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Abstract In this case study, we apply a novel fracture imaging and interpretation workflow to take a systematic look at hydraulic fractures captured during thorugh fracture coring at the Hydraulic Fracturing Test Site (HFTS) in Midland Basin. Digital fracture maps rendered using high resolution 3D laser scans are analyzed for fracture morphology and roughness. Analysis of hydraulic fracture faces show that the roughness varies systematically in clusters with average cluster separation of approximately 20' along the core. While isolated smooth hydraulic fractures are observed in the dataset, very rough fractures are found to be accompanied by proximal smoother fractures. Roughness distribution also helps understand the effect of stresses on fracture distribution. Locally, fracture roughness seems to vary with fracture orientations indicating possible inter-fracture stress effects. At the scale of stage lengths however, we see evidence of inter-stage stress effects. We also observe fracture morphology being strongly driven by rock properties and changes in lithology. Identified proppant distribution along the cored interval is also correlated with roughness variations and we observe strong positive correlation between proppant concentrations and fracture roughness at the local scale. Finally, based on the observed distribution of hydraulic fracture properties, we propose a conceptual spatio-temporal model of fracture propagation which can help explain the hydraulic fracture roughness distribution and ties in other observations as well.
This study analyzes in detail the different pressure depletion patterns occurring when the effective conductivities of the various hydraulic fractures in a stage are different. Currently prevalent modeling practice commonly assigns the same fracture conductivity to the fractures in each stage, assuming uniform contributions to the production of the well. Recent studies, however, have shown that geomechanical stress shadowing effects during the fracturing of rocks with high horizontal stress anisotropy may result in considerable spatial variation of hydraulic fracture quality. For example, in a stage with three clusters, only one "super-fracture" may consume the entirety of the injected fluid, and the created fracture performance will significantly differ from the intended completion design. Our study shows that the drained rock volume (DRV) and pressure drawdown patterns around individual hydraulic fractures may significantly vary, depending upon the conductivity of the hydraulic fractures. We use both a numerical reservoir simulator (CMG) and a Eulerian particle tracking model, based on complex analysis methods (CAM). Our study shows that the fluid flux from individual hydraulic fractures may spatially vary, mainly due to fracture interference, even when the fracture conductivity is the same. A field example from the Eagle Ford shale play is presented. This systematic study leads to a better understanding of the effects on well performance of either variable or constant hydraulic fracture conductivities within the same fracture stage (e.g., due to even or uneven proppant concentration). Our results can be applied to wells from any unconventional play to better manage the DRV, based on fracture treatment design and execution quality (e.g., perforation and proppant placement), and improve the fracture treatment plan accordingly. Ultimately, the findings reported here can be used to mitigate the adverse impacts of flow interference in closely spaced hydraulic fractures.
The development of unconventional shale reservoirs has increased rapidly due to the technological advancements in multi-pad horizontal drilling with numerous transverse hydraulic fractures. The hydraulic fractures enhance the conductivity of the reservoirs previously deemed uneconomic due to their low permeability. However, even with closely spaced hydraulic fractures, the recovery factor of unconventional shale reservoirs remains extremely low (e.g., as low as ~4% for Midland basin wells; Khanal et al., 2019). The low recovery factor for hydraulically fractured unconventional wells can partly be attributed to water oil ratios of 3 or higher in certain shale wells, but is also due to highly complex and unpredictable interactions of hydraulic fractures competing for fluid withdrawal from the drainage space. The determination and optimization of hydraulic fracture geometry, the distribution of the proppant within the fractures, the number of producing fractures, effective fracture half-lengths/conductivity and other attributes remain key concerns in the oil and gas industry.
McClure, Mark (ResFrac Corporation) | Picone, Matteo (ResFrac Corporation) | Fowler, Garrett (ResFrac Corporation) | Ratcliff, Dave (ResFrac Corporation) | Kang, Charles (ResFrac Corporation) | Medam, Soma (ResFrac Corporation) | Frantz, Joe (ResFrac Corporation)
Abstract Hydraulic fracturing and reservoir simulation are used by operators in shale to optimize design parameters such as well spacing, cluster spacing, and injection schedule. In this paper, we address ‘freqently asked questions’ that we encounter when working on hydraulic fracture modeling projects with operators. First, we discuss three high-level topics: (1) data-driven and physics-based models, (2) the modeling workflow, and (3) planar-fracture modeling versus ‘complex fracture network’ modeling. Next, we address specific technical topics related to modeling and the overall physics of hydraulic fracturing: (1) interrelationships between cluster spacing and other design parameters, (2) processes affecting fracture size, (3) fracture symmetry/asymmetry, (4) proppant settling versus trapping, (5) applications of Rate-Transient Analysis (RTA), (6) net pressure matching, (7) Initial Shut-In Pressure (ISIP) trends along the wellbore, and (8) the effect of understressed/underpressured layers. We discuss practical modeling decisions in the context of field observations.
