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Abstract Characterization of hydraulic fracture system in multi-fractured horizontal wells (MFHW) is one of the key steps in well spacing optimization of tight and shale reservoirs. Different methods have been proposed in the industry including core-through, micro-seismic, off-set pressure data monitoring during hydraulic fracturing, pressure depletion mapping, rate-transient analysis, pressure-transient analysis, and pressure interference test. Pressure interference test for a production and monitoring well pair includes flowing the production well at a stable rate while keeping the monitoring well shut-in and recording its pressure. In this study, the coupled flow of gas in hydraulic fractures and matrix systems during pressure interference test is modeled using an analytical method. The model is based on Laplace transform combined with pseudo-pressure and pseudo-time. The model is validated against numerical simulation to make sure the inter-well communication test is reasonably represented. Two key parameters were introduced and calculated with time using the analytical model including pressure drawdown ratio and pressure decline ratio. The model is applied to two field cases from Montney formation. In this case, two wells in the gas condensate region of Montney were selected for a pressure interference test. The monitoring well was equipped with downhole gauges. As the producing well was opened for production, the bottom-hole pressure of the monitoring well started declining at much lower rate than the production well. The pressure decline rate in the monitoring well eventually approached that of the producing well after days of production. This whole process was modeled using the analytical model of this study by adjusting the conductivity of the communicating fractures between the well pairs. This study provides a practical analytical tool for quantitative analysis of the interference test in MFHWs. This model can be integrated with other tools for improved characterization of hydraulic fracture systems in tight and shale reservoirs.
Summary Decline curve analysis (DCA) has been the mainstay in unconventional reservoir evaluation. Because of the extremely low matrix permeability, each well is evaluated economically for ultimate recovery as if it were its own reservoir. Classification and normalization of well potential is difficult because of ever-changing stimulation total contact area and a hyperbolic curve fit parameter that is disconnected from any traditional reservoir characterization descriptor. A new discrete fracture model approach allows direct modeling of inflow performance in terms of fracture geometry, drainage volume shape, and matrix permeability. Running such a model with variable geometrical input to match the data in lieu of standard regression techniques allows extraction of a meaningful parameter set for reservoir characterization, an expected outcome from all conventional well testing. Because the entirety of unconventional well operation is in transient mode, the discrete fractured well solution to the diffusivity equation is used to model temporal well performance. The analytical solution to the diffusivity equation for a line source or a 2D fracture operating under constrained bottomhole pressure consists of a sum of terms, each with exponential damping with time. Each of these terms has a relationship with the constant rate, semisteady-state solution for inflow, although the well is not operated with constant rate, nor will this flow regime ever be realized. The new model is compared with known literature models, and sensitivity analyses are presented for variable geometry to illustrate the depiction of different time regimes naturally falling out of the unified diffusivity equation solution for discrete fractures. We demonstrate that apparent hyperbolic character transitioning to exponential decline can be modeled directly with this new methodology without the need to define any crossover point. The mathematical solution to the physical problem captures the rate transient functionality and any and all transitions. Each exponential term in the model is related to the various possible interferences that may develop, each occurring at a different time, thus yielding geometrical information about the drainage pattern or development of fracture interference within the context of ultralow matrix permeability. Previous results analyzed by traditional DCA can be reinterpreted with this model to yield an alternate set of descriptors. The approach can be used to characterize the efficacy of evolving stimulation practices in terms of geometry within the same field and thus contribute to the current type curve analyses subject to binning. It enables the possibility of intermixing of vertical and horizontal well performance information as simply gathering systems of different geometry operating in the same reservoir. The new method will assist in reservoir characterization and evaluation of evolving stimulation technologies in the same field and allow classification of new type curves.
The industry spends significant amount of time and money to optimize completion designs to develop various unconventional resource plays, including cluster spacing or fracture spacing. It is strongly believed that better reservoir characterization and better modeling technique selection ought to shorten the learning curve and save money. This article reviews the state-of-the-art on fracture spacing optimization and discusses the challenges that the industry is facing to achieve an optimal cluster spacing decision. The current technology to develop unconventional resource plays is a horizontal well with multistage hydraulic fracturing treatments. Since permeability is extremely low ( 0.001 md) in unconventional resource reservoirs, multiple fractures are needed to have economic well rates, as shown in the image on top (Figure 1).
Horizontal wells in liquids-rich shale plays are now being drilled such that lateral and vertical distances between adjacent wells are significantly reduced. In multistacked reservoirs, fracture height and orientation from geomechanical effects coupled with natural fractures create additional complications; therefore, predicting well performance using numerical simulation becomes challenging. This paper describes numerical-simulation results from a three-well pad in a stacked liquids-rich reservoir (containing gas condensates) to understand the interaction between wells and production behavior. The reservoir simulator used for this study was designed to handle unstructured-grid-based simulation cases. Most of the numerical reservoir simulators that are used for modeling horizontal wells with multiple hydraulic fractures are based on structured grid cells in which the hydraulic fractures are modeled as symmetric biwing fractures perpendicular to the wellbore.
