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Abstract In some basins, large scale development of unconventional stacked-target plays requires early election of well targeting and spacing. Changes to the initial well construction framework can take years to implement due to lead times for land, permitting, and corporate planning. Over time, as operators wish to fine tune their development plans, completion design flexibility represents a powerful force for optimization. Hydraulic fracturing treatment plans may be adjusted and customized close to the time of investment. With a practical approach that takes advantage of physics-based modeling and data analysis, we demonstrate how to create a high-confidence, integrated well spacing and completion design strategy for both frontier and mature field development. The Dynamic Stimulated Reservoir Volume (DSRV) workflow forms the backbone of the physics-based approach, constraining simulations against treatment, flow-back, production, and pressure-buildup (PBU) data. Depending on the amount of input data available and mechanisms investigated, one can invoke various levels of rigor in coupling geomechanics and fluid flow – ranging from proxies to full iterative coupling. To answer spacing and completions questions in the Denver Basin, also known as the Denver-Julesburg (DJ) Basin, we extend this modeling workflow to multi-well, multi-target, and multi-variate space. With proper calibration, we are able generate production performance predictions across the field for a range of subsurface, well spacing, and completion scenarios. Results allow us to co-optimize well spacing and completion size for this multi-layer column. Insights about the impacts of geology and reservoir conditions highlight the potential for design customization across the play. Results are further validated against actual data using an elegant multi-well surveillance technique that better illuminates design space. Several elements of subsurface characterization potentially impact the interactions among design variables. In particular, reservoir fluid property variations create important effects during injection and production. Also, both data analysis and modeling support a key relationship involving well spacing and the efficient creation of stimulated reservoir volumes. This relationship provides a lever that can be utilized to improve value based on corporate needs and commodity price. We introduce these observations to be further tested in the field and models.
Abstract The goal of our work was to maximize gas production and recovery from a horizontal appraisal well in the Mancos shale in New Mexico. This required a fracture design that would maximize perforation cluster efficiency and a lateral placement strategy that would maximize gas recovery. A key challenge was to design a fracture treatment that would overcome the extreme stress shadowing effects. Another key challenge was to optimize the lateral placement balancing multiple factors. Fracture treatment simulations were completed for various designs. Fracture simulations indicated cluster efficiency could be dramatically improved by optimizing the way we pump the pad. A step-up technique for increasing pumping rates during the pad stage helped to initiate more fractures. Intra-stage diversion was utilized. Fracture simulations were performed to optimize the lateral placement. This required balancing multiple factors to access the highest gas-in-place (GIP) interval yet facilitate more fracture initiations per stage. Fracture descriptions from the fracture simulations were input to a reservoir simulator to determine the optimal design. This paper will focus on the hydraulic fracture modeling. This appraisal well was the most productive Mancos gas well ever delivered in the San Juan Basin. The 9,546’ lateral produced at a choke constrained plateau rate of about 13 MMscfd for 7 months and produced over 6 BCF in the first 20 months. A radioactive tracer log indicated an overall perforation cluster efficiency of 83%, a significant achievement in a shale with high stress shadowing. The fracturing fluid design, diverter design and pumping techniques can be applied in many other shales as a low-cost way to increase perforation cluster efficiency, which will in turn result in higher production rates and higher cumulative recovery. Building on the success observed in the Mancos wells, BP and BPX Energy have subsequently utilized these techniques in other shale plays with success. The concepts and workflow used to decide the optimal lateral placement is a well-defined approach that can be applied to other unconventional wells to increase hydrocarbon recovery.
Wallace, K. J. (Encana Oil & Gas (USA) Inc.) | Aguirre, P. Reyes (Schlumberger) | Jinks, E.. (Encana Oil & Gas (USA) Inc.) | Yotter, T. H. (Encana Oil & Gas (USA) Inc.) | Malpani, Raj (Schlumberger) | Silva, Felipe (Schlumberger)
Abstract This paper describes a comprehensive field study of eight horizontal wells deployed in the stacked Niobrara and Codell reservoirs in the Wattenberg oilfield (Denver-Julesburg basin). The overall goal was to understand the geometry of the hydraulic fractures (propped), producing volume with respect to completions design, target reservoirs, and well spacing. Through this understanding we are able to develop the asset more effectively and economically. In this study, an unconventional hydraulic fracture model was developed and calibrated against surface and downhole microseismic recordings, "frac hits" in offset vertical wells, chemical tracers, pressure interference testing, diagnostic fracture injection tests (DFITs), and treatment pressure/instantaneous shut-in pressure (ISIP) history matching. The hydraulic fracture geometry and conductivity were simulated using unconventional models populated with a natural discrete fracture network (DFN) defined through outcrop and image log observations along with a rigorous mechanical earth model. A special unstructured grid that conforms to the shape of the calibrated hydraulic fracture model planes was constructed. This unstructured, fractured reservoir grid was fed into a compositional reservoir simulator that was tuned using pressure dependent permeability, offset vertical well pressure depletion, and relative permeability (among others) to match the production history available to date. This workflow allowed for complete integration of geological, geomechanical, and production models in a single platform to produce a consistent set of results. This study concludes that 1) Increasing the hydraulic fracture treatment volume beyond a certain point does not significantly enhance the fracture geometry or improve early time well performance; 2) additional wells are needed to access undrained reservoir; 3) existing vertical-well depletion has a significant impact on early time well performance, and; 4) hydraulic fracture height extension allows initial communication between the Niobrara and Codell reservoirs, however this connectivity dissipates during production likely due to the loss of fracture connectivity vertically.