In this paper, we introduce a novel fracture imaging method which uses high resolution 3D laser scanning to develop detailed surface maps of the core fracture faces. The digital maps are then used to analyze fracture surface characteristics wherein observed variations provide us with meaningful insights into the fractures. We share a mathematical approach for roughness evaluation to identify morphological properties for individual fractures within rock samples. The approach is tested on core extracted at the Hydraulic Fracturing Test Site (HFTS - 1) in the Permian Basin. We characterize the roughness variations with depth across the cored section. In addition, we compare results obtained previously from core sampling and analysis to demonstrate that proppant entrapment observed within the cored interval is strongly correlated with the changes in fracture morphology. We also use calculated roughness along with the the changing behavior of roughness radially away from the center of fracture faces to predict roughness "types" such as propagational features or textural roughness characteristics. Based on the specific fracture characterization work shared here as well as other potential uses, our paper highlights significant advantages such scanning and digital imaging of fractures may have over traditional cataloging using photographic imaging. Furthermore, as demonstrated in this study, data sampled from these detailed maps can be used to further characterize and analyze these features in a more systematic and robust manner when compared with the more traditional geological analysis of cores.
Abstract This paper is a companion to URTeC 2670034, “Sampling a Stimulated Rock Volume: An Eagle Ford Example.” That paper detailed the nature of the stimulated rock volume adjacent to a hydraulically fractured horizontal well. It demonstrated that hydraulic fractures are far reaching and abundant but quite variably distributed spatially; the presence of well propped fractures beyond 100 feet of the stimulated well appeared negligible. The present paper reconciles the production performance of the central pilot well with far-field pressure monitor data to characterize the drained rock volume (DRV). Central to the stimulated reservoir description is the integration of data from core, image logs, proppant tracer, distributed temperature sensing (DTS), distributed acoustic sensing (DAS) and pressure which shows that not all hydraulic fractures are created equal. Principal and secondary hydraulic fractures are identified based on the correlation between image log interpreted fracture aperture and the far-field pressure data. Analysis of distributed temperature data during the completion and warm back period is furthermore used to infer fracture connectivity to the well. A highly fractured near well region between clusters is concluded. A novel data-driven reservoir model is constructed wherein the key interpretations are consistently integrated. Production, bottom hole pressure, and far-field pressure data from 14 pressure monitoring stations are history matched. A heterogeneous drained rock volume is predicted. The integrated model is compared to common production history matched planar fracture models to assess the potential impacts on cluster spacing, well spacing, and well stacking decisions. Introduction In 2017 ConocoPhillips reported (Raterman, et al., 2018) on a pilot conducted in the Eagle Ford (EF) shale that was internally referred to as the “SRV pilot”. The original paper dealt primarily with the execution of the pilot and the attendant description of hydraulic and natural fractures within the timulated ock olume. The observations were derived from multiple core and image logs acquired in a series of five drill through wells sampling a total of 7700 feet proximal to a stimulated producer within the EF Formation. Notable conclusions regarding hydraulic fractures included the following. Hydraulic fractures are numerous and broadly subparallel. There are many more fractures than perforation clusters. In the piloted area, the hydraulic fracture density decreases above and laterally away from the producer. The SRV is likely broader than tall, some fractures extending as far as 1500 feet. Fracture deflection, offset and branching at bedding surfaces and other naturally occurring heterogeneities appears to significantly promote fracture complexity. At the locations sampled, from as near as 60 to as far as 400 feet from the producer, evidence for well propped fractures is sparse.
