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Results
Frac Charge Performance at Downhole Conditions: Assessments and Implications
Grove, Brenden (Halliburton Jet Research Center) | McGregor, Jacob (Halliburton Jet Research Center) | DeHart, Rory (Halliburton Jet Research Center) | Dusterhoft, Ron (Halliburton) | Stegent, Neil (Halliburton) | Grader, Avrami (Ingrain, a Halliburton Service)
Abstract Hydraulically fractured completions dominate industry perforating activity, particularly in North American land basins. This has led to the development of fracture-optimized perforating systems in recent years. Aside from overarching safety, reliability, and efficiency priorities, the main technical performance attribute of these systems is consistent hole size in the casing, driven by limited entry fracture design considerations. While the industry continues to seek further improvements in hole size consistency, attention is also being directed to the perforations more holistically, from a perspective of maximizing the effectiveness of subsequent hydraulic fracturing and ultimately production operations. To this end, this paper presents two related activities addressing the development, qualification, and optimization of perf-for-frac systems. The first is a surface testing protocol used to characterize perforating system performance, in particular casing hole size and consistency. The second is a laboratory program, recently conducted to investigate perforating stressed Eagle Ford shale samples at downhole conditions. This program explored the influences of charge size, formation lamination direction, pore fluid, and dynamic underbalance on perforation characteristics. Casing hole size was also assessed. For the first activity (surface testing), we find that using cement-backed casing can be an important feature to ensure more downhole-realistic results. For the second activity (laboratory program), perforation casing hole sizes for the charges tested were in line with expectations based on existing surface test data, exhibiting negligible pressure dependency. Corresponding penetration depths into the stressed shale samples generally ranged from 3.5-in to 5-in, which is much shallower than might be expected based on surface concrete performance. Dynamic underbalance was found to exhibit some slight effect on the tunnel fill characteristics, while pore system fluid was found to have minimal influence on the results. An interesting feature of the perforated samples was the complex fracture network at the perforation tips, which appeared "propped" to some extent with charge liner debris. Some of these fractures were formation beds which had delaminated during the shot, a phenomenon observed for perforations both parallel and perpendicular to the laminations. The implications of these results to the downhole environment continues to be assessed. Of particular interest is the impact these phenomena might have on fracture initiation, formation breakdown, and treatment stages which accompany subsequent hydraulic fracturing pumping operations.
- North America > United States > Texas (1.00)
- Asia (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.47)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.35)
- 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)
- (4 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
Wolfcamp Hydraulic Fracture Test Site Drained Rock Volume and Recovery Factors Visualized by Scaled Complex Analysis Method (CAM): Emulating Multiple Data Sources (Production Rates, Water Cuts, Pressure Gauges, Flow Regime Changes, and b-Sigmoids)
Weijermars, Ruud (Texas A&M University) | Nandlal, Kiran (Texas A&M University) | Tugan, Murat Fatih (Texas A&M University) | Dusterhoft, Ron (Halliburton) | Stegent, Neil (Halliburton)
Abstract Shale field development strategies are aimed at increasing recovery factors and thus revolve around well-spacing decisions and hydraulic fracture treatment plans. The hydraulic fracture test site (HFTS) consortium provided invaluable data and insight in terms of the interaction between multiple wellbore pads. Although pressure communication between wellbores during completion and production has been analyzed in previous HFTS studies, relatively little work has been performed to constrain the actual reservoir volume being recovered—this paper addresses an integrated approach to assess the development of the drained rock volume (DRV) and recovery factors. A detailed analysis of flow regime changes, shows when the first fracture pressure interference occurs in each well, and also pinpoints the onset of inter-well pressure interference. Computation of the instantaneous b-value from well rate decline data reveals the occurrence of b-sigmoid patterns, which provide a more detailed indication of the onset of flow regime shifts and pressure interference (with adjacent fractures and well drainage boundaries). Typical changes in water-oil ratios (WOR) and gas-oil ratios (GOR) were also studied, in particular in conjunction with flow regime shifts and bubble point pressure flips during well shut-in tests. Understanding flow regime shifts related to (1) the diffusive advance of pressure transients, and (2) the convective growth of the DRV, can help design more efficient well spacing, cluster staging, perforation design, lateral length and landing targets, fracture design and geometry, etc. to increase hydrocarbon recovery factors. 