Abstract This paper presents the continuing evolution of our Bakken advanced completion design with the added enhancement of Extreme Limited Entry (XLE) perforating. With this cost-effective XLE strategy, we are consistently stimulating more than eleven perforation clusters per stage. Confirmation of this high number of active clusters, or fracture initiation points, has been directly measured with radioactive tracers and fiber optic diagnostics, and more importantly, is validated through improved production relative to offset completions. The goal of this strategy is to consistently and confidently drive a high number of clusters per stage, ultimately increasing capital efficiency by right sizing the cluster and stage count per well. Practically, the number of stages for a 9,500-ft. lateral is limited to 40 or 50 stages in the Bakken due to operational and cost limits. We believe the published trends on stage count are fundamentally linked to the number of active clusters per stage or fracture initiation points, and by driving significantly more active clusters per stage with XLE perforating in combination with previously presented High Density Perforating (HDP), we now have proven the ability to reduce stage count without sacrificing performance. Liberty now incorporates XLE as a key design technique to successfully stimulate 15 clusters per stage. Production performance is encouraging and post frac fiber optic diagnostics support prior radioactive proppant tracer data in showing that over 11 of the 15 clusters shot can be stimulated with slickwater at 80 bpm. XLE operational considerations for frac plug ratings, oriented perforating, even-hole perforating charges, variable pipe friction and a review of existing papers on limited entry are included as well. Limited entry perforating has been around for over 50 years; however, its effectiveness has been limited in the horizontal revolution due to insufficient perforation friction relative to the variability in stress and near-wellbore tortuosity found within a stage. This paper presents the improved results for specifically designing perforations and stimulation injection rates to achieve diversion to almost all 15 perforation clusters per stage. For this paper, we define XLE as completion designs with perforation friction exceeding 2,000 psi. Since the beginning of 2015 we have reduced our standard stage count from 50 down to 27, for a 9,500-ft lateral, while continuing to significantly outperform offset operators. When it comes to value creation, the cost per barrel of oil produced is a critical metric to assess development opportunities and achieving the same or increased oil production with less capital has led to significant gains in capital efficiency.
Li, N.. (Black Hills Exploration & Production) | Lolon, E.. (Liberty Oilfield Services) | Mayerhofer, M.. (Liberty Oilfield Services) | Cordts, Y.. (Black Hills Exploration & Production) | White, R.. (Black Hills Exploration & Production) | Childers, A.. (Black Hills Exploration & Production)
Abstract The Mancos-Niobrara formation in western Colorado is estimated by the USGS to contain 66 trillion cubic feet of natural gas. Successfully developing this asset depends on understanding the geology, geomechanics, the impact of fracture length and height, conductivity, fracture spacing, and well spacing on estimated ultimate recovery. The Mancos-Niobrara has tremendous resource potential and is in the early stages of development in the study area. This paper discusses the development and application of a detailed numerical reservoir model to guide best practice development. Six wells drilled from two multi-well pads and hydraulically fractured to produce natural gas are the subject of this paper. This study provides a comprehensive evaluation and integrated approach to help optimize field development in this new emerging play. The reservoir model includes six wells on two pads. The reservoir was characterized using geochemistry, triple-combo logs, dipole-sonic logs, and formation images. Completion geometry and efficiency were evaluated by collecting data including micro-seismic fracture mapping, micro-deformation, mini-fracturing tests, and production logs. Different designs or treatment schedules were utilized during completion operations to provide additional information on the formation sensitivity to differing completion parameters. The numerical reservoir modeling performed in this study gives deference to the rich data collected. The model was used to estimate effective fracture lengths and heights, evaluate well communications, predict individual well performance, and identify areas for economic optimization. Created fracture half-lengths were estimated to be 900-1,000 ft. This result shows excellent agreement between history matching the hydraulic fracture treatment, micro-seismic monitoring, and production results. The reservoir model confirms direct hydraulic connections, modeled as a few high-conductivity pathways (‘pipelines’), crossing multiple wells that could result from the repeated enhancement of the same natural fracture network during different treatment stages. Production results show large performance differences among the wells despite the similarity in completion designs which is attributed to well interference and shared production. Therefore, it would be advantageous in future development―utilizing essentially the same completion technique, double well spacing to 2,700 ft., while still maintaining 75%-80% gas recovery factors over 40 years, and drilling half the number of wells. Production logging indicated that only 30% of perforated clusters were producing a significant amount of gas. The simulation sensitivity shows that significant gas production boost was possible, especially in the first five years, if cluster efficiency was increased. Fracture conductivity was found to be of secondary importance for short and long-term gas recoveries due to the low system permeabilities. Accordingly, the flexibility in diversion techniques and varying proppant size to increase cluster efficiency should be tested. The reservoir modeling also shows that only a portion of the gross formation thickness may be effectively produced implying that the effective fracture height may be less than 750 ft. measured by micro-deformation. This leads to a future opportunity of targeting the more liquids-rich upper Niobrara zones in addition to the lower gas-producing interval.