Not enough data to create a plot.
Try a different view from the menu above.
Dontsov, Egor
Practical Optimization of Perforation Design with a General Correlation for Proppant and Slurry Transport from the Wellbore
Dontsov, Egor (ResFrac Corporation, Palo Alto, CA, USA) | Ponners, Christopher (ResFrac Corporation, Palo Alto, CA, USA) | Torbert, Kevin (Cornerstone Engineering, Inc., Bakersfield, CA, USA) | McClure, Mark (ResFrac Corporation, Palo Alto, CA, USA)
Abstract During plug and perf completion, perforation pressure drop is used to encourage a uniform distribution of flow between clusters by overcoming stress shadowing, stress variability, and nonuniform breakdown pressure. However, proppant inertia, gravitational settling, and perforation erosion contribute to nonuniformity, even with an aggressive limited-entry design. In prior work, Dontsov (2023) developed a correlation for predicting proppant outflow from the wellbore as a function of slurry velocity, perforation phasing, and other parameters. In the present study, the Dontsov (2023) correlation is integrated into a wellbore dynamics simulator capturing key physical processes that control slurry and proppant outflow from the wellbore, such as erosion, stress shadowing, and near-wellbore tortuosity. The simulator is fast running and incorporated into a tool for Monte Carlo uncertainty quantification and design optimization. First, we run a series of sensitivity analysis simulations to evaluate the effect of key model inputs. The simulations demonstrate processes that can cause heel bias, toe bias, or heel/toe bias in the erosion distribution. Next, we apply the tool to analyze field datasets from the Eagle Ford and the Montney. Downhole imaging of erosion data enables model calibration. Calibration is necessary because differences in casing, cement, and formation properties cause differences in erosion behavior and flow distribution. Parameters controlling the magnitude of erosion and stress shadow are modified to match the trends observed from the downhole imaging. After calibration is performed, the model is applied to maximize the uniformity of proppant placement by optimizing perforation phasing, diameter, count, and cluster spacing.
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.55)
- Geophysics > Borehole Geophysics (0.55)
- 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)
- (26 more...)
Abstract Limited entry technique is often employed to achieve uniform flow distribution between perforation clusters during hydraulic fracturing treatment. However, the proppant distribution between clusters will not necessarily be uniform, even if the slurry distribution is uniform. As the average slurry velocity reduces from one cluster to another, this leads to proppant settling and higher particle concentration in the lower portion of the wellbore. Also, the slurry makes a sharp turn to enter a perforation and the higher proppant density causes some particles to miss the perforation. These two physical effects are primarily responsible for the non-uniform proppant distribution between the clusters. In view of these observations, the purpose of this study is to investigate the degree of uniformity of proppant placement based on a recently developed proppant-wellbore dynamics model. A field scale case consisting of 13 perforation clusters is considered. Three perforation designs are compared: the original design with 3 perforations phased 120ยฐ, a case in which the orientation of each individual perforation shot is optimized, and a case in which phasing is optimized with the constraint that all perforations have the same orientation. The goal of the optimization procedure is to achieve more uniform proppant distribution. Results are presented in the context of uncertainty of perforation diameter and phasing. Finally, the effect of stress shadow from the previous stage on the variability of proppant placement is investigated. It is found that the optimal perforation phasing leads to a significantly more uniform proppant distribution between perforations and that the effect of stress shadow does not significantly alter the results as soon as sufficiently strong perforation friction is used. Uncertainty of perforation phasing and diameter introduces a certain level of variation to the results, but this level is noticeably smaller compared to the improvement achieved by using the optimal perforation orientation.