1. Introduction The US Department of Energy (DOE) sanctioned in 2014 two major field test sites to study the effects of hydraulic fracturing when applied to hydrocarbon reservoirs with multi-well development. One field project was staged in the Eagle Ford Formation, in a lease region in DeWitt County, Texas (Raterman et al., 2018, 2019); the other so-called HFTS project was located in the Permian Basin (DOE award number DE-FE0024292) and studied well completions in the Wolfcamp Formation, in a lease region in Reagan County, Texas (Ciezobka et al., 2018). Both projects were enabled by consortia of participating companies and research institutions (such as NETL, UT Austin and BEG), matching the DOE funding with subcontracted services and in-kind contributions. The two projects were managed by the Gas Technology Institute based in Des Plaines, Illinois, a non-profit organization which develops, demonstrates, and licenses new energy technologies for private and public clients, with a particular focus on the natural gas industry.
- North America > United States > Texas > Reagan County (0.24)
- North America > United States > Texas > DeWitt County (0.24)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.48)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Recovery factors (1.00)
- (3 more...)
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.
- North America > United States > Texas (1.00)
- North America > Canada (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Codell Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (38 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- (5 more...)
A Kinetic Monte Carlo Study to Investigate the Effective Permeability and Conductivity of Microfractures within Unconventional Reservoirs
Inyang, Ubong (Halliburton) | Cortez-Montalvo, Janette (Halliburton) | Dusterhoft, Ron (Halliburton) | Apostolopoulou, Maria (University College London) | Striolo, Alberto (University College London) | Stamatakis, Michail (University College London)
Abstract Estimating the effective permeability and microfracture (MF) conductivity for unconventional reservoirs can be challenging; however, a new method for estimating using a stochastic approach is discussed. This new analysis method estimates matrix permeability and the unpropped and propped MF conductivities during laboratory testing where MFs were propped with ultrafine particles (UFPs). Kinetic Monte Carlo (KMC) simulations form the basis of the method used to estimate effective permeability of the core sample. First, the stochastic model was implemented to calculate effective matrix permeability of a small core taken from unfractured Eagle Ford and Marcellus formation samples using scanning electron microscopy (SEM) images and adsorption data to obtain the pore-size distribution (PSD) within the sample. The KMC approach then evaluated the effect of various parameters influencing the conductivity of laboratory-created MFs. Case studies considered for this work investigate the conductivity improvement of a manmade MF as a function of the UFPs used as proppants that maintain width under high stress, the UFP (proppant) concentration, and the UFP flow perpendicular into a secondary or adjacent MF zone (2MF) penetrating the face of an opened MF during flow testing under stress. The leakoff area widths considered were 1, 2, and 3 mm and can be propped or unpropped. Results obtained for the unfractured Eagle Ford and Marcellus samples closely correlate with other computational and experimental data available. For the laboratory-prepared nonpropped and propped MF samples, the effective propped width was determined to have the greatest effect on the MF conductivity, which increased by two orders of magnitude in the presence of the UFPs. The remaining two factors—proppant concentration and length of 2MFs—helped improve the effective MF conductivity in a linear manner; the highest proppant concentration and the 2MF zone resulted in the highest fracture conductivity achieved. Insight obtained from this study can be used to optimize fracturing designs by including UFPs and to create strategies for maximizing hydrocarbon recovery during development of unconventional resources where MFs are opened during stimulation treatments.
