Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract This paper presents a rigorous method to scale rate-time profiles of multi-fractured horizontal wells (MFHW) to a set of reference reservoir and completion properties. Scaling is required for development of accurate production forecasts and typical well production profiles (type wells) with minimum uncertainty. We use a modified version of commonly-used type curves, notably the Wattenbarger type curve, to fit production data. The fit requires that production profiles exhibit a negative half slope during transient linear flow followed by negative unit slope during boundary-dominated flow on a rate vs. material balance time plot. The horizontal and vertical displacement required to fit observed data to the type curve define the scaling factors for individual wells. We present a set of equations to scale a given well's production profile to that of a reference well with specified effective permeability, fracture length, lateral length, net-pay thickness, drawdown, and fracture stage spacing. Just as we can scale a group of wells to common reference conditions, we can also rescale to predict the performance of a well with specified properties, such as average properties determined from wells analyzed or wells with completion designs different from those analyzed. While it is common and clearly important to normalize (scale) rate profiles for lateral length, we demonstrate that it is also crucial to scale production profiles in rate and time to account for differences in permeability, fracture spacing and thus, the duration of flow regimes. We provide examples of successful scaling based on publically reported production data from Marcellus, Barnett, Niobrara, Midland Basin (Wolfcamp) and Eagle Ford resource plays. Most of the methods used to assess the performance of MFHW's in resource plays rely on having a statistically significant number of analogs. However, datasets of sufficient size are often either unavailable or limited by the large variety of completion designs and well performance characteristics. Our approach to scale production can dramatically increase the number of analogs available to characterize a geologically similar area and thus reduce the uncertainty in production forecasts.
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.32)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- (30 more...)
Dimensionless Section-Level Cumulative Oil Vs. Pumped Fluid Normalization Plot in Unconventional Development
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.
- North America > United States > Wyoming (1.00)
- North America > United States > Colorado (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Geology > Geological Subdiscipline > Stratigraphy (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- (48 more...)
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 โ 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.
- North America > United States > Wyoming (1.00)
- North America > United States > Colorado (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- (22 more...)
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.
- North America > United States > Colorado > Weld County (0.37)
- North America > United States > Colorado > Denver County (0.37)
- North America > United States > Colorado > Larimer County (0.27)
- (3 more...)
- Geology > Rock Type > Sedimentary Rock (0.70)
- Geology > Structural Geology > Fault (0.69)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- (13 more...)
Abstract Unconventional completions in North America have seen a paradigm shift in volumes of proppant pumped since 2014. There is a clear noticeable trend in both oil prices and proppant volumes โ thanks to low product and service costs that accompanied the oil price crash in early 2015. As the industry continues to recover, operators are reevaluating completion designs to understand if these proppant volumes are beyond what is optimal. This paper analyzes trends in completion sizes and types across all major unconventional oil and gas plays in the US since 2011 and tracks their impact on well productivity. Completion and production data since 2011 from more than 70,000 horizontal wells in seven major basins (Gulf Coast, Permian, Appalachian, Anadarko, Haynesville, Williston and Denver Julesburg basins) and 11 major oil/gas producing formations were analyzed to examine developments in proppant and fluid volumes. Average concentration of proppant per gallon of fluid pumped was used to understand transitional trends in fracturing fluid types with time. Production performance indicators such as First month, Best 3 or Best 12 months of oil and gas production were mapped against completion volumes to evaluate if there are added economic advantages to pumping larger designs. In general, all major basins have seen progressive improvements in average well performance since 2011, with the Permian Basin showing the highest improvement, increasing from an average first-six-months oil production of 25,000 bbl in 2011 to 75,000 bbl in 2017. The Gulf Coast basin, where the Eagle Ford formation is located, has seen a 6-fold increase in proppant volumes pumped per foot of lateral since 2011 while the Permian and Appalachian basins hit peak proppant volumes in 2015 and 2016 respectively. In Permian and Eagleford wells, higher proppant volumes in general have resulted in better production up to a certain concentration. In Williston and Denver basins, most operators are moving away from gelled fluids, and reduced average proppant concentration per fluid volume pumped shows inclination toward hybrid or slickwater designs. While some of these observations are tied to reservoir quality, proppant volumes have begun to peak as operators have either reached an optimal point or are in the process of reducing volumes. Demand for proppant is expected to nearly double by 2020. As oil prices continue to recover, well AFEs continue to increase, despite multiple efforts to improve capital efficiency. The need for enhanced fracture conductivity and extended half-lengths on EURs are been discussed by combining actual observed production data and sensitivities using calibrated production models. The industry is moving toward large-volume slickwater fracturing operations using smaller proppants, but he operating landscape is expected to see a correction when such designs become less economical.
