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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.
Brinkley, Kourtney (Devon Energy) | Ingle, Trevor (Devon Energy) | Haffener, Jackson (Devon Energy) | Chapman, Philip (Devon Energy) | Baker, Scott (Devon Energy) | Hart, Eric (Devon Energy) | Haustveit, Kyle (Devon Energy) | Roberts, Jon (Devon Energy)
Abstract This case study details the use of Sealed Wellbore Pressure Monitoring (SWPM) to improve the characterization of fracture geometry and propagation during stimulation of inter-connected stacked pay in the South Texas Eagle Ford Shale. The SWPM workflow utilizes surface pressure gauges to detect hydraulically induced fracture arrivals athorizontal monitor locations adjacent to the stimulated wellbore (Haustveit et al. 2020). A stacked and staggered development in Dewitt County provided the opportunity to jointly evaluateprimary completion and recompletion efforts spanning three reservoir target intervals. Fivemonitor wells at varying distances across the unit were employed for SWPM during the stimulation of four wells. An operational overview, analysis of techniques, correlation with seismic attributes, image log interpretations, and fracture model calibration are provided. Outputs from this workflow allow for a refined analysis ofthe overall completion strategy. The high-density, five well monitor array recorded a total of 160 fracture arrivals at varying vertical and lateral distances, with far-field fracture arrivalsprovidingsignificant insight into propagation rates and geometry. Apronounced trend occurred in both arrival frequency and volumes pumped as monitor locations increased in distance from the treatment well. Specific to target zone isolation, it was identified that traversing vertically in section through a high stress interval yielded a 30% reduction inarrival frequency. An indirect relationship between horizontal distance and arrival frequency was also observed when monitoring from the same interval. A decrease in fracture arrivals from 70% down to 8% was realized as offset distance increased from 120 to 1,700 ft. The results from this study have proven to be instrumental in guiding interdisciplinary discussion. Assessing fracture geometry and propagation during stimulation, particularly in the co-development of a stacked pay reservoir, is paramount to the determination of proper completion volume, perforation design, and well spacing. Leveraging the observations of SWPM ultimately provides greater confidence in field development strategy and economic optimization.
Abstract Well spacing and stimulation design are amongst the highest impact design variables which can dictate the economics of an unconventional development. The objective of this paper is to showcase a numerical simulation workflow, with emphasis on the hydraulic fracture simulation methodology, which optimizes well spacing and completion design simultaneously. The workflow is deployed using Cloud Computing functionality, a step-change over past simulation methods. Workflow showcased in this paper covers the whole cycle of 1) petrophysical and geomechanical modeling, 2) hydraulic fracture simulations and 3) reservoir simulation modeling, followed by 4) design optimization using advanced non-linear methods. The focus of this paper is to discuss the hydraulic fracture simulation methods which are an integral part of this workflow. The workflow is deployed on a dataset from a multi-well pad completed in late 2018 targeting two landing zones in the Vaca Muerta shale play. On calibrated petrophysical and geomechanical model, hydraulic fracture simulations are conducted to map the stimulated rock around the wellbores. Finely gridded base model is utilized to capture the property variation between layers to estimate fracture height. The 3d discrete fracture network (DFN) built for the acreage is utilized to pick the natural fracture characteristics of the layers intersected by the wellbores. The methodology highlights advances over the past modeling approaches by including the variation of discrete fracture network between layers. The hydraulic fracture model in conjunction with reservoir flow simulation is used for history matching the production data. On the history matched model, a design of experiments (DOE) simulation study is conducted to quantify the impact of a wide range of well spacing and stimulation design variables. These simulations are facilitated by the recent deployments of cloud computing. Cloud computing allows parallel running of hundreds of hydraulic fracturing and reservoir simulations, thereby allowing testing of many combinations of stimulation deigns and well spacing and reducing the effective run time from 3 months on a local machine to 1 week on the cloud. Output from the parallel simulations are fitted with a proxy model to finally select the well spacing and stimulation design variables that offer the minimum unit development cost i.e. capital cost-$ per EUR-bbl. The workflow illustrates that stimulation design and well spacing are interlinked to each other and need to be optimized simultaneously to maximize the economics of an unconventional asset. Using the workflow, the team identified development designs which increase EUR of a development area by 50-100% and reduce the unit development cost ($/bbl-EUR) by 10-30%.
