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Results
Naturally Occurring Isotopic Tracers Provide Insight into Hydraulic Fracturing Flowback and Horizontal Well Clean-Up Dynamics
Travers, Patrick (Dolan Integration Group) | Burke, Ben (HighPoint Resources) | Rowe, Aryn (HighPoint Resources) | Hodgetts, Stephen (Dolan Integration Group) | Dolan, Michael (Dolan Integration Group)
Abstract Scope: The management, treatment and disposal of hydraulic fracturing flowback fluids and produced water presents a major challenge to operators. Though the volumes of water are tracked closely during operations, the sources of that water are not well understood. The objective of this study is to apply a cost effective and proven technique, stable isotope analysis, along with an extensive sampling program (n>1,500 samples) to describe the contributions of variable water sources through completions, flowback and the production lifecycle of multiple horizontal, hydraulically fractured wells in the Denver Basin, Colorado. Methods: The water stable isotopes of hydrogen (H and H) and oxygen (O and O) are conservative tracers and particularly advantageous because they occur naturally in these systems and rely on well-established scientific and analytical techniques. Sample collection is simple and does not require specialized equipment or operational downtime. 80 horizontal, hydraulically fractured wells completed in the Cretaceous Niobrara or Codell Formations were selected for this study. More than 1,500 samples were collected and analyzed in total, including: baseline samples of the source water used to stimulate the well, time series samples collected at daily or semi-daily intervals during the early weeks of flowback, and samples collected several months after the wells were brought on production. Samples of produced water were also collected from legacy wells in the field as well as offset wells being monitored for frac hits during completions. Results: Samples of the near surface and shallow aquifer source water collected prior to hydraulic fracturing fell on or near the global meteoric water line (GMWL) as defined by Craig (1961). This isotopic signature is expected for modern water in aquifers charged by precipitation. In contrast, samples collected during flowback and production were significantly enriched in H and O. Furthermore, the magnitude of the isotopic difference between the source and flowback water increased with time until equilibrating after several months. This equilibrated composition is consistent for Niobrara and Codell wells in the field, as well as legacy wells sampled and consequently is hypothesized to be indicative of native formation water. The study did find exceptions, particularly with wells known to be connected to major fault or fracture networks. These samples deviated from typical formation water signatures, potentially indicating the migration of deeper sourced fluids or the vertical mixing of shallower fluids with Cretaceous waters. Significance: The scale of this study is unique in the literature and provides novel and comprehensive insight into the dynamics of flowback and the sources of produced water in the Denver Basin. This study demonstrates that these data can clearly differentiate water injected during stimulation from native formation waters, as well as track the magnitude and duration of well cleanup. It can also identify wells that may be producing water with a unique composition due to fluid migration through faults or fracture networks or due to nearby well communication.
- 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 > Codell Formation (0.99)
- (47 more...)
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 – 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 – 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 > Neuquén > 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...)
Many horizontal wells and fracture stages are needed to drain a shale reservoir, and these is a need for effective fractures and horizontal wells to produce these reservoirs. We conducted a case study of the use of data analytics to study the Niobrara shale rock, and suggest the best completion strategies used to effectively produce from the shale rock. We then compared the characteristics of the Niobrara shale rock with the 12 most common shale plays in North America. Geochemical and geomechanical properties of these shale rocks vary significantly among the reservoirs and vary within the same reservoir. We believe that this paper will assist in selecting proper completion techniques for horizontal wells. It is a standard belief in the industry that sweet spot segment of the rock leads to successful treatment and then a higher recovery. Table 1 shows the average sweet spot criteria.
- North America > United States > Texas (1.00)
- North America > United States > Colorado (1.00)
- North America > United States > Wyoming (0.88)
- (2 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 > Texas > Haynesville Shale Formation (0.99)
- (10 more...)
Summary The Codell Sandstone has recently been the subject of extensive exploration and subsequent development activity in both the Colorado and Wyoming portions of northern DJ Basin. The Niobrara Formation has been the primary historical exploration target since the late 1980's due to success at the Silo Field from horizontal wells drilled in the Niobrara B Bench. In 2009, EOG Resources discovered the Hereford Field with the Jake 02-01H, producing approximately 1700 barrels of oil per day initially from the Niobrara B Bench. The next two years in the area saw much drilling focused for the Niobrara B Bench with the completion of many non-commercial wells. In 2012, SM Energy drilled a lateral focused on evaluating the Codell Sandstone. Cirque Resources, Kaiser Francis and EOG soon followed with their own exploratory wells, establishing the play. This new play area is thermally in the oil window. Codell Sandstone oil producers have gas-oil ratios less than 2000 scf/bbl. The Codell Sandstone thins from north to south due to erosional truncation beneath an angular unconformity at the base of the Fort Hays Limestone Member of the Niobrara Formation. Gross thickness ranges from 18 to 33 feet. The Codell Sandstone is a very-fine to fine-grained sandstone and produces oil from two main facies: bioturbated sandstone and laminated sandstone. The laminated facies is parallel to sub-horizontally bedded, has 8 to 15 percent porosity, and .01 to 0.10 millidarcies permeability. The bioturbated sandstone has 8 to 13 percent porosity and .008 to .05 millidarcies permeability. The Codell Sandstone is a low-resistivity pay zone that produces oil with low water cuts from zones with less than 10 ohm-m resistivity. Clay content is 15–25% with abundant microporosity as imaged with epifluorescent microscopy, accounting for high bound water content and explaining the low formation resistivity. Oil typing indicates the oil found in the Codell is sourced from the Niobrara and is distributed across the area through migration. Oil saturation varies across the play depending the on the distance from areas of oil generation and expulsion into the Codell. Use of mercury capillary injection pressure analysis was essential in resolving the oil migration route throughout the play area. Drilling and completion techniques have evolved since the first wells were drilled. Best practices to date involve 1280 acre spacing units with 9300' lateral lengths, cemented liner with perf & plug completion techniques. Introduction The DJ Basin has been a very active province for exploration and development in the recent horizontal drilling boom since 2009. Driven primarily by the Niobrara Formation, the Codell Sandstone has also been a large contributor to activity. Due to all of this activity, both within the core of the Wattenberg Field as well as the step out activity in both Colorado and Wyoming, the production for the basin has increased from 192,000 BOEPD in 2010 to over 480,000 BOEPD in early 2016.
- North America > United States > Wyoming > Laramie County (0.86)
- North America > United States > Colorado > Weld County (0.71)
- 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 > Codell Formation (0.99)
- (21 more...)