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Pei, Yanli (University of Texas at Austin (Corresponding author) | Yu, Wei (email: firstname.lastname@example.org)) | Sepehrnoori, Kamy (University of Texas at Austin and Sim Tech LLC) | Gong, Yiwen (University of Texas at Austin) | Xie, Hongbing (Sim Tech LLC and Ohio State University) | Wu, Kan (Sim Tech LLC)
Summary The extensive depletion of the development target triggers the demand for infill drilling in the upside target of multilayer unconventional reservoirs. However, such an infill scheme in the field practice still heavily relies on empirical knowledge or pressure responses, and the geomechanics consequences have not been fully understood. Backed by the data set from the Permian Basin, in this work we present a novel integrated reservoir-geomechanics-fracture model to simulate the spatiotemporal stress evolution and locate the optimal development strategy in the upside target of the Bone Spring Formation. An embedded discrete fracture model (EDFM) is deployed in our fluid-flow simulation to characterize complex fractures, and the stress-dependent matrix permeability and fracture conductivity are included through the compaction/dilation option. After calibrating reservoir and fracture properties by history matching of an actual well in the development target (i.e., third Bone Spring), we run the finite element method (FEM)-based geomechanics simulation to model the 3D stress state evolution. Then a displacement discontinuity method (DDM) hydraulic fracture model is applied to simulate the multicluster fracture propagation under an updated heterogeneous stress field in the upside target (i.e., second Bone Spring). Numerical results indicate that stress field redistribution associated with parent-well production indeed vertically propagates to the upside target. The extent of stress reorientation at the infill location mainly depends on the parent-child horizontal offset, whereas the stress depletion is under the combined impact of horizontal offset, vertical offset, and infill time. A smaller parent-child horizontal offset aggravates the overlap of the stimulated reservoir volume (SRV), resulting in more substantial interwell interference and less desirable oil and gas production. The same trend is observed by varying the parent-child vertical offset. Moreover, the efficacy of an infill operation at an earlier time is less affected by parent-well depletion because of the less-disturbed stress state. The candidate infill-well locations at various infill timings are suggested based on the parent-well and child-well production cosimulation. Being able to incorporate both pressure and stress responses, the reservoir-geomechanics-fracture model delivers a more comprehensive understanding and a more integral solution of infill-well design in multilayer unconventional reservoirs. The conclusions provide practical guidelines for the subsequent development in the Permian Basin.
Buijs, Hernán (Wintershall Dea Headquarters) | Guerra, Clairet (Wintershall Dea Headquarters) | Sonwa, Roger (Wintershall Dea Headquarters) | Nami, Patrick (Wintershall Dea Headquarters) | Vecchia, Luciano (Wintershall Noordzee B.V) | Ishmuratov, Roman (Wintershall Noordzee B.V)
Hydraulic fracture design driven by multi-disciplinary collaboration can maximize the production potential of complex multi-frac horizontal wells. Integration of multiple information sources (i.e.: geological, dynamic and geomechanical data) allows to build representative models and have proven to improve modelling towards a realistic understanding of tight reservoir performance of several multi-fracced wells. 3D properties encompassing the reservoir geological heterogeneity, pore pressure, mechanical elasticity and state of stress were utilized to develop a strategy to fracture stimulate a horizontal wellbore in the North Sea Region. The study was instrumental to build fit-for-purpose hydraulic fracture designs by incorporating state of stress changes related to pore pressure depletion on different faulted compartments supported by a reservoir dynamic simulation. Such models provided meaningful value to optimize the well trajectory used to access the host rock, understand fracture height growth possibilities in different compartments and define the number/size of hydraulic fractures required for optimum production.
In acid fracturing treatments, the goal is to create enough fracture roughness through differential acid etching on fracture walls such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the closure stress. The viscous fingering phenomenon has been utilized in acid fracturing treatments to enhance the differential acid etching. For relatively homogeneous carbonate reservoirs, by injecting a low-viscosity acid into a high-viscosity pad fluid during acid fracturing, the acid tends to form viscous fingers and etch fracture surfaces non-uniformly. In order to accurately predict the acid- fracture conductivity, a detailed description of the rough acid-fracture surfaces is required. In this paper, we developed a 3D acid transport model to compute the geometry of acid fracture for acid fracturing treatments with viscous fingering. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. Our simulation results reproduced the acid viscous fingering phenomenon ob-served from experiments in the literature. During the process of acid viscous fingering, high-conductivity channels developed in the fingering regions. We performed parametric studies to investigate the effects of pad fluid viscosities and acid injection rates on acid fracture conductivity. We found that a higher viscosity pad fluid and a higher acid injection rate help acid to penetrate deeper in the fracture and result in a longer etched channel.
