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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.
Summary Pseudosteady-state (PSS) flow is a dominant time-dependent flow regime during constant-rate production from a finite closed reservoir. For a vertical well with a fully penetrated vertical fracture in a circular drainage area modeled as bounded by a slightly elliptical boundary, Prats et al. (1962) obtained an exact analytical solution for such a flow for the case of infinite fracture conductivity. For finite fracture conductivity, the current method to achieve a PSS solution is to run numerical simulations to long times. This paper extends the work of Prats et al. (1962), and presents the first exact analytical solution for PSS flow for a fully penetrated fractured vertical well with finite fracture conductivity. The exact analytical solution is expressed in terms of elementary functions, and it provides simple expressions for the PSS constant, dimensionless productivity index (PI), and effective wellbore radius. The present work eliminates the need of performing time-consuming numerical simulation for obtaining PSS solution for fractured wells in such a reservoir, and the new analytical solution can be used to generate approximate solutions for reservoirs of other geometrical shapes. The new solution can also be used for fracture-design optimization and production-rate decline analysis.
Summary A significant portion of the US gas resources is located in low-permeability, bypassed pay zones, within multilayered sandstone-shale sequences. Acquiring these resources leads to operational and design difficulties in stimulation, particularly if the target zone is bounded above and below by existing producing zones. The objective of this work was to evaluate the impact of adjacent, existing producing zones on the stimulation design and therefore production performance of the bypassed payzone. To investigate this problem, a 3D planar, hydraulic fracture propagation model was constructed and superimposed on a 3D flow model. The physical model comprises three layers, the top and bottom representing previously stimulated and producing layers, and the middle layer the target or bypassed layer. The impact of lithology, fracture length, and total stress variations over time on the fracture conductivity, fracture efficiency, and average reservoir pressure were investigated. Evidence of pressure depletion of the target layer was observed caused by production of the upper and lower layers. The degree of depletion is dependent on the fracture length and lithology of all of the layers. That is, the ability to propagate a fracture in the target layer was a strong function of the shale content and to a lesser extent, on the hydraulic fracture length of the bounding layers. Increased shale content in the target as well as the bounding layers resulted in a decrease in fracture conductivity of the target layer. However, an increase in fracture length did not necessarily result in a decrease in fracture conductivity of the target layer. The study includes examples of stimulating the Menefee formation in the San Juan basin. Introduction The purpose of this paper is to analyze the overall behavior of a multilayer formation, paying special attention to the effect of the current productive zones on the production and stimulation of the bounded, middle layer. To evaluate the general lithologic sequences, it is necessary to properly define both the design goals and the design variables that affect the overall process. Because both production and stimulation are considered, concepts on hydraulic fracturing (i.e., elasticity theory, rheology, continuity, and fracture mechanics) and fluid flow (i.e, continuity, flow rules, and state equations) must be incorporated for the design goals to be fully coupled. Also, because the common element in both hydraulic fracturing and fluid flow theories is the sensitivity of the medium to stress, the incorporation of nonisotropic permeability tensors and stress maps is necessary to properly describe the system. The model considers a formation consisting of three layers, of which the top and bottom have been stimulated and producing for a period of time. After several years of production, the second (middle) layer is stimulated, and the entire system (three layers) produce to the wellbore. The proportion of propped target length among layers has been set to one (i.e., 750 feet [ft]) or two (i.e., 1,500 ft), and therefore in an X:1-2-2 sequence, the propped length for the first layer is 750 ft., whereas it is 1,500 ft. for the second and third layers, respectively. The impact of four different types of rocks are investigated as shown by Fig. 1. These impacts, along with the number of layers that compose the system, lead to the selection of only eight possible lithologic sequences, on the basis of the following restrictions:The first and third layer is never either "sandy shale" or shale. Two contiguous layers cannot share the same type of rock. Fig. 2 depicts the considered sequences. From the previously mentioned considerations, a methodology for the development of a fully coupled model is proposed, and the corresponding lithologic sequences are evaluated and optimized.
