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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.
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.
This paper presents a log-based workflow that provides the cm-scale vertical resolution well framework capable of capturing the level of heterogeneity often present in mudstones. The cm-scale resolution is required to understand (1) scaling effects and (2) rock-engineering-production cause and effect relationships, with the goal of improving production procedures in unconventional reservoirs while decreasing cost and risk. The use of multiple logs, including but not limited to GR, RHOB, PE, NPHI, RESD, DTc and DTs, is key in developing multiphysics-based petrophysical and geomechanical models. One concern with those logs is their ∼1 m vertical resolution which causes a gross averaging of the formation properties as seen by the logging tools. As such, standard log-based petrophysical and geomechanical outputs cannot resolve properties of individual sub-cm-scale beds, often characteristic of mudstones. In spite of their mono-physics nature, borehole images offer a cm-scale vertical resolution alternative capable of capturing beds that are often undetected by scalar logs. In this workflow, the "averaged" rock bulk volumes from the standard vertical resolution (∼1 m) petrophysical model are automatically redistributed into a high-resolution (cm-scale) well framework by using local constraints from borehole images. The resulting high-vertical resolution/multi-physics petrophysical outputs provide a more accurate description of the penetrated formation, where single cm-scale beds and their respective interfaces can be identified. Integration of high-resolution core data in this well framework enables (1) the well-scale calibration and recognition of facies and stacking patterns, (2) the petrophysical and geomechanical characterization of individual beds, (3) the proper prediction of the anisotropic mechanical properties of each individual beds and continuous modeling of the minimum horizontal stress, and (4) the detection and classification of sedimentary interfaces and inclusion of their mechanical and flow contributions to each individual mechanical/flow-units. Once upscaled, these products provide a borehole-view of reservoir quality, fluid flow units, and geomechanical stratigraphy–key information for a more optimal asset development.
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.
Suarez-Rivera, Roberto (W.D. Von Gonten Laboratories, LLC) | Von Gonten, W. D. (W.D. Von Gonten & Co. Petroleum Engineering) | Graham, J. (W.D. Von Gonten & Co. Petroleum Engineering) | Ali, S. (W.D. Von Gonten & Co. Petroleum Engineering) | Degenhardt, J. (W.D. Von Gonten Laboratories, LLC) | Jegadeesan, Ajay (W.D. Von Gonten & Co. Petroleum Engineering)
Abstract Field production data from unconventional reservoirs including Eagle Ford, Marcellus, Wolfcamp, Utica, and Vaca Muerta formations indicate that the landing location of horizontal wellbores is a critical control variable to well productivity, and that small changes in the landing depth (e.g., from 15 to 30 ft.) may result in significant changes in well performance. The reasons for these changes are not yet well understood. In this paper, we show that hydraulic fracture height growth is less extensive than anticipated from hydraulic fracturing modeling or microseismic monitoring, and that proper landing depth selection helps improve the final propped and connected fracture height. We also show that a primary source of height growth suppression is the pervasive rock layering in mudstones and hybrid reservoir systems, which often exhibit strongly contrasting properties between layers and weak interfaces at their contacts. In some reservoirs, bed parallel ash beds, mineralized veins, and slickensides are also present, and all of these interfaces can be weakened further by tectonic deformation. We studied rock layering and various types of weak interfaces in outcrops and cores, including their geologic and stratigraphic context. We also studied the effect of these on hydraulic fracture height growth, using large-scale laboratory hydraulic-fracturing testing, and through field diagnosis of hydraulic fracture height growth in vertical pilot wells. These evidences indicate that the pervasive layering and weak interfaces induce step-overs and branching during hydraulic fracturing, which close after pumping and truncate the initial hydraulic connectivity of the fracture. We observe that during fracturing, the distance from the wellbore to the weak interfaces is a critical measure that controls whether or not these can be overcome without developing step-overs. Proper selection of the lateral landing depth thus depends on understanding rock layering and the distribution of weak interfaces in the section to be fractured. It depends on anticipating critical step-overs and truncation points, and reducing their effect on the hydraulic fracture by adjusting their distance from the wellbore. It depends on choosing the optimal wellbore location that will extend the propped and connected surface area and will maximize economic well production. Using this methodology we have recommended lateral landing depths on multiple wells in the Wolfcamp, Eagle Ford, Utica, Velkerri, and Vaca Muerta plays. This was done while maintaining the same completion and fracture design, so as to evaluate the effect of lateral landing depth alone. Results show a 22% to 46% increase in well production and greater consistency in production from well to well. Some of these results are publicly available. Introduction Field production data from unconventional reservoirs including Eagle Ford, Marcellus, Wolfcamp, Utica, and Vaca Muerta formations indicate substantial variability in well productivity, which is incommensurate with the variability in reservoir properties. Despite our industry's improved understanding of reservoir quality, reservoir thickness and reservoir pressure, we still observe that a substantial number of the wells drilled are uneconomical or marginal, while others perform well, and few outperform all expectations (Hodenfield, 2012). Given our understanding of reservoir quality, what then drives the large variability in well production?