- North America > United States > Texas (0.49)
- North America > United States > Colorado (0.29)
Abstract We developed a propagation algorithm that enables accurate calculation of hydraulic fracture geometry, even in the presence of thin layers and with a relatively coarse crack mesh. Conventionally, hydraulic fracture simulators either add one element at a time (less accurate) or require constant remeshing (computationally expensive). Our new algorithm benefits from the simplicity of adding one element at a time, but does not compromise the accuracy. This is because the algorithm continuously tracks the position of the crack tip within each tip element. In addition, the continuous front tracking allows for the algorithm to account for varying rock properties within the element and to accurately simulate propagation across arbitrarily thin layers. The algorithm has been implemented in a commercial combined hydraulic fracturing and reservoir simulator. First, some mathematical foundations of the algorithm are outlined. Then, we perform basic validation simulations, showing that the algorithm can accurately solve standard benchmark solutions in the toughness and viscosity dominated regimes. Next, we simulate propagation of a single crack in a layered media with highly variable properties (e.g. stress or toughness) between layers. We perform sensitivity analysis to show that the algorithm retains accuracy, even if the mesh is coarsened considerably. The mesh coarsening leads to dramatically faster numerical simulations, relative to the corresponding fine mesh solutions. Finally, we apply the algorithm in a field-scale simulation of an actual pad-scale dataset. We show that the algorithm is capable of accurately reproducing the fracture geometry and, at the same time, retains practical computational times.
Ultra-Fast, Pad-Scale Modeling of Hydraulic Fracturing and Depletion for Optimizing Development Plans in the Eagle Ford Play
Dontsov, Egor (ResFrac Corporation) | Suarez-Rivera, Roberto (W. D. Von Gonten Laboratories) | Panse, Rohit (W. D. Von Gonten Laboratories) | Quinn, Christopher (W. D. Von Gonten Laboratories) | LaReau, Heather (BP America Production Company, BPx Energy Inc.) | Suter, Kirke (BP America Production Company, BPx Energy Inc.) | Hines, Chris (BP America Production Company, BPx Energy Inc.) | Montgomery, Ryan (BP America Production Company, BPx Energy Inc.) | Koontz, Kyle (BP America Production Company, BPx Energy Inc.)
Abstract As the number of wells drilled in regions with existing producing wells increases, understanding the detrimental impact of these by the depleted zone around parent wells becomes more urgent and important. This understanding should include being able to predict the extent and heterogeneity of the depleted region near the pre-existing wells, the resulting altered stress field, and the effect of this on newly created fractures from adjacent child wells. In this paper we present a workflow that addresses the above concern in the Eagle Ford shale play, using numerical simulations of fracturing and reservoir flow, to define the effect of the depletion zone on child wells and match their field production data. We utilize an ultra-fast hydraulic fracture and depletion model to conduct several hundred numerical simulations, with varying values of permeability and surface area, seeking for cases that match the field production data. Multiple solutions exist that match the field data equally well, and we used additional field production data of parent-child well-interaction, to select the most plausible model. Results show that the depletion zone is strongly non-uniform and that large reservoir regions remain undepleted. We observe two important effects of the depleted zone on fractures from child wells drilled adjacent to the parents. Some fractures propagate towards low pressure zones and do not contribute to production. Others are repelled by the higher stress region that develops around the depletion zone, propagate into undepleted rock, and have production rates commensurate to that from other child wells drilled away from depleted region. The observations are validated by the field data. Results are being used to optimize well placement and well spacing for subsequent field operations, with the objective to increase the effectiveness of the child wells.
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.48)
- North America > United States > Oklahoma > Anadarko Basin > Cana Woodford Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.97)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.97)
- (10 more...)
Multi-Well Pressure History Matching in Delaware Play Helps Optimizing Fracturing for Subsequent Pads
Suarez-Rivera, Roberto (W. D. Von Gonten Laboratories) | Panse, Rohit (W. D. Von Gonten Laboratories) | Sovizi, Javad (Baker Hughes) | Dontsov, Egor (ResFrac Corporation) | LaReau, Heather (BP America Production Company, BPx Energy Inc.) | Suter, Kirke (BP America Production Company, BPx Energy Inc.) | Blose, Matthew (BP America Production Company, BPx Energy Inc.) | Hailu, Thomas (BP America Production Company, BPx Energy Inc.) | Koontz, Kyle (BP America Production Company, BPx Energy Inc.)