Clarkson, Christopher R. (University of Calgary) | Williams-Kovacs, Jesse (University of Calgary and Sproule Associated Limited) | Zhang, Zhenzihao (University of Calgary) | Yuan, Bin (University of Calgary) | Ghanizadeh, Amin (University of Calgary) | Hamdi, Hamidreza (University of Calgary) | Islam, Arshad (Baytex Energy Corp.)
Abstract Recently it has been demonstrated that rate-transient analysis (RTA) performed on flowback data frommulti-fractured horizontal wells (MFHWs) can provide timely estimates of hydraulic fracture properties. This information can be used to inform stimulation treatment design on upcoming wells as well as other important operational and development decisions. However, RTA of flowback data may be complicated by rapidly changing operating conditions, dynamic hydraulic fracture properties and multi-phase flow in the fractures, complex fracture geometry, and variable fracture and reservoir properties along the MFHW, among other factors. While some constraints on RTA model assumptions may be applied through a carefully-designed surveillance and testing program in the field (e.g. to constrain fracture geometry), still others require laboratory measurements. In this work, an integrated flowback RTA workflow, designed to reduce uncertainty in derived hydraulic fracture properties, is demonstrated using flowback data from MFHWs producing black oil from low-permeability reservoirs in the Montney and Duvernay formations. The workflow includes rigorous flow-regime identification used for RTA model selection, straight-line analysis (SLA) to provide initial estimates of hydraulic fracture properties, and model history matching of flowback data to refine hydraulic fracture property estimates. The model history matching is performed using a recently-introduced semi-analytical, dual-porosity, dynamic drainage area (DP-DDA) model that incorporates primary (propped) hydraulic fractures (PHF) as well as a dual-porosity enhanced fracture region (EFR) with an unpropped (secondary) fracture network. Inclusion of both the PHF and EFR components addresses the need to incorporate both propped and unpropped fractures and fracture complexity in the modeling. The DP-DDA model is constrained using estimates of propped fracture conductivity and unpropped fracture permeability (measured as a function of stress), and unpropped fracture compressibility values, obtained in the laboratory for Montney and Duvernay core samples. Use of these critical laboratory data serves to improve the confidencein the modeling results. The case studies provided herein demonstrate a rigorous workflow for obtaining more confident hydraulic fracture property estimates from flowback data through the application of RTA techniques constrained by both field and laboratory data.
Abstract Aimed at sharing the unconventional wisdom gained from a hydraulic fracturing monitoring case study in the Montney tight gas play, the work showcases the ability of 4D modeling of collective behaviors of microseismic events to chase the frac fluid and navigate the spatiotemporal fracture evolution. Moreover, microseismicity-derived deformation fields are integrated with volumetric estimates made by rate transient analysis to calibrate spatially-constrained SRV models. Through the case study, we give evidence of fracture containment, evaluate the role of natural fractures and the use of diverting agents, estimate cluster efficiencies, conduct analytical well spacing optimization, model productivity decline induced by communication frac-hits from offsets, and provide contributing fracture dimensions and numerical production forecasts. To support the interpretations, we supplement the work by the results of 3D physics-based analytical modeling and multi-phase numerical simulations, and the findings are then validated using two extensive datasets: production profiles acquired by fiber optic DAS, and reservoir fluid fingerprints extracted from mud logs. Besides describing the evolution of seismicity during the treatment, the applied integrated fracture mapping process gives a more reliable and unique SRV structure that streamlines forward modeling and simulations in unconventional reservoirs as well as contributes to solving inverse problems more mechanistically.
The Diyab Reservoir is an unconventional prospect in Abu Dhabi where previous exploration efforts revealed thin low permeability targets, unsuccessful stimulation, and poor well placement. This early field experience coupled with limited knowledge about local
The fit-for-purpose field data acquisition program, 3D hydraulic fracture simulation, and reservoir flow modeling helped establish a baseline understanding of the relationship between 3D reservoir characterization and proppant transport. Seismic data was interpreted to understand structural components and natural fracture characterization. Elastic inversions were performed on this data using petrophysical models to populate high-resolution 3D geological and geomechanical models calibrated against log derived rock properties and
Post frac analysis for three Diyab wells reveals that the ISIP varied significantly among the stages and the largest post frac pressure drops occurred at stages intersected by small-scale faults or natural fracture zones, particularly when they are well oriented for shear slip.
