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Abstract This study expands the high-resolution visualization of the drainage around horizontal wells using a newly developed analytical streamline simulator. A first case of single synthetic fractured well highlights the stagnation points occurring between the frac clusters, where drainage is ineffectively slow. A second synthetic case of two parallel wellbores with multiple fracture hits may enlarge the stagnant zones, with negligible drainage, occurring between the frac clusters. Finally, our flow tracking method is used to history match the total production with fracture allocated production for a multi-stage fracked well in the Wolfcamp formation, Midland basin. Progressive drainage of the SRV is visualized using the actual production data. The recovery factor after 5 years is 4% but rapidly slows and reaches only 6% after 40 years. When natural and/or hydraulically induced micro-fractures are assumed absent, only the near-frac regions in the SRV are drained even for tight frac spacing. Pressure near those fracs is rapidly lost and the productivity index of unconventional wells remains very low. Unrecovered oil remains trapped in so-called dead zonesoccurring in the matrix domains of extremely slow flow between the principal frac zones. Our simulation suggests that refracs between the original frac clusters can tap the oil in the dead zones after the first few years of production and may increase recovery factors and thus improve well economics. This conclusion is contingent on the assumption that the matrix domain between the fracs remains unfractured, When the matrix is micro-fractured, deeper domains would be drained (future work), leaving only residual, un-recovered hydrocarbons entrapped in the matrix blocks engulfed by the microfractures. Introduction Contrary to the main trend of solving reservoir flows using numerical solvers for discrete elements, our reservoir modeling method is based on linear differential equations and closed-form solutions (Weijermars et al. 2017, Part 1, URTeC 2670073A). A major advantage of solutions based on the analytical description is infinite resolution due to the closed-form algorithms used. Reservoir drainage area, drained volume (using time-of-flight contours for successive fluid batches to reach the frac zones) and pressure fields can all be accurately visualized with our new method. The analytical results perfectly match those of the commercial, numerical simulator augmented with a streamline tracing algorithm (Part 1, URTeC 2670073A). The continuous solution allows us to visualize the flow around individual fractures in greater detail and with accuracy limited only by the uncertainty in input parameters and not by any grid sizing.
Weijermars, Ruud (Texas A&M University) | van Harmelen, Arnaud (Texas A&M University) | Zuo, Lihua (Texas A&M University) | Nascentes, Ibere Alves (Texas A&M University) | Yu, Wei (Texas A&M University)
Abstract The reservoir drainage around horizontal wells is visualized at high-resolution using a newly developed analytical streamline simulator based on complex potentials. Drainage contours show the progressive oil recovery from the stimulated rock volume (SRV). The method plots streamlines, the time-of-flight for fluid to fracs, velocity contours and pressure distribution around fracked wells. Independent simulations with a commercial reservoir simulator confirm the visualizations with complex potentials are accurate, and that the latter method gives high-resolution images of the pressure and flow field around individual fracs. We show the depth of investigation reflected by pressure contour gradients is a poor indicator of drained reservoir volume. Drainage contours based on particle velocity tracking give a much clearer view of the actual region drained by a well via its fracs. First, matrix drainage by 2-frac and 3-frac clusters is studied in detail. Flow separation surfaces between 2 clustered fracs (with equal length and flux) are always straight, creating planes of symmetry between adjacent drainage regions. Clusters of 3 fracs develop curved flow separation surfaces, convex toward the inner frac. For frac spacing less than 4 times total frac length, drainage of the central region of the 3-frac clusters slows down due to flow interference, which confirms earlier findings that production gains become insignificant above certain frac length/spacing ratios. Next, the analysis shows the flow field, drainage contours, velocity contours and pressure distribution for a horizontal, synthetic well with 11 transversal, kinked fractures. The basic analysis in this paper (URTeC 2670073A, Part 1 of our study) is expanded in a companion paper (URTeC 2670073B, Part 2 of our study), which applies the methodology of flow visualization using drainage and velocity contours to a sample well from the Midland Basin, Texas. Introduction Unconventional hydrocarbon resource development currently still suffers from ineffectively low recovery values of the hydrocarbons in place. More than 90% of oil and up to 80–65% of natural gas remains trapped in the formation. With recovery factors so low, the life cycle of unconventional reservoirs can be easily doubled or tripled if we find ways to break through the limitations of current field development approaches. An increase in the recovery factor per well and enhancement of the field life of shale plays can be achieved if the fracture treatment is optimized. Engineering the optimum frac spacing that minimizes cost and optimizes production output is a key aspect of unconventional resource development strategy (Cipolla and Wallace, 2014; Lalehrokh and Bouma, 2014). Simulation of the drainage by hydraulic fractures shows production growth becomes insignificant after frac spacing is reduced beyond a certain minimum (Fig. 1a; Yu, 2015). Declining productivity per frac in fact is due to increased flow interference between fracs.