- North America > United States > Texas (0.46)
- North America > United States > California (0.46)
- North America > United States > Oklahoma (0.29)
- Geology > Geological Subdiscipline (0.68)
- Geology > Mineral (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.30)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract Most current hydraulic fracturing operations are performed in unconventional reservoirs (i.e., tight gas and oil reservoirs and organic-rich shale plays) that have sub-microdarcy permeability and require stimulation to achieve commercial flow. Hydraulic fracturing helps unlock these reservoirs by creating a fracture network to access the resources. This paper evaluates the mechanism by which a nonuniform partial monolayer of small-sized proppants with particle sizes much less than 100 mesh can significantly enhance the conductivity of the complex microfracture (MF) network. To evaluate smaller proppant particles, a new test design was used to measure fracture conductivity of unpropped MFs and MFs propped with extremely small quantities of ultra-fine particulates (UFPs) on outcrop samples from Marcellus, Eagle Ford, and Barnett Shale formations, including an actual Delaware Wolfcamp core. Geomechanical testing on formation samples determined their mechanical properties, UFP distribution along the created fracture faces before and after UFP treatment was studied using computed tomography (CT) scans, and X-ray diffraction quantitatively assessed reservoir rock mineralogy to identify potential rock-fluid interactions that could affect longterm conductivity. This study evaluates the impact of effective stress on the created MF permeability, helping understand the influence of UFPs on long-term MF conductivity. Additionally, the effective conductivity is influenced by the UFP concentration, core mineralogy, and sample anisotropy of the outcrop cores used for this study. Field applications of UFP materials have proven to be successful with increasing well productivity and sustaining higher productivity over a significantly longer period of time. This experimental study demonstrates the impact of small quantities of extremely small proppant materials on the effective conductivity of MFs created during hydraulic fracturing operations. The improved conductivity observed during these tests clearly demonstrates that these materials can increase the effective permeability of the formation surrounding primary hydraulic fractures. This paper provides summarized test results and computer simulation to establish well productivity effects. The experimental results are compared to actual well productions to validate the study.
- North America > United States > Texas (1.00)
- Europe (0.93)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.56)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Cana Woodford Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.89)
- (11 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (3 more...)
Abstract This paper describes the stress-dependent permeability of split shale core plugs from Eagle Ford, Bakken, and Barnett formation samples studied in presence of microproppants in microcracks. An analytical permeability model is developed, including the interaction between the fracture walls and monolayer microproppants under stress. The model is then used to analyze a series of pressure pulse decay measurements of the propped shale samples in the laboratory. The analysis provides the propped fracture permeability of the samples and predicts a parameter related to the quality of the proppant areal distribution in the fracture. The proppant placement quality can be used as a measure of success of the delivery of proppants into the fractures and to design stimulation in the laboratory.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.95)
- 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)
- (5 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Abstract Because commodity prices have substantially decreased since peaking in late 2014, operators have implemented strategies that focus on the most prolific acreage and have concentrated drilling activities on the "sweet spots" in many unconventional plays. This development practice has resulted in decreased well spacing and infill (development) wells being drilled in close proximity to parent (delineation) wells, causing lower productivity than expected in many development wells because of drainage area and fracture interference. Many operators use a method known as parent well protection (PWP) to help mitigate this effect and increase recovery from both parent (delineation) and closely offsetting development (child) wells. This paper presents an analysis of the economic impact of PWP treatments performed for repressurizing the reservoir system and chemical stimulation of the parent well. This evaluation of PWP production benefits was performed using a combination of numerical reservoir simulation with advanced gridding and reservoir modeling capabilities and economic analysis tools for net present value (NPV) evaluation. Advanced modeling capabilities helped enable grid transformation of the simulation grid at the time of completion of the infill well to simulate the effects of drainage area interference. Wellbore flow parameter alterations modeling near-wellbore (NWB) and skin damage effects were implemented. In addition to fracture interference mitigation, NWB damage remediation of the parent well was implemented at varying magnitudes to simulate the effects of a chemical stimulation treatment performed in conjunction with the repressurization treatment. An analysis of the fiscal impact of the PWP treatment with water only and PWP treatment with stimulation fluids was performed to determine the scenario with optimal NPV. Results indicated that substantial benefit can be realized through PWP treatments. The primary goal of the PWP treatment is to help prevent production loss in the parent well and mitigate production interference from the child well completion. Production interference is caused by asymmetric fracture growth from the child well completions into the depleted region around the parent well (typically the area of least stress). Simulation results showed that mitigation of asymmetric fracture growth can result in an increase in 4-year cumulative recovery of up to 21%. Chemical stimulation treatments addressing only NWB/skin damage can result in an increase in 4-year cumulative recovery of up to 16%. Combining both resulted in an increase of up to 36%. The break-even price for the cost of the PWP treatment, rate of return (ROR), and return on investment (ROI) were evaluated and associated with the cumulative production of the various reservoir models. This paper presents case histories and examples of PWP treatments. The benefits of PWP treatments cannot only be evaluated based on the incremental recovery in the parent well, but should also take into account production loss from fracture interference in both the parent and child wells. Increased recovery and economics can be achieved through stimulation of the parent well in conjunction with repressurizing, prior to completion of the child well.