Results of high-resolution 3D simulation of frac stages on earlier wells showed proppant distribution closely followed reservoir property distributions of low stress and similar Young’s Modulus values. Wells were landed in specific target reservoirs, however, the simulation demonstrated that proppant from some stages was inadvertently placed in overlying reservoirs. The natural fractures play a significant role in stage efficiency indicating the need to utilize non-geometric completion design. Simulating the role of natural fractures to create reservoir access indicated significant differences in propped height and length within naturally fractured stages. Dual permeability pre-frac reservoir modeling based on frac simulation results predicted cumulative gas rates for the new wells.
Given the state of the oil & gas industry today, i.e., low hydrocarbon prices and a global health crisis still in high gear, making good business decisions is more crucial than ever. Deciding which wells to keep open for production, which wells to shut-in, which wells to re-stimulate for immediate production, and which new wells to drill, if any, may directly impact a business' financial survival. This is true for both conventional and unconventional assets, but of significantly more concern to the unconventional asset investor, because incremental production is already capital-intensive at the best of times. Over the last decade, unconventional resources have become a significant source of the total production output in various parts of the world, and the primary stimulation treatment used is hydraulic fracturing. This technique sections a wellbore into multiple stages into which highly pressurized fluid is pumped at various fracture initiation locations. Historically, the number of stages and the number of clusters per stage, has primarily been based on total lateral length, previous experience in the same or similar fields, and on investment considerations, with a strong tendency towards decreasing stage and fracture spacing (i.e., increasing stage and fracture count). Field experience showing non-productive and full-physics simulations suggest room for improvement and indicate that there must be an optimal stimulation treatment that maximizes profit. Beyond this point, adding another stage in the treatment becomes more expensive than what can be recuperated by incrementally increased production. Thus, in the current work, the problem is posed as a classic constrained optimization problem and solved using Monte Carlo methods. Results show that in general, profitability of the production revenue is very sensitive to the reservoir recovery factor, porosity, drainage volume for the lease window, and, ultimately, the market price. Introduction Unconventional wells are challenging in many ways, and significant capital investment combined with relatively short production periods makes exploitation of these types of reservoirs a balancing act between costs and profit. Wells can run in the millions when drilling and completion costs are accounted for, with completion costs accounting for more than half of the capital requirement (EIA 2016). Fortunately, the completion details are one of the few inputs that can be adjusted in the field, which allows for fine-tuning to local conditions. In this work, we employ hydraulic fracturing as the stimulation technique, and note that it is the most common type of completion technique currently in use. During hydraulic fracturing, fluid is injected into a wellbore at high pressure to create cracks in the sub-surface in the neighborhood of the wellbore, through which natural gas and oil flow more freely than through the low-permeability formations typical of unconventional reservoirs. The pressurized fluid typically carries propping material such as sand, which is intended to hold open fractures after fracturing pressure is relieved and shut-in begins. The origins of hydraulic fracturing date back to early experiments in the 1940s at the Hugoton gas field in Grant County of southwestern Kansas by Stanolind (Charlez 1997; Montgomery et al. 2010), and one of the first commercially successful applications of the new technology in the 1950s. As of 2012, about 2.5 million "frac jobs" had been performed worldwide on oil and gas wells; over one million of those within the U.S. (King 2012). In years past, such stimulation treatment was generally necessary to achieve profitable flow rates in shale gas, tight gas, tight oil, and coal seam gas wells (Charlez 1997), but in today's market environment, using the optimal stimulation treatment is all but economic requirement for economic survival.