Waste injection in shale, with matrix permeability in the nanodarcy range and without the presence of any permeable layers, has been performed on the Norwegian Continental Shelf (NCS) for more than 15 years. To avoid leakages to the seafloor using this method, techniques have been developed that allow wells to dispose of several million barrels into individual shale domains, with vertical propagation of the disposal domain less than 1,000 ft above the injection point. Recently, use of frequent 4D interpretations of seismic surveys shot over a permanent sensor array allowed detailed domain mapping and independent dynamic monitoring. Changes of North Sea regulations in the mid- to late 1990s made the seabed disposal of oily cuttings and other waste from drilling and production impossible without the use of significant topside cleaning systems. Meanwhile, the development of fields required increasingly complex wells, resulting in the almost systematic use of oil-based mud for efficient drilling.
An operator has faced a number of challenges producing heavy oil (8000–20 000 cp) from the Khuff and Kahmah carbonate reservoirs at the Mukhaizna field since their discovery in 2010. The large, low-productivity reservoirs have few analogs in the world, so the operator established new approaches to bring these reserves to market. This paper covers the staged field-development methodology, including analysis and evaluation of various development concepts, that enabled the company to optimize both completion design and artificial-lift selection, reducing downtime and lowering operating costs by nearly 50%. The Mukhaizna field, located in the eastern part of central Oman, was discovered in 1975 by Petroleum Development of Oman. The Kahmah Group consists of shelf carbonate deposits of Cretaceous age, whereas the Khuff formation is of Permian age, with a major unconformity between the lower Kahmah and Khuff formations.
Summary This study focuses on the development of an analytical model to predict the long-term productivity of channel-fractured shale gas/oil wells. The accuracy was verified by comparing productivity calculated by the proposed model with numerical results. Sensitivity analysis was conducted to analyze significant parameters on the performance of channel fracturing. Field application of the model was conducted using production data obtained from an Eagle Ford Formation dry gas well, which was completed using channel fracturing. The procedure for estimating reservoir and stimulation parameters from production data was provided. The results indicated that the equivalent fracture width obtained from our model is consistent with the inversion of cubic law. Comparison with numerical simulations demonstrated that the proposed model might under- or overestimate well productivity, with mean absolute percentage error (MAPE) values of less than 8%. Sensitivity analysis indicated that, with the increase of fracture width, fracture half-length, and matrix permeability, the productivity of channel-fractured wells increases disproportionately. In addition, well productivity will increase as the ratio of the pillar radius to the length of channel fracture decreases, provided that the proppant pillars are stable and the fracture width is held constant. Under the conditions of smaller fracture width and larger matrix permeability, the effect of using channel fracturing to increase well productivity is more significant. However, as the fracture width becomes large, the benefits of channel fracturing will diminish. The case study indicated that the shale gas productivity estimated by the proposed model matches well with field data, with MAPE and R of 12.90% and 0.93, respectively. The proposed model provides a basis for optimizing the design of channel fracturing.
In this study, we conduct two-dimensional hydraulic fracture (HF) simulations using Finite-Discrete Element Method (FDEM) in naturally fractured media with different matrix permeability and natural fracture density. Natural fractures (NFs) and fluid flow through the porous matrix and fractures are explicitly modeled in this framework through a fully coupled hydromechanical formulation. The stress redistribution due to the presence of discrete fracture network (DFN) and the complex pattern of HF propagation path due to HF/NF interactions are captured in these numerical simulations. For validation, the results of two-dimensional and hydromechanical FDEM simulations are compared to laboratory experiments and analytical solutions for hydraulic fracture initiation and propagation from a notch on a pressurized cavity in an impermeable and homogeneous medium under an anisotropic stress condition. Results of simulations reveal the significant role of NF pattern and permeability of the rock matrix on its response to HF stimulation. Hydraulic treatment of a medium with denser DFN activates more NFs and will more likely create flow channeling through some of the surrounding NFs. Size of the wet stimulated reservoir area depends on the permeability of the rock matrix, but the size of dry stimulated reservoir area is independent of the permeability.
Hydraulic fracturing technology has brought us a lot of economic and societal benefits because it makes the extraction of oil, gas, and heat from low permeability rocks possible. However, the accurate design of efficient well treatment operations to create sustainable stimulated reservoir volume (SRV) is not possible yet. Commonly used simplified models (linear elastic fracture mechanics integrated with lubrication theory) cannot predict the behavior of natural reservoirs because those models are developed for linear, elastic, homogeneous, isotropic intact rocks filled with Newtonian fluids. Natural rocks are Discontinuous, Inhomogeneous, Anisotropic, and Non-Elastic (DIANE) materials (Harrison and Hudson, 2000). In addition, they are porous and permeable, thus a complex set of poro-mechanical properties influence their behavior. Hydraulic fracturing, therefore, involves multiple interacting phases (rock blocks, granular materials, and fluids), and the behavior vary drastically depending on the involved scales, in-situ state of stress, host fluid properties, treatment parameters (e.g., viscosity and flow rate), poromechanical properties of the rock matrix, morphology, size, spacing, pattern, mineralization of the natural fractures (NF), and their relative orientation with respect to the wellbore and present-day principal stresses (Blanton, 1982; Warpinski and Teufel, 1987; Gale, et al., 2014; Raterman, et al., 2018; Daneshy, 2019).