Summary The recent slump in oil prices has resulted in new terminology: “drilled uncompleted wells,” often referred to as DUC wells by the industry. In 2013 and 2014, when oil prices were more than USD 100/bbl, rate of return (ROR) from most unconventional plays was in the range of 15 to 50%, depending on the quality of rock and the operator's portfolio in the basin. The objective of this paper is to address key challenges associated with DUC completions when they are eventually fractured and brought on line for production. The paper addresses four main concerns that can have significant impacts on productivity of DUC wells: fracture hits (well interference), reservoir quality (hydrocarbon drainage), multiple horizons (zone connectivity), and well spacing (high-density drilling). The paper also showcases case studies in which real-time observations made from wells have been used to validate predictions from forward-looking fracture and production models. First, fracture hits commonly have been observed in all unconventional plays throughout the US, with effects on offset wells being mixed. Some fracture hits result in a positive uptick in production in offset wells, whereas other fracture hits affect production negatively in the form of increased water cut, reduced wellhead pressure, and other responses. Understanding fracture hits and their influence on other wells is very critical to avoid any detrimental impacts or to leverage positive effects on production. Second, reservoir quality decides how much oil in place is available for the DUC wells to drain, which, in turn, depends on length of production history and parent-well-completion geometries in offset wells. Third, in basins where there are multiple producing horizons or formations, fracture-height growth and interference between adjacent formations can result in asymmetric fracture propagation toward depleted zones. The longer these wells completed in the same/adjacent formations have been on production, the greater the extent of asymmetry will be. Addressing this concern requires a good understanding of drainage patterns from offset wells and evaluation of their impact on fracture geometries in DUC wells. Last, in areas with high-density drilling, a combination of longer production and fracturing stages with multiple perforation clusters per stage can leave very little oil available for the DUC well to produce.
Abstract This paper presents a new workflow comprised of using hydraulic fracture modeling outputs (effective length, height, and conductivity) for the next step - a discrete fracture flow model which visualizes the drainage pattern in 3D based on history matched production data. The first part of the paper is designated to fracture forward modeling and prediction of the proppant placement geometry and conductivity of hydraulic fractures in a multistage horizontal well. The influence of wellbore deviations and other local initial conditions are all taken into account and explain localized fracture initiation, fracture asymmetry, and propagation, as well as proppant placement efficiency. The primary model focus is on the creation of fracture conductivity maps, one for each transverse fracture. The second part of this study shows the process of import and conversion of 2D fracture conductivity maps for further use in fluid flow allocation to the individual fractures. The 3D Drained Rock Volume (DRV) is rendered based on 2D streamline and time-of-flight maps for drainage, velocity and pressure depletion with 5 ft vertical resolution layers representing the reservoir. Instead of using a grid-based numerical simulation, we apply a meshless flow model based on Complex Analysis Methods (CAM) to solve linear differential equations. The fluid velocity field is computed for narrowly discretized time steps, which allows high-resolution visualization of hydrocarbon flow near and into each of the discrete fractures. Honoring critical physical interaction of fracture fluid, rock mechanics, proppant transport, the fracture propagation model coupled with the flow model for discrete fractures, provides a powerful tool to pinpoint the drained rock volume. Our systematic study highlights trade-offs between fracture design inputs and the total drained rock volume. Field data from the Wolfcamp Formation, Midland Basin in West Texas, provides a real-world case to demonstrate our workflow. Recommendations are made for adjusting frac design and improving the recovery factor of hydrocarbons in place.
Inconsistent production performance from wells completed in similar pay zones has been observed when shale formations are exploited through horizontal wells. Ineffective completion practices, fracture design, and reservoir heterogeneity have generally been blamed for the variability in the performance. Limited importance has been attached to drilling quality and well trajectory placement in the current approaches by the operators. The objective of this study is to demonstrate an engineered lateral landing approach for improved long-term productivity in the unconventional reservoirs.
Coupling the reservoir model to the wellbore and accounting for the transient flow behavior are important for improving deliverability in horizontal wells. The study in this paper encompasses a field case study of a geocellular and geomechanical earth model in the Permian basin, which involves hydraulic fracturing modeling, reservoir simulation, fluid flowback, and transient wellbore flow modeling. Pressure losses accounted for in the reservoir, in the near-wellbore region, and in the wellbore profile are modeled and calibrated with bottomhole and surface gauge measurements. Complex hydraulic fracture geometry and numerical reservoir simulation are used to characterize the pressure losses in the reservoir. Transient wellbore fluid flow considerations are used to evaluate the pressure losses in the wellbore.