Barton, Colleen (Baker Hughes) | Izadi, Ghazal (Baker Hughes) | Tinnin, John (Baker Hughes) | Randazzo, Santi (Baker Hughes) | Ghadimipour, Amir (Baker Hughes) | Bouzida, Yasmina (Baker Hughes) | Leseur, Nicolas (Baker Hughes)
Abstract The Diyab Reservoir is an unconventional prospect in Abu Dhabi where previous exploration efforts revealed thin low permeability targets, unsuccessful stimulation, and poor well placement. This early field experience coupled with limited knowledge about local in situ stress and the impact of faults and subseismic fractures to affect hydrofracs led to a concentrated field data acquisition program together with a fully integrated 3D reservoir simulation approach to assess Producibility, Fracability and Geohazards in the Diyab. The fit-for-purpose field data acquisition program, 3D hydraulic fracture simulation, and reservoir flow modeling helped establish a baseline understanding of the relationship between 3D reservoir characterization and proppant transport. Seismic data was interpreted to understand structural components and natural fracture characterization. Elastic inversions were performed on this data using petrophysical models to populate high-resolution 3D geological and geomechanical models calibrated against log derived rock properties and in situ tests. A detailed analysis of core identified bitumen layers and thinly laminated mudstones that have the ability to undermine completions by causing horizontal hydraulic fracture growth and undesirable proppant migration. Physics-driven frac simulation of this fully integrated geomodel was performed to determine design completion and fracking strategies for the target reservoirs. Post frac analysis for three Diyab wells reveals that the ISIP varied significantly among the stages and the largest post frac pressure drops occurred at stages intersected by small-scale faults or natural fracture zones, particularly when they are well oriented for shear slip. Results of high-resolution 3D simulation of frac stages on earlier wells showed proppant distribution closely followed reservoir property distributions of low stress and similar Young’s Modulus values. Wells were landed in specific target reservoirs, however, the simulation demonstrated that proppant from some stages was inadvertently placed in overlying reservoirs. The natural fractures play a significant role in stage efficiency indicating the need to utilize non-geometric completion design. Simulating the role of natural fractures to create reservoir access indicated significant differences in propped height and length within naturally fractured stages. Dual permeability pre-frac reservoir modeling based on frac simulation results predicted cumulative gas rates for the new wells.
Zhang, X. (Research Centre of Multiphase Flow in Porous Media, China University of Petroleum (East China)) | Huang, Z. (Research Centre of Multiphase Flow in Porous Media, China University of Petroleum (East China)) | Yao, J. (Research Centre of Multiphase Flow in Porous Media, China University of Petroleum (East China)) | Bi, Y. (Research Centre of Multiphase Flow in Porous Media, China University of Petroleum (East China)) | Li, Y. (Research Centre of Multiphase Flow in Porous Media, China University of Petroleum (East China)) | Lei, Q. (ETH Zurich)
ABSTRACT We develop a coupled thermo-hydro-mechanical (THM) model to study the fluid flow and heat extraction processes in hot fractured vuggy reservoirs consisting of natural fracture network and vug. Fluid flow along fractures and vugs are determined according to the cubic law and Navier-Stokes equation, and an extended Beavers-Joseph-Saffman boundary condition is adopted to couple the porous media-vug interface. Heat exchange between the interface of fracture, vug and matrix are calculated based on local thermal nonequiuilibrium. We implement a fracture constitutive model to capture the variation of fracture apertures due to normal compression-induced closure and shear dislocation-induced dilation. We conduct a series of numerical experiments to systematically analyze how hydraulic properties and heat extraction parameters are affected by the combined effects of geometrical distribution and geomechanical deformation of fracture vug networks. The results show geometrical connectivity of fracture vug networks plays a critical role in dominating the thermo-hydro-mechanical processes of fractured vuggy rocks and the geomechanical deformation of fractured vuggy reservoir exerts a secondary-order influence on the response of hydraulic and thermal performance. 1. INTRODUCTION Hot fractured vuggy reservoir consisting of rock matrix, fractures and vugs are naturally existed in the fracture/karst dominated carbonate rock, classified as one of the resource types of geothermal play . Well-developed Fractures (distributed with disconnected or connected form) and vugs (isolated or connected with fractures, varied in size from centimeter to meters in diameter) are existed due to the tectonic movement and paleokarst dissolution effects . Long-term circulation of cold fluid into a fractured vuggy reservoir tends to disturb the hydraulic, thermal and mechanical equilibrium of the reservoir, leading to spatial and temporal variations of fracture transmissivity, due to compression-induced closure and shear-induced dilatancy of rough fractures [3–6]. Meantime, the fractures play a vital role in enhancing the conductivity of low permeable rock mass and increase the efficiency of heat extraction. Therefore, the understanding of fluid flow and heat transport in the context of combined effects of geometrical distribution and geomechanical deformation of fracture vug networks in fractured vuggy geothermal reservoirs is of great importance for optimizing the long-term heat extraction [7, 8]. However, due to the complex geometry of fracture and vug and distinct flow patterns of different reservoir space, it is challenge to conduct numerical simulation of fluid flow and heat transfer in fractured vuggy reservoir with the consideration of geomechanical process.