Abstract Predicting fracture behavior is important for well placement design and for optimizing multi-well development production. This requires the use of fracturing models that are calibrated to represent field measurements. However, because hydraulic fracture models include complex physics and uncertainties and have many variables defining these, the problem of calibrating modeling results with field responses is ill-posed. There are more model variables than can be changed than field observations to constrain these. It is always possible to find a calibrated model that reproduces the field data. However, the model is not unique and multiple matching solutions exist. The objective and scope of this work is to define a workflow for constraining these solutions and obtaining a more representative model for forecasting and optimization. We used field data from a multi-pad project in the Delaware play, with actual pump schedules, frac sequence, and time delays as used in the field, for all stages and all wells. We constructed a hydraulic fracturing model using high-confidence rock properties data and calibrated the model to field stimulation treatment data varying the two model variables with highest uncertainty: tectonic strain and average leak-off coefficient, while keeping all other model variables fixed. By reducing the number of adjusting model variables for calibration, we significantly lower the potential for over-fitting. Using an ultra-fast hydraulic fracturing simulator, we solved a global optimization problem to minimize the mismatch between the ISIPs and treatment pressures measured in the field and simulated by the model, for all the stages and all wells. This workflow helps us match the dominant ISIP trends in the field data and delivers higher confidence predictions in the regional stress. However, the uncertainty in the fracture geometry is still large. We also compared these results with traditional workflows that rely on selecting representative stages for calibration to field data. Results show that our workflow defines a better global optimum that best represents the behavior of all stages on all wells, and allows us to provide higher-confidence predictions of fracturing results for subsequent pads. We then used this higher confidence model to conduct sensitivity analysis for improving the well placement in subsequent pads and compared the results of the model predictions with the actual pad results.
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- Asia > China > Sichuan > Sichuan Basin (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin > Wolfcamp A Formation (0.89)
- (2 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 > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
Summary Multiple hydraulic fractures are often generated simultaneously from a wellbore to increase efficiency of reservoir stimulation. Numerical modeling of such a system of fractures is computationally costly, especially if the goal is to simulate numerous stages, each containing multiple fractures, on different wells, which is the current trend in the petroleum industry. To address the challenge, this study defines a method and a workflow to represent the simultaneous propagation of multiple fractures with a reduced number of equivalent fractures that accurately describes the overall fracture geometry, the created surface area, the propped surface area, the fluid leakoff, and the resulting induced stresses, as resulting from the original configuration. A hybrid approach is used, in which a combination of physical modeling and data science is involved. We first develop a database of numerical solutions using a fully coupled hydraulic fracturing simulator. The equivalent fracture representation is quantified for each set of problem parameters presented in the database. Then, the results of the database solutions are used to tackle more general cases with field pumping schedules and rock properties. Several numerical examples are presented to validate and illustrate the developed concept.
- North America > United States > Texas (1.00)
- Europe (0.67)
- 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 > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- (2 more...)
Laboratory Investigation of Leak-Off During Hydraulic Fracturing into Bedding Interfaces
Abell, Bradley (W.D. Von Gonten Laboratories) | Xing, Pengju (W.D. Von Gonten Laboratories) | Bunger, Andrew (University of Pittsburgh) | Dontsov, Egor (W.D. Von Gonten Laboratories) | Suarez-Rivera, Roberto (W.D. Von Gonten Laboratories)
Abstract Bedding interfaces occur in laminated rock formations at the boundary between different rock types. These interfaces can contribute to fluid leakoff during hydraulic fracturing and thus affect fracture geometry, propped surface area, and the overall hydrocarbon productivity of wells, yet they are only recently being studied. The objectives of this investigation are to empirically measure leakoff into fabricated bedding interfaces and investigate the change in leakoff introduced by fracturing fluid additives, and consequently investigate potential increases in propped surface area and productivity by using fluid additives. A laboratory scale flow cell was developed that accurately simulates hydraulic fractures by allowing for: (i) interfaces that are independent from each other and have adjustable thicknesses that can be changed depending on the proppant being used, and (ii) fracture size and system specifications that produce the same fluid velocities as during field hydraulic fracturing, and (iii) the fluid leaked through the interfaces is continuously collected and weighted, which allows the total leakoff rate to be measured. In addition, the flow cell allows direct visualization of hydraulic stimulations as the entire system is made of visually transparent acrylic blocks. Flow experiments, with clean fluids of different viscosities, were conducted and verified that the measurements agree with theoretical results from lubrication theory. Results of experiments with proppants verified that proppant enters the interfaces for the case when proppant diameter is several times smaller than the interface thickness. And, experiments with cellulose fibers demonstrated that the fibers bridged and accumulated in the regions near interfaces while the main fluid flow inside the fracture developed a tortuous path around these fibers, reducing the leakoff by changing the flow pattern inside the fracture. Understanding the leakoff potential of bed parallel interfaces will allow better evaluation of fracture geometry, fluid flow and proppant transport in the fracture, the resulting propped surface area, and the potential for frack hits during hydraulic fracturing.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.68)