Based on the fracturing fluid type, the conductivity profile of the hydraulic fractures, connection to the wellbore, and coverage of the pay zone are important criteria in considering the landing location for wells in unconventional reservoirs. However, having the most effective hydraulic fracture design is not enough to decide the well trajectory. Mitigating liquid loading, fluid flowback, proppant settling, and cross-flow of reservoir fluid helps to diagnose the true production potential. Therefore, transient flow models were coupled to the reservoir and fracture models to design a more-effective well trajectory.
The study demonstrates the need to couple the wellbore model to the reservoir simulation and hydraulic fracturing model in shale formations to optimize well landing, trajectory profile, and long-term productivity.
The methodology provides the first integrated data workflow for well drilling and trajectory planning in unconventional reservoirs that is generated from the perspective of reservoir potential and deliverability. Although variances exist in completion effectiveness due to reservoir heterogeneity, applying the robust modeling workflow as discussed in this study would help deliver consistent results that can be used in field management and EUR estimates across various shale basins.
Abstract Restimulation treatments have been attempted in a wide variety of reservoirs, and more than 140 papers have been published documenting the success and failure of these efforts. A database of these published examples has been compiled and analyzed to identify the mechanisms responsible for production improvement following restimulation with propped fractures (refracs). A portion of this database was recently published (Vincent 2010), and specific field examples were highlighted to demonstrate that refrac treatments can improve production by numerous mechanisms including: –Enlarged fracture geometry –Improved pay coverage through increased fracture height in vertical wells –Greater lateral coverage in horizontal wells or initiation of more transverse fractures –Increased fracture conductivity compared to initial frac –Restoration of fracture conductivity loss due to embedment, cyclic stress, proppant degradation, gel damage, scale, asphaltene precipitation, fines plugging, etc. –Increased conductivity in previously unpropped or inadequately propped portions of fracture –Use of more suitable fracturing fluids –Reorientation due to stress field alterations, leading to contact of "new" rock This paper will briefly review restimulation attempts in six Canadian reservoirs of interest to the local audience, and will then present a more detailed review of restimulation of horizontal wells in the unconventional Bakken oil formation. In addition to a summary of published results, this paper will introduce a significant amount of previously unpublished data regarding refrac treatments of horizontal laterals completed in the Middle Bakken. This study will identify several additional concerns and opportunities with restimulating horizontal wellbores that were not previously identified in literature reviews. This organized summary of field results and references will provide significant value to readers evaluating or designing restimulation treatments.
Abstract A database has been compiled and analyzed, summarizing more than 100 field studies in which restimulation treatments (hydraulic refracs) have been performed, along with the production results. Field results demonstrate that refrac success can be attributed to many mechanisms, including: –Enlarged fracture geometry, enhancing reservoir contact –Improved pay coverage through increased fracture height in vertical wells –More thorough lateral coverage in horizontal wells or initiation of more transverse fractures –Increased fracture conductivity compared to initial frac –Restoration of fracture conductivity lost due to embedment, cyclic stress, proppant degradation, gel damage, scale, asphaltene precipitation, fines plugging, etc. –Increased conductivity in previously unpropped or inadequately propped portions of fracture –Improved production profile in well; preferentially stimulating lower permeability intervals [reservoir management] –Use of more suitable fracturing fluids –Re-energizing or re-inflating natural fissures –Reorientation due to stress field alterations, leading to contact of "new" rock Although less frequently published, unsuccessful restimulation treatments are also common. Documented concerns illustrated in this paper include: –Low pressured, depleted wells (especially gas wells) posing challenges with recovery of fracturing fluids –Low pressured or fault-isolated wells with limited reserves –Wells in which diagnostics indicate effective initial fractures and drainage to reservoir boundaries –Wells with undesirable existing perforations, or uncertain mechanical integrity of tubing, casing, or cement This paper will explore the common problems that lead to unsatisfactory stimulation, or initial treatments that fail over time. Guidelines for evaluating refrac candidates and improving initial treatments will be reviewed. The paper summarizes restimulation attempts in oil and gas wells in sandstone, carbonate, shale and coal formations. This organized summary of field results and references will provide significant value to readers evaluating or designing restimulation treatments.