- North America > United States > Texas (1.00)
- North America > United States > Oklahoma (1.00)
- North America > United States > North Dakota (1.00)
- (4 more...)
- Phanerozoic > Paleozoic > Permian (1.00)
- Phanerozoic > Paleozoic > Devonian (0.93)
- Phanerozoic > Paleozoic > Carboniferous > Mississippian (0.69)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.94)
- Geology > Structural Geology > Tectonics (0.69)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (97 more...)
Abstract Accelerating the learning curve in the development of the Vaca Muerta utilizing lessons learned in North American unconventional resource plays is the focus of this paper. Reducing completion costs while maintaining high productivity has become a key objective in the current low-price environment. Completion diagnostics have been demonstrated to optimize stimulation and completion parameters that have shaped successful field developments. The paper reviews stimulation diagnostic data from wells completed in the Tuscaloosa Marine Shale, Eagle Ford, Wolfcamp and Niobrara shale formations. Case histories are presented in which proppant and fluid tracers were successfully employed in completion optimization processes. In the examples presented, diagnostic results were used to assess the stimulation of high productivity intervals within a target zone, evaluate various completion methods, and optimize stage and cluster spacing. The diagnostic data were compared with post-frac production rates in an effort to correlate completion changes with well performance. Results presented compare first, engineered perforations versus conventional geometrically spaced perforations to drive up effectiveness in cluster stimulation. Second, new chemistries, such as nanosurfactant, versus conventional chemistries to cut either completion cost or prove their profitability. Third, employing an effective choke management strategy to improve well productivity. Last, as in any stacked pay, determining fracture height growth in order to optimize well density, well spacing, field development and ultimately the recovery of the natural resources. Completion effectiveness is shown to be improved by landing laterals in high productivity target intervals, increasing proppant coverage across the lateral by utilizing the most effective completion methods, optimizing cluster spacing and decreasing the number of stages to reduce completion costs while achieving comparable production rates. Cluster treatment efficiency (CTE), in particular, has become a critical metric when optimizing hydraulic fracturing treatment designs based on current and future well densities. It can be used to rationalize well performance as well as to identify possible candidates for a refrac program. Using completion diagnostics, successful completion techniques were identified that led to production enhancements and cost reductions in prolific plays such as the Tuscaloosa Marine Shale, Eagle Ford, Wolfcamp and Niobrara.
- North America > United States > Wyoming (1.00)
- North America > United States > Texas (1.00)
- North America > United States > Colorado (1.00)
- North America > United States > Nebraska (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play (1.00)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- (30 more...)
3D Hydraulic Fracture Simulation Integrated With 4D Time-Lapse Multicomponent Seismic and Microseismic Interpretation, Wattenberg Field, Colorado
Alfataierge, A.. (Colorado School of Mines) | Miskimins, J. L. (Colorado School of Mines) | Davis, T. L. (Colorado School of Mines) | Benson, R. D. (Colorado School of Mines)
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.
- North America > United States > Colorado > Weld County (1.00)
- North America > United States > Colorado > Larimer County (1.00)
- North America > United States > Colorado > Denver County (1.00)
- (3 more...)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- (12 more...)
Abstract The acquisition of accurate downhole pressure measurements from land-based unconventional wells can enable analysis of pressure data that can be used to help optimize and reduce the cost of fracture treatments and improve overall well productivity. The pressure data for the analysis are obtained from downhole electronic gauges in both the target well and in the surrounding observation/monitoring wells. The objective of this paper is to demonstrate the value monitoring this downhole pressure data can provide throughout the life of land-based unconventional wells. The paper also describes the selection of the equipment, the steps necessary for its successful installation, project commissioning, and acquisition of reliable data throughout the life of the well. Historically, operators have experienced less-than-desirable success rates for long-term downhole pressure monitoring, especially in multizone, openhole, horizontal wells. This paper discusses how the success rate of these installations has been significantly improved by the implementation of a program with a well-defined series of steps that includes detailed planning (completing the well on paper exercise), onsite function testing of equipment prior to installation, and stringent attention to job execution detail. This program is based on the fact that adoption of the proper selection criteria for the application is critical to selection of the proper type of monitoring equipment and to the operational and economic success of these pressure-monitoring projects.
