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Results
Application of Fracture Injection Test, Rate Transient Analysis, and Pearson Correlation in Niobrara and Codell Formations to Evaluate Reservoir Performance in a Northern DJ Basin
Mindygaliyeva, B. (Colorado School of Mines) | Bekbossinov, N. (Colorado School of Mines) | Kazemi, H. (Colorado School of Mines)
ABSTRACT: This paper presents an assessment of well drilling strategy and the associated hydraulic fracture stimulation for a field in the Northern DJ Basin, Colorado. The paper is rich in data related to well orientation, completion, and production over a ten-year period from an unconventional field. Shale formations have very low permeabilities; however, multistage hydraulic fracturing stimulates the rock matrix by inducing micro- and macro-cracks; thus, improving formation drainage. Subsequently, rate transient analysis (RTA) of production data determines the quality of well stimulation. RTA emanates from single-phase linear-flow theory using rate-normalized-pressure versus (Equation) of the production data; however, RTA also extends to multiphase flow. RTA yields the effective formation permeability (EFP) and, occasionally, hydraulic fracture conductivity (HFC). Additionally, we used an iterative Perkins-Kern-Nordgren (PKN) model to interpret diagnostic fracture injection tests (DFIT) for the unstimulated formation permeability. Finally, we used 21 variables to generate a ‘correlation map’ of various reservoir performance measures: well s pacing, lateral length, number of perforations, total stimulation fluid injected, amount of sand placed, sand mesh size, quantity of p roduced oil, gas, and water. The variables that yielded the strongest positive correlation coefficients were well spacing, produced oil and gas volumes, 20/40 sand, acid additives, EFP, and HFC. 1. INTRODUCTION The Shale formations are denoted as ‘tight’ reservoir plays with low, nano-Darcy, matrix permeabilities where pore-size distribution is in the nanometer higher frequencies (Luo, 2018). Because of low matrix permeability, the maturation of the organic matter takes place in the source rock and the resultant distribution of hydrocarbon components also remains within the source rock with little outward migration. Formations with such characteristics are designated ‘unconventional reservoir’. There is a continued demand for hydrocarbon production due to the global energy demand and population growth. Fortunately, innovations in the technological sector of the oil and gas industry has provided effective means of oil and gas recovery from such tight formations (Kazemi et al., 2015). Contribution of unconventional reservoirs is significant in maintaining the balance in the energy market (Cui, 2015).
ARMA-2022-0018
basin, bekbossinov, Codell formation, Colorado, correlation, correlation coefficient, correspond, equation, flow in porous media, Fluid Dynamics, formation, fracture, Fracture Injection Test, hereford field, hydraulic fracturing, mindygaliyeva, Niobrara Formation, permeability, regime, Reservoir Characterization, seismic surveying, unconventional reservoir, Upstream Oil & Gas
Country:
- North America > United States > Wyoming (1.00)
- North America > United States > Colorado (1.00)
Oilfield Places:
- 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 > Permian Basin > Delaware Basin (0.99)
- (11 more...)
SPE Disciplines:
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (2 more...)
Technology: Information Technology > Artificial Intelligence > Machine Learning > Performance Analysis > Accuracy (0.41)
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.
Artificial Intelligence, asset and portfolio management, completion design, complex reservoir, correlation, cumulative oil production, Denver Basin, Directional Drilling, drilling operation, Energy Economics, equation of state, fluid intensity, geocluster, HCPV, hydraulic fracturing, intensity, machine learning, n-plot, Niobrara Well, normalization plot, normalized stimulation fluid, Petroleum Engineer, stimulation fluid, unconventional resource economics, Upstream Oil & Gas, well performance, well spacing
Country:
- North America > United States > Wyoming (1.00)
- North America > United States > Nebraska (1.00)
- North America > United States > Kansas (1.00)
- North America > United States > Colorado (1.00)
Oilfield Places:
- 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...)
SPE Disciplines:
- Well Completion > Hydraulic Fracturing (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (0.94)
- (2 more...)
Technology: Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (0.86)
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.
Bakken formation, basin, fracturing fluid, fracturing materials, hydraulic fracturing, lateral foot, lateral length, Midland Basin, oil production, operator, Permian Basin, proppant, proppant volume, shale, slickwater, Technology Conference, Texas, Thickness, unconventional resource technology conference, Upstream Oil & Gas, US government, Williston Basin
Country:
- North America > United States > Texas (1.00)
- North America > United States > Oklahoma (1.00)
- North America > United States > North Dakota (1.00)
- (2 more...)
Geologic Time:
- Phanerozoic > Paleozoic > Permian (1.00)
- Phanerozoic > Paleozoic > Devonian (0.93)
- Phanerozoic > Paleozoic > Carboniferous > Mississippian (0.69)
Industry:
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
Oilfield Places:
- 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...)
SPE Disciplines: Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
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