Shahri, Mojtaba (Apache Corp.) | Tucker, Andrew (Apache Corp.) | Rice, Craig (Apache Corp.) | Lathrop, Zach (Apache Corp.) | Ratcliff, Dave (ResFrac) | McClure, Mark (ResFrac) | Fowler, Garrett (ResFrac)
Abstract In the last decade, we have observed major advancements in different modeling techniques for hydraulic fracturing propagation. Direct monitoring techniques such as fibre-optics can be used to calibrate these models and significantly enhance our understanding of subsurface processes. In this study, we present field monitoring observations indicating consistently oriented, planar fractures in an offset-well at different landing zones in the Permian basin. Frac hit counts, location, and timing statistics can be compiled from the data using offset wells at different distances and depths. The statistics can be used to calibrate a detailed three-dimensional fully coupled hydraulic fracturing and reservoir simulator. In addition to these high-level observations, detailed fibre signatures such as strain response during frac arrival to the monitoring well, post shut-in frac propagation and frac speed degradation with length can be modeled using the simulator for further calibration purposes. Application to frac modeling calibration is presented through different case studies. The simulator was used to directly generate the ‘waterfall plot’ output from the fibre-optic under a variety of scenarios. The history match to the large, detailed synthetic fibre dataset provided exceptional model calibration, enabling a detailed description of the fracture geometry, and a high-confidence estimation of key model parameters. The detailed synthetic fibre data generated by the simulator were remarkably consistent with the actual data. This indicates a good consistency with classical analytical fracture mechanics predictions and further confirm the interpretation of planar fracture propagation. This study shows how careful integration of offset-well fibre-optic measurements can provide detailed characterization of fracture geometry, growth rate, and physics. The result is a detailed picture of hydraulic fracture propagation in the Midland Basin. The comparison of the waterfall plot simulations and data indicate that hydraulic fractures can, in fact, be very well modeled as nearly-linear cracks (the ‘planar fracture modeling’ approach).
Abstract In this paper, the authors examine the impacts of natural fractures on the distribution of slurry in a well with a permanent fiber installation and drill bit geomechanics data. Additionally, they propose a framework for further investigation of natural fractures on slurry distribution. As part of the Marcellus Shale Energy and Environmental Laboratory (MSEEL), the operator monitored the drilling of a horizontal Marcellus Formation well with drill bit geomechanics, and subsequent stimulation phase with a DAS/DTS permanent fiber installation. Prior to the completion, the authors used an analytical model to examine the theoretical distribution of slurry between perforation clusters from a geomechanics framework. A perforation placement scheme was then developed to minimize the stress difference between clusters and to segment stages by the intensity of natural fractures while conforming to standard operating procedures for the operator's other completions. The operator initially began completing the well with the geomechanics-informed perforation placement plan while monitoring the treatment distribution with DAS/DTS in real time. The operator observed several anomalous stages with treating pressures high enough to cause operational concerns. The operator, fiber provider, and drill bit geomechanics provider reviewed the anomalous stages’ treatment data, DAS/DTS data, and geomechanics data and developed a working hypothesis. They believed that perforation clusters placed in naturally fractured rock were preferentially taking the treatment slurry. This phenomenon appeared to cause other clusters within the stage to sand-off or become dormant prematurely, resulting in elevated friction pressure. This working hypothesis was used to predict upcoming stages within the well that would be difficult to treat. Another perforation placement plan was developed for the second half of the well to avoid perforating natural fractures as an attempt to mitigate operational issues due to natural fracture dominated distribution. Over the past several years, the industry's growing understanding of geomechanical and well construction variability has created new limited-entry design considerations to optimize completion economics and reduce the variability in cluster slurry volumes. Completion engineers working in naturally fractured fields, such as the Marcellus, should consider the impact the natural fractures have on slurry distribution when optimizing their limited-entry designs and stage plan.
Elsayed, Mahmoud (King Fahd University of Petroleum and Minerals) | El-Husseiny, Ammar (King Fahd University of Petroleum and Minerals (Corresponding author) | Kwak, Hyung (email: email@example.com)) | Hussaini, Syed Rizwanullah (Saudi Aramco) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals)
Summary In-situ evaluation of fracture tortuosity (i.e., pore geometry complexity and roughness) and preferential orientation is crucial for fluid flow simulation and production forecast in subsurface water and hydrocarbon reservoirs. This is particularly significant for naturally fractured reservoirs or postacid fracturing because of the strong permeability anisotropy. However, such downhole in-situ characterization remains a challenge. This study presents a new method for evaluating fracture tortuosity and preferential orientation based on the pulsed field gradient (PFG) nuclear magnetic resonance (NMR) technique. Such an approach provides diffusion tortuosity, τd, defined as the ratio of bulk fluid diffusion coefficient to the restricted diffusion coefficient in the porous media. In the PFG NMR technique, the magnetic field gradient can be applied in different directions, and therefore anisotropy in diffusion coefficient and τd can be evaluated. Three 3D printed samples, characterized by well controlled variable fracture tortuosity, one fractured sandstone, and three acidized carbonate samples with wormhole were used in this study. PFG NMR measurements were performed using both 2- and 12-MHz NMR instruments to obtain τd in the three different principal directions. The results obtained from the NMR measurements were compared with fracture tortuosity and preferential orientation determined from the microcomputed tomography (micro-CT) images of the samples. The results showed that τd increases as the fracture tortuosity and pore geometry complexity increases, showing good agreement with the image-based geometric tortuosity values. Moreover, the lowest τd values were found to coincide with the preferential direction of fracture surfaces and wormhole body for a given sample, whereas the maximum τd values correspond to the nonconnected pathway directions. These results suggest that the implantation of directional restricted diffusion measurements on the NMR well logging tools would offer a possibility of probing tortuosity and determining preferential fluid flow direction via direct downhole measurements.