- North America > United States > Texas (1.00)
- Europe (0.93)
- 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)
- (11 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (3 more...)
Summary This paper presents a new workflow that combines the stochastic earth model and geomechanical analysis to assess the best geological landing intervals and geomechanical targeting zones in unconventional reservoirs before drilling and completion operations. The stochastic earth model uses geostatistical algorithms and multivariate analytics to create a shale quality index (QI) that identifies potential zones with a high probability of containing organic-rich, brittle shales with low effective shale water saturation. The geomechanical analysis uses the material point method (MPM) solid mechanics tools to assess the stress field in the fractured reservoir. This helps identify the best zones for hydraulic fracturing operations that can enable the development of a complex stimulated reservoir volume. The value of combining the two methods is illustrated in two generic areas (Areas A and B). Both areas have the same high shale QI but have different fracture sets characteristics. Area A has a broad range of fractures orientation and Area B has a uniform orientation. A sensitivity analysis highlighted the importance of shear fractures for deriving stress variability. Fractures oriented along and perpendicular to the maximum horizontal stress showed less impact. However, the final stress field was driven by the interaction between different fractures sets, when present. Geomechanical analysis of Area A indicated many zones of low-to-medium differential stress (DS) within high QI zones. However, Area B had a zone of high DS. Area A had a broader range of fracture orientation, which could result in more stress variability and possible connectivity of the induced fractures to the reservoir. These observations could affect the production of wells in similar areas. Therefore, the combined geomechanical and earth model analysis workflow is important to better understand shale reservoirs and adapt stimulation treatments according to local stress conditions related to the reservoir geology and geomechanics sweet spots. Thus, the integrated shale QI and geomechanical analysis can be used to design a fracturing operations strategy for wells to determine target stages. Introduction The current low commodity prices present numerous challenges in the oil and gas industry, particularly in the unconventional reservoirs that have experienced tremendous growth in the past decade and still hold significant untapped potential. The positive aspect of the current downturn is the recognition that current hydraulic fracturing practices do not meet expectations, thus initiating new industry-wide efforts to optimize drilling and completion strategies in unconventional reservoirs.
