Although organic-rich shale formations are being extensively produced in many places in the United States, the unexpected early production decline is still not fully understood. This phenomenon could have many physical or operational reasons. One of the physical attributes is the time-dependent characteristics of the shale mineral assemblage when interacting with the fracturing fluid. Creep deformation is one of those time-dependent characteristics through which rocks exhibit continuous deformation under constant load that affects reservoir completion and hydraulic fracture stimulation. In this study, shale creep deformation was characterized and rheological models were developed. Triaxial creep experiments were conducted on rock samples from the Eagle Ford shale from southern Texas. Samples were tested with water, decane, or without any circulating fluid to assess fluid-shale interaction. Eagle Ford shale mineral compositions were also investigated using X-Ray Diffraction analyses in an attempt to correlate minerals fluid sensitivity. Problems such as loss of fracture width and length due to shale viscoelastic behavior while embedding the proppant can be better understood if the magnitude of shale creep is well characterized. The experimentally calibrated viscoelastic model not only addressed the instantaneous, transient, and long term sample deformations, but also enabled the estimation of proppant embedment depth during production. The creep deformation was most pronounced when the shale was impregnated with water. Decane-impregnated samples produced less creep deformation and the least creep was measured on the dry ones. The theory of linear viscoelasticity was used to model the samples timedependent deformation when subjected to their respective constant loads.
Summary Optimal spacing between fracture clusters has eluded reservoir and completions engineers since the inception of multistage hydraulic fracturing. Very small fracture spacing could result in fracture to fracture (intrawell) interference and a higher completion cost, whereas very large fracture spacing could lead to inefficient hydrocarbon recovery, which is detrimental to the well economics. Meramec Formation has moved to full-field development, and multiple wells are put on production in a relatively short time. Depending on the desired economic metric, net present value (NPV), or rate of return (ROR), the magnitude of intrawell interference can be optimized by adjusting fracture spacing. For instance, if the objective is to maximize ROR, then tighter fracture spacing can be accepted. Furthermore, petroleum economics are often ignored in simulation studies, particularly the concepts of time value of money and oil-price sensitivity. This has led to a knowledge gap in identifying optimal drawdown procedure and fracture spacing from numerical models. This study proposes a framework that integrates petroleum economics with simulation results to optimize a horizontal well from the Meramec Formation. On the basis of this framework, we identified optimal drawdown procedure and fracture spacing. Then, oil-pricing sensitivity analysis was conducted to illustrate the effect of oil-price volatility on design parameters. Moreover, this study investigates the relative contribution of reservoir and completions characteristics with regard to short- and long-term well performance. These characteristics include drawdown management, fracture spacing, pressure-dependent permeability, critical gas saturation, and petrophysical properties. Available geologic data were integrated to construct a geologic model that is used to history match a well from the Meramec Formation. The geologic model covers an area of 640 acres that encompasses a multistage hydraulically fractured horizontal well. The well is unique because it is unbounded and has more than 2 years of continuous production without being disturbed by offset operations. Findings suggest that the drawdown strategy (aggressive vs. conservative) has more effect on short-term oil productivity than fracture spacing. Drawdown strategy even has more of an effect on short-term oil recovery than does a 20% error in porosity, or water saturation. Furthermore, the profile of the producing-gas/oil ratio (GOR) depends on completions efficiency, and it has been interpreted using linear-flow theory.
In development of the Bakken/Three Forks play, it is crucial to obtain a strong understanding of not just the hydraulic fracture geometry, but also what portion of those hydraulic fractures are conductive. If both parameters and their interactions are not fully understood, then development of the play could be severely compromised due to unoptimized well spacing and completion design. This study represents a two-pronged approach to better understand this interaction. The first step was to perform a Sealed Wellbore Pressure Monitoring (SWPM) test to gain an understanding of hydraulic half-length (Haustveit. et al. 2020). Then, a conductive interference test was performed to utilize Chow Pressure Group (CPG) to understand the conductive half-length (Chu et al. 2018). This paper will address the results from these two tests and how they can be coupled together to optimize the unique relationship between well spacing and completion design to maximize the value in development of the Bakken/Three Forks play or any play both new and mature. The SWPM test was successfully completed on a nine well zipper frac operation consisting of two pads (four well pad/five well pad) where four Middle Bakken and five Three Forks wells were stimulated. The SWPM results provided insight into the hydraulic fracture geometry of the stimulation in multiple scenarios of vertical and lateral separation, as well as various amounts of offsetting depletion. The next step in the analysis was performing a CPG interference test on the five well zipper pad. The CPG results provided insight into not just the initial conductive geometry, but a three month follow up test also showed how the conductivity of the fractures rapidly degrade over time. By coupling the SWPM and CPG analysis together, an operator can learn where hydraulic fractures are growing and what portion of those fractures are conductive. This project design of coupled SWPM and CPG provided multiple learnings: Hydraulic fractures for a well in either the Middle Bakken or Three Forks grow through the Lower Bakken Shale and create large geometries in both the landing and staggered zone Hydraulic growth is faster and geometry larger growing towards modern completion parents versus vintage completion parents A relatively small portion of the hydraulic geometry is conductive, and although early time wells communicate through the Lower Bakken Shale, a 3-month interference test shows closure between the Three Forks and Middle Bakken. From these learnings, an optimized development is being developed for the Bakken/Three Forks play and a similar workflow can be applied to any play both new or mature to maximize value and returns for operators.
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