit us the optimization of the fracture design in other wells, thus minimizing the vertical overlapping of the fractures and maximizing the connectivity of the stimulated interval in the well. In addition, traced proppant was confirmed close to the wellbore in several intervals that together represent approximately 60% of the pay which represents a 170 m. To improve completion efficiency, this information can be used to place hydraulic fracture stages and define clusters geometry. Finally, it could be determined that a set of factors allowed the control of the vertical growth of the hydraulic fracture with proppant in the proximity of the wellbore. The main control on hydraulic fracture height was the magnitude of the minimum horizontal stress. The presence of discontinuities in the rocks such as calcite veins volcanoclastic intervals and limestone beds may also play a role. These new data provide confidence on the current geomechanical model helping to optimize the upcoming stimulation operations in the area.
- South America > Argentina > Patagonia Region (1.00)
- South America > Argentina > Neuquén Province > Neuquén (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.35)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract The combination of multistage hydraulic fracture treatments with horizontal drilling technology has been the primary driver to the successful development of resource plays. More than 85% of wells drilled in North America today employ these methods. However, while these technologies have been wildly successful, only recently has the industry begun to address in earnest, the efficiency of current practices. These completion and development optimization efforts require an understanding of which portions of the reservoir have not been adequately contacted/stimulated and are thereby failing to contribute to production, and ultimate hydrocarbon recovery. Understanding where the proppant is located, both near- and far-field, is the starting point for these evaluations, and is the basis for this paper. Traditional fracture mapping technologies provide indirect estimates of fluid distribution within the fracture network. However, there is little direct correlation between fluid distribution and proppant location, and since most unpropped portions of fractures rapidly collapse, identification of the proppant location better represents the region which contributes to ultimate recovery. Near-wellbore detection of proppant can provide insight into whether all perf clusters (in the case of plug and perf) have received proppant as well as the impacts of proppant overflush. Conversely, accurate determination of far-field proppant placement will affect everything from well and stage spacing, to stage design and refrac candidate selection, and allow significant optimization of diversion techniques. While knowledge of both near- and far-field proppant location is necessary for the industry to overcome the single-digit recovery factors that are now projected in many unconventional plays, far-field proppant detection techniques have been largely absent to date. This paper briefly reviews the current "state of the industry" regarding near-wellbore proppant detection technology. It then presents a novel far-field proppant detection technique which utilizes electro-magnetic differencing and a specialty detectable proppant. This includes a description of the technology as well as the methodology of the technique. In addition, the paper reviews the design and results from a recent (first-ever) field deployment of this technology in a horizontal Permian Basin well. Visualization of the proppant in the far-field is also shown. This paper should be beneficial to all engineers and technologists currently interested in evaluating completion efficiencies as well as fracture stimulation effectiveness. Understanding proppant location in both the near- and far-field regions has significant impact on well spacing, stage and perf cluster spacing, and ultimate recovery from stimulated horizontal wells.
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Petroleum Play Type > Unconventional Play (0.68)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Electromagnetic Surveying (0.68)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (33 more...)