Abstract In this work we address the importance of numerical modeling for conducting sensitivity analysis of stacked, multi-stage, multi-well pad completions, as well as multi-pad completions, to optimize well placement and maximize well productivity. Designing stacked, multi-stage, multi-well, completions requires an evaluation of the induced stresses between interacting fractures and the effect that these stresses introduce into the growth of subsequent fractures. We tested the importance of the induced stressess by using two hydraulic fracture simulators that evaluate fracture geometry, propped surface area, and the local and far-field induced stresses at the end of the fracture treatment. Using a real case study in the Midland basin, we investigated the consequences of optimizing well placement to maximize well productivity using single-well simulations (i.e., assuming standalone wells), compared to conducting the same optimization using multi-well modeling (i.e., field zipper frac configuration). Results show that one cannot optimize the placement of stacked wells by treating them as standalone wells. We also investigated the effect of zipper fracture sequencing on the propped surface areas and well productivity. Results show that fracture sequencing affects the order of interaction between fractures and their associated induced stresses. In turn, this leads to changes in the fracture geometry and propped surface area, and thus influences the productivity of the entire pad or multi-pad system. The consequences of these changes are not easy to anticipate based on the knowledge of the individual well's behavior (either single stage modeling or multi-stage modeling). For the present case under investigation, after selecting the optimal wells placement, the propped surface area was practically insensitive to fracture sequencing. This, however, is not commonly the case. Furthermore, results showed a strong sensitivity to leakoff and the corresponding fracturing fluid efficiency. Unfortunately, this is not a parameter that can be controlled (except by using fluid loss additives and viscocifying agents). At the same time, this demonstrates the necessity of obtaining field leakoff measurements for accurate modeling.
- North America > United States > Texas > Permian Basin > Midland Basin > Wolfcamp A Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin > Dean Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- (6 more...)
Abstract The primary objective of this paper is to present a hydraulic fracturing simulator that can be used to investigate how spatial variation of properties and the presence of existing wells influence the optimal completion design and fracturing sequence for multi-well and multi-pad developments, or cube developments. Cube development optimization is challenging to model because of excessively time-consuming computational demands. We circumvented this problem by creating an ultrafast hydraulic fracturing simulator that models multi-stage fracturing within seconds, but still accounts for stress shadow interactions. Our simulator uses the same principles of fracture mechanics, rock anisotropy, fluid flow, and proppant transport prevalent as in existing simulators and agrees well with reference solutions, but does not rely on tuning parameters. To highlight the capabilities of our simulator, an example of cube development optimization is presented. Introduction Hydraulic fracturing is a technology to stimulate low permeability oil and gas reservoirs by injecting fluid with proppant to induce fractures that create a large surface area in contact with the reservoir (Economides and Nolte, 2000). At its inception, the technology was mostly used to generate a single bi-wing fracture in a vertical well. Responding to petroleum industry demand, the technology nowadays is used in massive unconventional field development that includes cube development, which we consider to be drilling multiple stacked horizontal wells that are then fractured in a given sequence. Cube development brings new challenges for modeling, notably the interactions among fractures from different stages (or wells) during both stimulation and production. Industry uses hydraulic fracture models to simulate and better understand processes that occur underground, and in turn optimizing productivity of wells. Early models were developed for single bi-wing fractures, such as KGD model (Khristianovic and Zheltov, 1955), PKN model (Perkins and Kern, 1961; Nordgren, 1972), or pseudo-3D model (Settari and Cleary, 1986). The development of computational resources shifted fracture models towards more computationally expensive fully planar fractures (Lee and Lee, 1990) and with an ability to capture lithology more accurately (Peirce and Siebrits, 2001). Industry's move toward unconventional resources and the need for cube development is again shifting the focus of fracture models. Industry needs fracture models that: propagate multiple fractures per stage simultaneously, propagate fractures in multiple stages, account for the stress shadow between fractures within the stage and among the stages and wells, include the effect of the depletion zone of the neighboring well(s), capture natural fractures and bedding interfaces, and incorporate small-scale variations of properties. The complexity of the problems has increased by orders of magnitude and so have the numerical simulators.
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.97)