Abstract Although the effect of partial penetration of an infinite conductivity hydraulic fracture has been considered in a homogeneous reservoir, there is no study in similar problem in naturally fractured reservoirs. This paper presents the analysis of the solution to such problem in naturally fractured reservoirs. The method of analysis with or without type curve that enables us to evaluate the permeability in the three principal axes directions is also presented. The solution to the mathematical model was obtained in Laplace domain with elliptical flow model. Several type curves were generated to study the pressure behavior. Both the early linear and pseudo-radial flow regimes are observed. The duration of the early linear flow regime is a function of the natural fractures storativity ratio, interporosity flow coefficient and the dimensionless hydraulic fracture's height. The effect of the dimensionless hydraulic fracture's height on the duration of the linear flow becomes negligible as its dimensionless height approaches unity. Therefore there is no single unique value of a dimensionless time for the end of the linear flow regime as in the case of homogeneous reservoir. Raghavan et al (1978) determined the end of the linear flow regime in fully penetrating hydraulic fractures in homogeneous reservoir to be 0.016. This value is based on the dimensionless pressure drop only. In this study, this value was found to be 0.01 and it was evaluated with pressure derivative curve which is more accurate. Two simulated examples were used to validate the method of the analysis developed. The results obtained are in agreement with the input data. Introduction Hydraulic fracturing in the oil industry has contributed sizable reserves to the overall hydrocarbon reserves in the world. All the tight hydrocarbon reservoirs have to be fractured before they can be producible. These reservoirs are often produced with fully penetrating hydraulic fracture. A fully penetrating hydraulic fracture in a reservoir with water and hydrocarbon in contact will lead to an early or immediate water production. The only method of preventing unwanted fluid at the wellbore in a hydraulic fracture is to carry out partially penetrating hydraulic fracturing. Anderson and Stahl (1967) have shown by actual measurement that hydraulic fracture may not penetrate the entire formation thickness even when it is intended to do so. According to Tinsley et al (1969), the entire height of the hydraulic fracture may not be producing in addition to partial penetration. Moreover, not all the fractured height is propped open by propants. The unpropped height may be healed and close completely. Therefore micro seismic and production logging tools are necessary to determine the effective height of the fracture. Raghavan et al (1978) first presented the solution to a partially penetrating hydraulic fracture in a homogeneous reservoir. Their solution is based on the Green's function product solution technique presented by Gringarten and Ramey (1973). Several type curves for evaluation were presented without any example. Rodriguez et al (1984) presented type curve method of analysis for finite and infinite conductivity based on a numerical method for homogeneous isotropic system. They did not investigate the effect of vertical position on the wellbore pressure. The effect of the transition flow regime on the duration of the linear flow regime makes it necessary to study the behavior of transient flow in naturally fractured reservoirs. Moreover, the method employed by Raghavan and Rodriguez cannot be applied directly to naturally fractured reservoirs because of the transfer function. The problem has to be solved in Laplace domain before inversion to the real time domain. In this study, the elliptical flow model was applied to compute the dimensionless pressure of a partially penetrating hydraulic fracture at the wellbore. The effect of the vertical position of the fracture on the computed wellbore pressure was fully investigated.
Fractal techniques are used to create networks with fracture swarm geometry that resembles that of exploratory cores recently reported in the literature. The networks have desired total pore volume, maximum and minimum fracture spacing and fractional dimension. These properties together with fracture conductivity control their hydraulic behavior. Numerical simulation of individual fragments and the addition of production to obtain total production is shown to be consistent with simulations of the entire network when fracture conductivity is high. In this case, the network exhibits sub-linear flow (pressure derivative slope between 0.5 and 1). When fracture conductivity is low, it exhibits sub-radial flow (pressure derivative slope between 0 and 0.5) at early times with transition to sub-linear or boundary dominated flow (BDF) at later times. Longer duration of sub-radial flow is achieved by reducing fracture conductivity. These types of flow behavior cover the entire range seen in unconventional wells. They show how the power-law behavior, frequently observed in diagnostic plots, can be produced by the combined effect of matrix fragments that individually can only show linear, bi-linear or BDF flow. The relatively simple geometry of fracture swarms allows calculation of properties for sub-radial flow that complement those already known for sub-linear flow. New insights into production mechanisms of unconventional wells are discussed.
The very low matrix permeability of unconventional wells causes the pressure transient response to last a long time, typically years. This makes pressure transient analysis (PTA), that relies on analysis of shut-in periods, limited in its ability to characterize flow behavior. Rate transient analysis (RTA), on the other hand, is especially suited to deal with long flowing periods. But there have been two different problems with the application of RTA to unconventional wells. The first is that the theoretical framework for RTA is not as developed as that of PTA. The second problem is that RTA responses of unconventional wells do not exhibit the familiar flow regimes (bi-linear, linear and radial) but rather power-law behavior with log-log derivative slopes different from the expected values for those flow regimes. To tackle the first problem, we developed a new theoretical framework by rewriting and solving the diffusivity equation in terms of cumulative production (Acuna, 2017). This new solution for constant pressure complies with theoretical expectations with respect to the constant flow rate solution as shown in Appendix B. It also handles all flow regimes seen in unconventional wells including the familiar ones mentioned before. To address the second problem, we proposed the simple idea that the flow behavior of an unconventional well is the result of many matrix fragments of different size acting together (Acuna, 2018a b), a concept further developed in this paper.