Abstract The objective of this study was to perform an integrated analysis to gain insight for optimizing fracturing treatment and gas recovery from Marcellus shale. The analysis involved all the available data from a Marcellus Shale horizontal well which included vertical and lateral well logs, hydraulic fracture treatment design, microseismic, production logging, and production data. A commercial fracturing software was utilized to predict the hydraulic fracture properties based on the available vertical and lateral well logs data, diagnostic fracture injection test (DFIT), fracture stimulation treatment data, and microseismic recordings during the fracturing treatment. The predicted hydraulic fracture properties were then used in a reservoir simulation model developed based on the Marcellus Shale properties to predict the production performance. In this study, the rock mechanical properties were estimated from the well log data. The minimum horizontal stress, instantaneous shut-in pressure (ISIP), process zone stress (PZS), and leak-off mechanism were determined from DFIT analysis. The stress conditions were then adjusted based on the results of microseismic interpretations. Subsequently, the results of the analyses were used in the fracturing software to predict the hydraulic fracture properties. Marcellus Shale properties and the predicted hydraulic fracture properties were used to develop a reservoir simulation model. Porosity, permeability, and the adsorption characteristics were estimated from the core plugs measurements and the well log data. The image logs were utilized to estimate the distribution of natural fractures (fissures). The relation between the formation permeability and the fracture conductivity and the net stress (geomechanical factors) were obtained from the core plugs measurements and published data. The predicted production performance was then compared against production history. The analysis of core data, image logs, and DFIT confirmed the presence of natural fractures in the reservoir. The formation properties and in-situ stress conditions were found to influence the hydraulic fracturing geometry. The hydraulic fracture properties are also impacted by stress shadowing and the net stress changes. The production logging tool results could not be directly related to the hydraulic fracture properties or natural fracture distribution. The inclusion of the stress shadowing, microseismic interpretations, and geomechanical factors provided a close agreement between the predicted production performance and the actual production performance of the well under study.
Summary The popular cohesive zone model (CZM) that only features decreasing cohesive traction along with crack separation might not adequately represent the fracturing behavior in organic-rich shale because of increased ductility. This paper proposes a novel CZM that can realize various traction/separation laws (TSLs) by a unified formulation to better represent the increased ductility of organic-rich shale. The implications of increased ductility in different forms on hydraulic fracturing were studied using the newly designed progressive parametric study. First, the shape of the TSL affects the hydraulic fracturing given the same cohesive crack energy and tensile strength, which further indicates the necessity of the newly proposed TSL. Second, the initial tensile strength, controlling when the cohesive crack starts propagating, has the greatest effect on the hydraulic fracturing among all TSL shape parameters. The effects of TSL parameters become less significant as the fracturing-fluid viscosity increases. Finally, Young's modulus among four common poroelastic parameters most significantly affects the brittleness of rock formation and hydraulic-fracture lengths. The increase in cohesive energy accompanied by the decrease of Young's modulus can greatly reduce the hydraulic-fracture length under the same injection volume. Introduction Shale as a common sedimentary rock is attracting more attention since the boom of exploration and production in unconventional oil and gas reservoirs with hydraulic fracturing. However, success of hydraulic fracturing in the important organic-rich shale is limited. The improvement of hydraulic-fracturing practices in these organic-rich shales awaits a better understanding of the effects of the increased ductility caused by ample organic matter. The core objective of this paper is to study the increased ductility of organic-rich shale and its effects on hydraulic fracturing by implementing a modified cohesive crack model into an appropriate numerical framework to handle fracture propagation. An in-house XFEM framework was developed to address the stronger ductility of organic-rich shale by use of the CZM.