Evaluating the Relationship Between Well Parameters and Production Using Multivariate Statistical Models: A Middle Bakken and Three Forks Case History
Lolon, E.. (Liberty Oilfield Services) | Hamidieh, K.. (Rice University) | Weijers, L.. (Liberty Oilfield Services) | Mayerhofer, M.. (Liberty Oilfield Services) | Melcher, H.. (Liberty Oilfield Services) | Oduba, O.. (Liberty Oilfield Services)
Abstract Building a predictive statistical model for evaluating the impact of various fracture treatment and well completion designs on production has been of great interest in the oil and gas industry. The objectives of this study were to evaluate the benefits of advanced statistical and machine-learning techniques for predicting production from oil wells, highlight the strengths and weaknesses of these techniques, and gain insight into the relationship between well parameters and production. The predictive models are described through mathematical functions or algorithms that rely on well data (training set). The ongoing dilemma is that these models often result in poor predictions, even if they result in a high R-squared (0.7 or higher). The new perspective that this study brings is the importance of cross-validation with "hold-out" datasets in the workflow to develop reliable statistical models. A database of available completion and production data has been assembled from the North Dakota Industrial Commission (NDIC) and Frac Focus websites and from internal completion documentation. To date, there are at least 6,800 horizontal wells completed in the Middle Bakken formation and 3,600 completed in the Three Forks formation on the North Dakota side of the Williston Basin. Various models such as multiple regression, random forests, and gradient boosting machine were built to predict the cumulative oil production of the Middle Bakken and Three Forks horizontal wells. Model predictive abilities were assessed by cross-validating the root mean squared errors (in cross-validation, a hold-out set was used to assess the modelis predictive ability). The results showed the following conclusions about statistical evaluation techniques: 1) regression models that account for overfitting provided the best predictive ability, 2) gradient boosting model with the highest R-squared value had the worst predictive ability for the specific datasets in this paper— which shows why it is critical to not rely solely on R-squared value to assess a modelis predictive ability, but to also perform cross-validation, and 3) random forests and gradient boosting machine can be used for determining variable importance. Moreover, we observed that there is statistical evidence to support the presence of important interactions among variables in predicting cumulative oil production. For the Middle Bakken and Three Forks wells included in this study, the results showed that water cut, which can be used as a proxy for reservoir quality, is the most important predictor for cumulative oil production. However, the most important completion-related variables for predicting oil production were total frac fluid and proppant pumped. The analysis and results presented in this paper will enable companies to apply the approach to their own data when building production prediction models and analyzing the complex relationships of variables that control well performance.
- North America > United States > North Dakota (1.00)
- North America > Canada (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (8 more...)
Abstract A better understanding of failure in heterogeneous rock materials can benefit a wide range of areas, from earthquake engineering to petroleum engineering. Study of such failure is of particular interest in the field of hydraulic fracturing. The prediction of this breakage phenomenon is a big challenge for the scientific community. Traditional continuum modeling techniques have the advantage of using classical nonlinear material models, however they often fail to accurately capture the complexity of the fractured geometry and path of multiple intersecting fractures. In particular, mesh dependence of the fracture path, 3D representation of natural fractures and their intersections, closing of an opened fracture, or shear in fractures, are difficult to accurately capture using these techniques. The use of the smoothed particle hydrodynamics (SPH) method for simulation of fracture in solids is relatively recent, where mesh free methods like SPH have the potential to overcome the previously mentioned limitations of mesh based methods. Simulation of the initiation and propagation of pressure-driven fractures in brittle rocks is presented in this study. By exploiting techniques commonly used in traditional continuum methods, we have implemented an elasto-plastic SPH model, which is based on the Drucker-Prager yield criterion, and the Grady-Kipp damage model. Results show that SPH is able to correctly predict the evolution of fracture in brittle rocks. The SPH method has been applied to the solution of crack propagation in a variety of test cases, including a pressurized borehole, 2D line crack, and 3D penny shaped crack. The influence of initial in-situ stresses was also accounted for. Comparison of SPH results for these cases to analytical solutions shows that SPH may be applied to accurately simulate the evolution of fluid-driven fractures in brittle rocks. Such model is a vital tool in correctly predicting fracture propagation in highly heterogeneous formations, for instance, shale formations.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.54)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (0.93)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.93)
Identification of Activated Fracture Networks Using Microseismic Spatial Anomalies, b-values, and Magnitude Analyses in Horn River Basin
Yousefzadeh, Abdolnaser (Schulich School of Engineering, University of Calgary) | Li, Qi (Schulich School of Engineering, University of Calgary) | Virues, Claudio (CNOOC- Nexen) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract We analyzed microseismic spatial and temporal distribution, magnitudes, b-values and treatment data to interpret and explain the observed anomalies in microseismic events recorded during exploitation of Shale Gas reservoirs in the Horn River Basin of Canada. We estimated the directional diffusivity to define the microseismicity front curve for each stage of hydraulic fracturing. Based on our definition of front curves, we managed to separate most of the microseismic events data that are related to natural fracture activation from hydraulic fracturing events. We analyzed the b-values for microseismic events of each stage before and after separating fracture activation microseismic events from original data and created a map of b-values in the study area. This allowed us to locate activated fractures mostly in the northeastern part of the study well pad. The b- value map agrees with our assumption of activated fracture locations and high ratio of seismic activities. Suggested fracture locations agree with anomalous events' density, energy distribution and treatment data. We are defining and proposing intermediate b-values for calculation of the stimulated reservoir volume (SRV) in areas with both hydraulically fractured events and events related to natural fracture network activation in those instances where the separation of events based on their origin is not viable.
