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Rosenhagen, Nicolas M. (Colorado School of Mines) | Nash, Steven D. (Anadarko Petroleum Corporation) | Dobbs, Walter C. (Anadarko Petroleum Corporation) | Tanner, Kevin V. (Anadarko Petroleum Corporation)
Abstract The volume of stimulation fluid injected during hydraulic fracturing is a key performance driver in the horizontal development of the Niobrara formation in the Denver-Julesburg (DJ) Basin, Colorado. Oil production per well generally increases with stimulation fluid volume. Often, operators normalize both production and fluid volume based on stimulated lateral length and investigate relationships using "per-ft" variables. However, data from well-based approaches commonly display such wide distributions that no useful relationships can be inferred. To improve data correlations, multivariate analysis normalizes for parameters such as thermal maturity, depth, depletion, proppant intensity, drawdown, geology and completion design. Although advancements in computing power have decreased cycle times for multivariate analysis, preparing a clean dataset for thousands of wells remains challenging. A proposed analytical method using publicly available data allows interpreters to see through the noise and find informative correlations. Using a data set of over 5000 wells, we aggregate cumulative oil production and stimulation fluid volumes to a per-section basis then normalize by hydrocarbon pore volume (HCPV) per section. Dimensionless section-level Cumulative Oil versus Stimulation Fluid Plots ("Normalization" or "N-Plot") present data distributions sufficiently well-defined to provide an interpretation and design basis of well spacing and stimulation fluid volumes for multi-well development. When coupled with geologic characterization, the trends guide further refinement of development optimization and well performance predictions. Two example applications using the N-Plot are introduced. The first involves construction of predictive production models and associated evaluation of alternative development scenarios with different combinations of well spacing and completion fluid intensity. The second involves "just-in-time" modification of fluid intensity for drilled but uncompleted wells (DUC's) to optimize cost-forward project economics in an evolving commodity price environment.
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 3D hydraulic fracture simulation modeling integrated with 4D time-lapse seismic and microseismic data were used to evaluate the efficiency of hydraulic fracture treatments in a one square mile spacing test within Wattenberg Field, Colorado. The study was conducted over a section within Wattenberg Field containing eleven horizontal wells that were hydraulically fracture stimulated and produced. The 4D time- lapse multicomponent seismic data were acquired pre-hydraulic fracturing, post-hydraulic fracturing, and after two years of production. The 3D simulation results integrated with and dynamic seismic observations are used to analyze the effect of geological heterogeneity on hydraulic fracturing efficiency and hydrocarbon production. A 3D geomechanical model was generated using geostatistical methods as an input to hydraulic fracture simulation and incorporated the faults and the lithological changes in the study area. The 3D geomechanical model was calibrated through the use of DFIT data from offset wells. A hydraulic fracture simulation model using a 3D numerical simulator was generated and analyzed for hydraulic fracturing efficiency and interwell fracture interference between the eleven wells. The 3D hydraulic fracture simulation is validated using observations from microseismic and 4D multicomponent (P-wave and S- wave) seismic interpretations. The validated 3D simulation results provide insight into the effect of geological heterogeneity on the hydraulic fracturing efficiency by providing information relative to the induced fracture lengths, resultant effective fracture lengths and established fracture conductivity. The 3D simulation result and dynamic seismic interpretations both reveal that variations in reservoir properties (faults, rock strength parameters, and in-situ stress conditions) influence and control hydraulic fracturing geometry and stimulation efficiency. Microseismic data is observed to capture hydraulic fracture lengths over 1000 ft. This was also confirmed using tracer analysis. The P-wave time-lapse seismic response from hydraulic fracturing is shown to be affected by pressure pulses created from stimulating the reservoir. The 4D P-wave response is indicative of the presence of pressure compartmentalization caused by fault barriers within the reservoir. The P-wave response also confirms the results from the 3D hydraulic fracture simulation demonstrating an effective stress barrier above the Niobrara formation which allows hydraulic fracture containment to occur. Shear wave (S-wave) time- lapse seismic data are shown to provide a close estimate for effective fracture lengths that result from hydraulic fracturing based on a successful match to the simulation results. The effective fracture length is defined as the propped fracture length that provides communication with the wellbore during the production cycle. Through this integrated 3D hydraulic fracture simulation modeling more confidence is placed on results from the simulation as a guide for further optimizing the development of the Niobrara Formation within the Wattenberg Field. The integrated analysis provides valuable insight into optimizing well spacing, increasing recovery and improving production performance in the Niobrara, as well as highlighting intervals with bypassed potential within the reservoir.
Abstract This paper presents construction and validation of a reservoir model for the Niobrara and Codell Formations in Wattenberg Field of the Denver-Julesburg Basin. Characterization of Niobrara-Codell system is challenging because of the geologic complexity resulting from the presence of numerous faults. Because of extensive reservoir stimulation via multi-stage hydraulic fracturing, a dual-porosity model was adopted to represent the various reservoir complexities using data from geology, geophysics, petrophysics, well completion and production. After successful history matching two-and-half years of reservoir performance, the localized presence of high intensity macrofractures and resulting evolution of gas saturation was correlated with the time-lapse seismic and microseismic interpretations. The agreement between the evolved free gas saturation in the fracture system and the seismic anomalies and microseismic events pointed to the viability of the dual-porosity modeling as a tool for forecasting and future reservoir development, such as re-stimulation, infill drilling, and enhanced oil recovery strategies.
Summary The 3D hydraulic-fracture-simulation modeling was integrated with 4D time-lapse seismic and microseismic data to evaluate the efficiency of hydraulic-fracture treatments within a 1 sq mile well-spacing test of Wattenberg Field, Colorado. Eleven wells were drilled, stimulated, and produced from the Niobrara and Codell unconventional reservoirs. Seismic monitoring through 4D time-lapse multicomponent seismic data was acquired by prehydraulic fracturing, post-hydraulic fracturing, and after 2 years of production. A hydraulic-fracture-simulation model using a 3D numerical simulator was generated and analyzed for hydraulic-fracturing efficiency and interwell fracture interference between the 11 wells. The 3D hydraulic-fracture simulation is validated using observations from microseismic and 4D multicomponent [compressional-wave (P-wave) and shear-wave (S-wave)] seismic interpretations. The validated 3D simulation results reveal that variations in reservoir properties (faults, rock-strength parameters, and in-situ stress conditions) influence and control hydraulic-fracturing geometry and stimulation efficiency. The integrated results are used to optimize the development of the Niobrara Formation within Wattenberg Field. The valuable insight obtained from the integration is used to optimize well spacing, increase reserves recovery, and improve production performance by highlighting intervals with bypassed potential within the Niobrara. The methods used within the case study can be applied to any unconventional reservoir. Introduction The Niobrara Formation is an organic-rich, self-sourcing unit composed of carbonate deposits in the form of alternating layers of chalks and marls. The Niobrara resource play is typically compared with the Eagle Ford Shale because of its high carbonate content. Early production can be dated back to 1976 from vertical wells in Wattenberg Field, although development was not deemed commercially viable at the time (Sonnenberg 2013). The shale play has become more attractive because of horizontal drilling and multistage hydraulic fracturing, allowing the Niobrara to be developed with overall success in the Denver-Julesburg Basin since 2009. The Niobrara Formation extends into several basins within the central USA involving Colorado, Wyoming, Nebraska, and Kansas.