- North America > United States > Colorado (0.69)
- North America > Canada (0.68)
- Europe (0.68)
- (2 more...)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (48 more...)
True-Triaxial Hydraulic Fracturing of Niobrara Carbonate Rock as an Analogue for Complex Oil and Gas Reservoir Stimulation
Frash, L. P. (Colorado School of Mines) | Gutierrez, M. (Los Alamos National Laboratory) | Tutuncu, A. (Colorado School of Mines) | Hood, J. (Khalifa University) | Mokhtari, M. (Colorado School of Mines)
Abstract Well stimulation by hydraulic fracturing is a common method for increasing the injectivity and productivity of wells. This method is beneficial for many applications including oil, gas, geothermal energy and CO2sequestration, however, hydraulic fracturing in shale and other similarly complex geologies remains poorly understood. A 300ร300ร300 mmblock specimen of Fort Hays Limestone was hydraulically fractured in the laboratory using a true-triaxial apparatus to study complex hydraulic fracturing. This material is a member of the Niobrara Shale formation, a major unconventional oil and gas play in the Denver-Julesburg Basin. Hydraulic fractures were stimulated by injection of plastic epoxy. Injected epoxy clearly marked the fluid penetrated zones of the stimulated fractures, partially preserved the in-situ fracture aperture and bonded the fracture faces to give improved visualization of complex fractures in cross-sections cut after the experiment. The experiment resulted with a complex fracture network including prominent tensile hydraulic fractures, shear activated discontinuities and bedding plane separations. Acoustic emissions, injection pressures and injection rates were analyzed with reference to the fracture geometry to develop relationships between these parameters and to develop means of identifying complex fracture growth, as applicable in field scenarios where the actual fracture geometry is not easily measured. 1. INTRODUCTION Hydraulic fracturing is a well stimulation method where fluid is injected into rock to create new fractures. These fractures are intended to function as high-conductivity fluid pathways enabling increased well productivity or injectivity. The hydraulic fracturing method can be used to improve oil, gas, geothermal, carbon sequestration, and deep waste injection well performance. Design and optimization of a hydraulic fracture treatment is non-trivial due to complexity stemming from multi-physical interactions between the in-situ rock and injected fluids. A comprehensive understanding of hydraulic fracture geometry is critical for understanding and predicting fluid flow behavior through stimulated wells. Fracture geometries in field treatments are expected to be complex, including combinations of tensile and shear fractures [1,2]. This expectation is supported by mine-back studies [3,4] and microseismic monitoring where acoustic emission (AE) sources are typically dispersed through a volume of rock and do not clearly indicate discrete fractures. Some stimulation treatments are thought to produce complex networks of inter-connected fractures, accessing large rock volumes.
- North America > United States > Colorado (1.00)
- North America > United States > Wyoming (0.89)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.86)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.77)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Kansas > Laramie Basin > Niobrara Formation (0.99)
- (6 more...)
Abstract Development and operation of oil and gas assets can contribute positive social gains to local, regional and national communities. Local economic benefits of oil and gas development and production can include new business opportunities and employment generated for communities, royalties paid to mineral and land owners, and taxes paid to governments. On a per employee basis, the oil and gas industry is a high-output, high-wage industry that has a multiplier effect on local economies. In addition to generating thousands of direct jobs and wages, the oil and gas sector purchases goods and services from other industries, thereby building transferrable skillsets and creating broad capacity in the community. Memberships and donations made to local universities and organizations can also benefit the community. This paper focuses on the economic benefits to local communities, and across the state, from the investment in exploration, development and operation of a specific unconventional resource asset in Colorado, USA. The investment spend by an operator (ConocoPhillips) is mapped from direct contracts through subcontracting with sub-suppliers. The mapping shows geographically dispersed benefits as they cascade through the oil and gas supply chain into the local communities in oil producing counties and beyond into counties without oil production. Investment with large national companies is mapped to increased employment throughout Colorado. Direct spend with Colorado-based companies is inventoried to show benefits to small suppliers and contractors. Spend on local supporting services, such as retail, restaurants and lodging with hundreds of businesses is documented. The framework of local economic benefits mapped for a specific Colorado unconventional asset development and operation is typical for unconventional asset developments and may be employed by similar developments in other geographies. This approach to mapping local economic benefits may also be employed in other types of oil and gas project developments to comprehensively identify positive social impacts. A Local Economic Benefit Fact Sheet was created from this assessment and is used to communicate key messages to external stakeholders in Colorado. The fact sheet is included in Appendix 1.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- (17 more...)