- North America > United States > Texas (1.00)
- Asia (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (66 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract Horizontal wells in liquids-rich shale plays are now being drilled such that lateral and vertical distances between adjacent wells are significantly reduced. In multistacked reservoirs, fracture height and orientation from geomechanical effects coupled with natural fractures create additional complications; therefore, predicting well performance using numerical simulation becomes challenging. This paper describes numerical simulation results from a three-well pad in a stacked liquids-rich reservoir (containing gas condensates) to understand the interaction between wells and production behavior. This paper discusses the use of an unstructured grid-based numerical simulator that incorporates complicated geometries of both hydraulic and natural fractures. It can handle compositional simulation to better model gas condensates with special focus on timing of third well placement and the loss of conductivity effects on production from these wells. A base case was created with a stacked shale play containing three parallel wells but with staggered elevations. Variables used in this study include matrix permeability, condensate-to-gas ratio (CGR), fracture length, well staggering, time of well placement, conductivity degradation, and presence of natural fractures. Simulation runs were conducted for a five-year duration. More than 20 compositional simulation runs were conducted. For the base case, staggering resulted in a slight decrease in both cumulative oil and gas production compared to a case without staggering. Matrix permeability had the most dominant effect on both oil and gas production. Fracture and matrix conductivity losses were more detrimental to cumulative gas production than oil production. For the limited cases studied, placement of the third well one year after the first two wells began producing resulted in a spike in both oil and gas production from the pad. This produced cumulative oil and gas amount was close to that of three wells producing simultaneously, especially if fracture half-lengths for the third well were the same as the first two. However, cumulative oil and gas production reduced significantly if fracture half-lengths were smaller than the other two wells. When all wells experienced significant conductivity loss, gas production was affected more than oil production when the third well was placed one year after the first two wells began producing. In all cases, placing the third well between the other wells was helpful in increasing overall production from this pad. Natural fractures increased both oil and gas production in the cases studied. This paper addresses important issues associated with a liquids-rich unconventional play. It demonstrates successful use of unstructured grid-based reservoir simulation modeling to address well placement timing, well staggering, conductivity damage effects, natural fractures, hydraulic fractures not perpendicular to the wellbores, and several other important issues for which little is known so far. Results from this study type can be used to make important decisions regarding well placement and timing in a multiwell setting.
- Asia (1.00)
- Europe (0.68)
- North America > United States > Texas (0.47)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (7 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- (5 more...)
Summary Throughout the past several years, economic and technological advancements in the North American shale market with respect to drilling and hydraulic-fracturing operations have helped create a “typical” operating scheme for producing from the multiple shale-formation reservoirs currently being exploited. This typical scheme focuses on operational efficiency and cost reduction to drive profitability in these markets. Although operational efficiency and effective cost control have led to more-profitable operations in these shale reservoirs, the unknowns regarding the subsurface of these highly complex formations can often create situations of operating without sufficient information to optimally design drilling-and-completions strategies to produce larger volumes of hydrocarbon from the reservoir. Opposed to conventional operations, the amount of basin and asset knowledge being collected and developed in most of these shale plays is much lower, and thus can result in poor development decisions, leading to less than optimum economic performance. Focus on subsurface knowledge as well as collaboration between the various aspects of developing an asset is essential to helping discover and produce more oil and gas from these complex reservoir systems. This paper examines a case study of three wells in Wise County, Texas, in the Barnett shale, where a collaborative subsurface insight investigation and a drilling-and-completions optimization process were used to illustrate the production benefit achieved through improved reservoir understanding. Within this process, an asset Earth model was created with the collected information from wireline logging, logging while drilling, core testing, mechanical rock and fluid properties, formation mineralogy, and wellbore-image logging. In addition, for the completions-design strategy, microseismic measurement and image-log fracture matching and complex-fracture modeling software tools were used to define and model the growth of the stimulated fracture network during hydraulic-fracturing completions. This paper presents an overview of “typical” previous completions and subsurface information collected before implementation of the new process in comparison to changes made to the drilling-and-completions designs used on three wells, as well as an overview of the types of information collected to supply the Earth model. Examples of the fracture matching and complex-fracture modeling for the wells help illustrate the design and optimization of hydraulic-fracturing treatments in a complex shale reservoir. Finally, a production-results comparison is presented to illustrate a significant increase to production of hydrocarbon through better reservoir understanding and drilling-and-completion designs.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.88)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.54)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Michigan > Michigan Basin > Wise Field > Dundee Limestone Formation (0.97)
- 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 > Shale gas (1.00)
- (3 more...)