The PDF file of this paper is in Russian.
The paper describes the features of using the methodology for calculating the specific drainage volumes for estimating the initial gas in place and the formation water volumes invading the formation for gas condensate reservoirs. It is shown that the application of thespecific drainage volumes method is a simple tool in the engineer'shands, allowing to do analysis of the variable drainagevolumes for wells with a minimal set of initial data. The method of specific dynamic volumes allow to determine them foreach producing well and to obtain an integral curve of the drainage gas-saturated volume of the resrvoir and determine the necessary time to drain the entire hydrodynamicallyconnecte gas-saturated volume of the deposit. The knowledge of time when the entire gas-saturated volume of the deposit is envolved in drainage is a necessary basis to justify the application of the material balance methods to calculategas in place volumes. The deviation of the integral curve of the gas-saturated drainage volume from its maximum value makes it possible to assess the water invading volumesin the reservoir in time, taking into account the processes of deformation of the reservoir and the drop out of condensate. Estimation of the gas-saturated pore volume and its reduction in time due to formation water encroachmentfrom the method of specific drainage volumes application allows to reduce the limits of uncertainty for original gas in place volumes(OGIP) and the aquifer parametersin the process of geological-hydrodynamic model history matching.
Hydraulic fracturing has been used extensively over the past fifteen years to stimulate low permeability oil and gas wells. A considerable permeability oil and gas wells. A considerable amount of fractured well performance theory has accumulated during this period. Transient drawdown solutions for vertically fractured liquid wells based on numerical simulation were published in 1964. These solutions established the influence of vertical fractures on transient pressure buildup and drawdown testing. Others have investigated well tests of vertically fractured gas wells using both analytical and numerical models. Recent studies have provided new information for type-curve matching of pressure data obtained from fractured (vertical and horizontal) wells. The objective of this paper is to illustrate the application of numerical simulation in evaluation of fracture stimulation of gas wells. The previously published interpretation methods, such as pressure buildup and drawdown analyses and type-curve pressure buildup and drawdown analyses and type-curve matching, form an extremely important part of the complete analysis. Better and more comprehensive well test interpretation can often be obtained by using the so-called conventional methods and numerical modeling together.
Prats, et.al., originally developed analytical solutions for the performance of vertically fractured reservoirs for the compressible fluid case. They considered both the constant terminal pressure and constant terminal rate cases. In the case of constant rate, however, the early-time pressure transient solutions were not investigated. In 1964, Russell and Truitt published transient pressure solutions for vertically-fractured oil or water wells based on numerical simulation. From their solutions they developed methods of analyzing pressure buildup and drawdown tests with conventional plotting techniques. Clark later applied the Russell-Truitt results in analysis of water-injection well falloff data. Analytical solutions and example applications for vertically fractured wells which produce slightly compressible fluids also were presented by van Everdingen and Meyer.
More recently Gringarten, et.al., have reviewed the work of previous authors and published new solutions especially useful for published new solutions especially useful for type-curve analysis. They illustrated the use of their results (for wells with either vertical or horizontal fractures) in a companion papers.
Abstract Performance prediction of wells producing from tight microdarcy formations is a daunting task. Complexities of geology (the presence/absence of naturally occurring fractures and contribution from different lithological layers), completion and fracture geometry complexities (multiple transverse and/or longitudinal fractures in long horizontal boreholes), and two-phase flow are impediments to simple performance forecasting. We demonstrate the use of various analytical and numerical tools to learn about both short- and long-term reservoir behaviors. These tools include (a) traditional decline-curve analysis (Arps formulation), (b) Valko's stretched-exponential method, (c) Ilk et al's power-law exponential method, (d) rate-transient and transient-PI analyses to ascertain the stimulated- reservoir volume, and (e) numerical simulation studies to gain insights into observed flow regimes. The benefits of collective use of analytical modeling tools in history-matching and forecasting both short- and long-term production performance of tight-oil reservoirs are demonstrated with the use of real and simulated data. Diagnosing natural fractures, quantifying stimulated-reservoir volume, and assessing reliability of future performance predictions, all became feasible by using an ensemble of analytical tools.