Summary The primary objective of this study is to develop fast analytical and/or semianalytical (A/SA) solutions for the problem of liquid flow/production and pressure interference in multifractured systems between parallel horizontal wells in ultralow-permeability reservoirs. We propose a new A/SA method that reduces the 3D flow equation into either a simple algebraic equation or an ordinary differential equation (ODE) in a multitransformed space, the inversion of which yields solutions at any point in space and time. In the proposed transformational decomposition method (TDM), a general, fully linearized form of the 3D partial-differential equation (PDE) describing low-compressibility liquid flow through porous and fractured media is subjected first to Laplace transforms (LTs) to eliminate time, and then to successive finite cosine transforms (FCTs) that eliminate either all three dimensions, yielding a simple algebraic equation, or two dimensions, yielding an ODE in space only. Inversion of the solutions of the multitransformed space equations provides solutions that are analytical in space and semianalytical in time. The TDM completely eliminates the need for time and space discretization, thus dramatically reducing the input-data requirements and long execution times of numerical simulations. The Fortran 95 code for the TDM solutions requires limited inputs and is easy to use. Because of the linearity requirements of the Laplace transformation of the underlying PDE, the TDM is only rigorously applicable at greater than the bubblepoint pressure. Using 3D stencils (the minimum repeatable elements in the horizontal well and hydraulically fractured system) as the basis of our study, solutions over extended production times were obtained for a range of isotropic and anisotropic matrix and fracture properties, constant and time-variable production regimes (rates or bottomhole pressures), combinations of stimulated reservoir volume (SRV) and non-SRV subdomains, variable hydraulic-fracture (HF) dimensions, and inner and boundary (toe and heel) stencils. The results were compared with analytical solutions (available for simple problems and domain geometries), as well as with numerical solutions from a widely used, fully implicit 3D simulator that involves very fine discretization of a 3D domain comprising more than 356,000 elements. The TDM solutions were shown to be in excellent agreement with the reference analytical and/or numerical solutions, while requiring a fraction of the memory and execution times of the latter because of the elimination of the need for time and space discretization. The TDM is an entirely new approach for the analysis of low-compressibility liquid flow and pressure interference in hydraulically fractured ultralow-permeability reservoirs. The TDM solutions have the potential to provide a reliable and fast tool to identify the dominant mechanisms and factors controlling the system behavior and can act as the basis for a rapid initial parameter identification in a history-matching process for possible further refinement using full numerical modeling at less than the bubblepoint pressure.
Summary Pulse hydraulic fracturing technology can greatly improve the effect of fracture propagation in rock and form complex fracture networks in reservoirs. The interaction mechanism between hydraulic fractures and pre-existing fractures under pulse hydraulic pressure is unclear. The induced laws of pre-existing fractures on the propagation direction of hydraulic fractures under different pulse frequencies and pulse hydraulic pressures are revealed in this work. We have carried out traditional hydraulic fracturing (THF) tests and pulse hydraulic fracturing tests with rock-like specimens. We compared the interaction between hydraulic fractures and pre-existing fractures in the two hydraulic fracturing tests. Acoustic emission (AE) characteristics of the interaction between hydraulic fractures and pre-existing fractures during pulse hydraulic fracturing are analyzed. The results show that pre-existing fractures in the rock-like specimen can induce the direction of propagation of hydraulic fractures. The influence of pre-existing fracture tips on hydraulic fracture propagation is greater with low pulse frequencies than with traditional hydraulic pressures and high pulse frequencies. When the pulse frequency is 1 Hz, hydraulic fractures are easily induced by pre-existing fracture tips. With increasing pulse frequency, the hydraulic fracture propagation direction gradually moves away from the pre-existing fracture tips and extends perpendicularly to the direction of the minimum principal stress. Under pulse hydraulic loading, more hydraulic fractures are generated around the wellbore than under THF and extend to the pre-existing fracture, and more hydraulic fractures around the wellbore are created with low-frequency pulse loading than with high-frequency pulse loading. Compared with traditional hydraulic pressures, hydraulic fracture propagation with low pulse frequencies (1 and 3 Hz) is more complex than hydraulic fracture propagation with traditional hydraulic pressures and high pulse frequencies (5 Hz). Under high pulse hydraulic pressure and pulse frequency, hydraulic fractures easily extend along the direction perpendicular to the direction of the minimum principal stress like propagation under traditional hydraulic pressure. The study of the interaction mechanism between hydraulic fractures and natural fractures under pulsating hydraulic pressure can provide a method for the formation of fracture network systems in large-scale fracturing and may improve the fracturing efficiency.