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.36)
- North America > United States > Kansas > Thomas Lease > Simpson Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Muskwa Field > Muskwa Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Zama Virgo Basin > Keg River Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Otter Park Formation (0.94)
Abstract A workflow that uses the strain derived from geomechanical modeling of hydraulic fractures interacting with natural fractures is applied to a Fayetteville shale well. The derived strain map is used to estimate the asymmetric half lengths that are input in a frac design software able to incorporate this information. The usual symmetric bi-wing design is replaced by realistic asymmetric half lengths observed in microseismic data by adjusting the leakoff coefficient, injection rate and the proppant concentration in such a way that the asymmetric half lengths of the frac design do not exceed the lengths of those provided by the strain map. Once the half lengths and orientation from the frac design match those provided by geomechanical simulation, the propped length and other key results provided by the frac design software are used in reservoir simulation. The derived strain is correlated to stimulated permeability through two calibration constants estimated during history matching. After history matching, the resulting pressure distribution facilitates more informed selection of refrac or new well candidates, optimization of well spacing, and estimation of an accurate EUR.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.65)
- North America > United States > Oklahoma > Arkoma Basin > Fayetteville Shale Formation (0.99)
- North America > United States > Arkansas > Arkoma Basin > Fayetteville Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.89)
- (8 more...)
Abstract Microseismic mapping during hydraulic fracturing processes in Vaca Muerta (VM) Shale in Argentina shows a group of microseismic events happening at shallower depth and at later injection time, and they clearly deviate from the growing planar hydraulic fracture. This spatial and temporal behavior of these shallow microseismic events incurs some questions regarding the nature of these events and their connectivity to the hydraulic fracture. To answer these questions, in this paper, we investigate these phenomena using a true 3D fracture propagation modeling tool along with statistical analysis on the properties of microseismic events. First, we propose a novel technique in Abaqus incorporating fracture intersections in true 3D hydraulic fracture propagation simulations based on pore-pressure Cohesive Zone Model (CZM). The simulations fully couple slit flow in fracture with poro-elasticity in matrix and continuum-based leak-off on the fracture walls, and honor the fracture tip effects in quasi-brittle shale. Using this model, we quantify vertical natural fracture activation depending on reservoir depth, fracturing fluid viscosity, mechanical properties of the natural fracture cohesive layer, natural fracture conductivity, and horizontal stress contrast. The modeling results demonstrate this natural fracture activation in coincidence with the hydraulic fracture growth complexities at the intersection such as height throttling, sharp aperture reduction after the intersection, and multi-branching at various heights and directions. Finally, we investigate the hydraulic fracture intersection with a natural fracture in the multi-layer VM Shale. We infer the natural fracture location and orientation from the microseismic events map and Formation MicroImager log in a nearby vertical well, respectively. We integrate the other field information such as mechanical, geological, and operational data to provide a realistic hydraulic fracturing simulation in the presence of a natural fracture. Our 3D fracturing simulations equipped by the new fracture intersection model rigorously simulate the growth of a realistic hydraulic connection path toward the natural fracture at shallower depths, which was in agreement with our microseismic observations.
- North America > United States > Texas (1.00)
- South America > Argentina > Neuquén Province > Neuquén (0.82)
- South America > Argentina > Patagonia Region (0.64)
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.93)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Quintuco Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)