VonGonten, W. D. (W.D. VonGonten and Co.) | Woods, Terry (W.D. VonGonten and Co.) | Yang, Yi-Kun (W.D. VonGonten and Co.) | Picha, Tim (W.D. VonGonten and Co.) | Lindsay, Garrett (W.D. VonGonten and Co.) | Ali, Safdar (W.D. VonGonten and Co.)
Production history matching data is an important step in any study that seeks to optimize unconventional completions and well development criteria. Understanding the reservoir mechanisms during production allows for better optimization of the hydraulic fracture system. Generating a model that fits historical data can be easy but honoring the true petrophysics and fluid dynamics of the reservoir is often challenging. Some of the major challenges during reservoir simulation are uncertainties in water saturation, permeability, phase behavior, and effective fracture surface area during production. This paper discusses how fit-for-purpose core measurements help reduce the uncertainty in these parameters, ultimately requiring a multiple porosity reservoir simulation model to account for these improved measurements and understandings.
Industry accepted core analysis techniques under-estimate reservoir water saturation due to loss of water from evaporation and core handling techniques (preservation, crushing, time). Proper evaluation of the void space will be shown and how this is better calibrated to field data. A review of how steady-state liquid permeability testing provides better estimates for reservoir permeability and deliverability in shale reservoirs will be discussed. Coupling these measurements with imbibition effects from hydraulic fracturing fluids and lab studies showing oil-wet and water-wet pore systems acting independently of each other, a slightly "outside of the box" reservoir simulation model was needed to mimic these physics.
The proposed reservoir simulation methodology consists of multiple porosities and was developed to incorporate near-wellbore hydraulic fracture effects that are observed during lab testing. Combining this methodology with other lab measurements and a fully three-dimensional (3D) hydraulic fracture model, the number of "knobs" that need to be turned to get a good history match are reduced.
Two examples will be presented in this paper showing how the proposed model better honors the physics of lab measurements and provides the user more flexibility during reservoir simulation, especially when buildup data is available. Reducing the uncertainty in these parameters has provided a workflow that helps minimize the multiple non-unique realizations during the history match process and provides a more reliable model for the engineer while reducing the amount of time needed to obtain a match.
Economic production from shale oil reservoirs relies on the longevity of conductive fractures. Choke or drawdown management is believed to better preserve the fracture conductivity during the early life of the wells, which thus potentially leads to a higher ultimate oil recovery. However, there is no strong consensus among the previous literature as to whether choke management can offer the incremental oil recovery in the long-term. Even if it can, the mechanism is not well understood, and the economic benefit can be challenged, because the choke management slows down the early oil production, which is worth the most in terms of Net Present Value (NPV).
In this study, a series of coupled flow-geomechanical numerical simulations is performed to examine the effect of choke management on the ultimate oil recovery and NPV. We built multiple reservoir realization models, each of which is validated based on the same field production data from Middle Bakken shale-oil reservoirs to perform probabilistic production forecasts. The different reservoir realization models are built to assess the uncertainty in the Stimulated Reservoir Volume parameters, including natural fracture spacing, water saturation in the matrix and fracture, and formation compressibility. The different reservoir parameters lead to each model having different primary recovery driving mechanisms of oil recovery, including imbibition and compaction drive. In each simulation run, stress-dependent permeability phenomena during fracturing and flowback are modeled to more closely simulate proppant crushing and embedment. Our model carefully simulates the matrix, natural, and hydraulic fractures separately, because each of these media demonstrates different stress sensitiveness.
This study quantitatively demonstrates that the choke management seems to increase both the ultimate oil recovery and NPV if the oil recovery is strongly driven by imbibition. A mechanistic discussion for this claim is presented. We have also shown that this claim can straighten out the mixed conclusions among some previous papers. As a result, this study proposes the evaluation of the dominant driving mechanism of shale-oil recovery for the optimum design of the choke management. Moreover, this study also attempts to propose the optimum ramping-down rate of the choke. For example, if the reservoir demonstrates a strong imbibition, the optimum choking rate is between 500 and 100 psi/day. Meanwhile, if the reservoir demonstrates a weaker imbibition, the optimum choking rate is between 50 and 10 psi/day. These optimum range is shown to be consistent, regardless of the objectives, whether to optimize the ultimate oil recovery or NPV.