The use of the bimodal production decline curve for the analysis of hydraulically fractured shale/tight gas reservoirs

The capability to conduct a rapid, near real-time model-based analysis of production data from tight/shale (TS) gas fields is important in determining fracture and matrix properties. Model-based analysis of production can range from simple analytical solutions to complex numerical models. The objective of this study is to develop a simple, Excel-based tool for the analysis of the complex problem of gas production from a fractured TS gas reservoir that is based on a robust model that is faithful to the underlying physics and can provide rapid estimates of the important system parameters. The scientifically robust model used as the basis for this tool is a significant modification and expansion of the bimodal production decline curve of Silin and Kneafsey (2012). The production period is divided into two regimes: an early-time regime before the extent of the stimulated reservoir volume (SRV) is felt, where an analytical similarity solution for gas production rate is obtained, and a late-time regime where the rate can be approximated with an exponential decline or more accurately represented with a numerical integration. Our basic model follows Silin and Kneafsey (2012) and produces the widely observed -½ slope on a log-log plot of early-time production decline curves, while our expanded model generalizes this slope to –n, where 0 < n < 1, to represent non-ideal flow geometries. The expanded model was programmed into an Excel spreadsheet to develop an interactive, user-friendly application for curve matching of well production data to the bimodal curve, from which matrix and fracture properties can be extracted. This tool allows significant insight into the model parameters that control the reservoir behavior and production: the geometry of the hydraulically-induced fracture network, its flow and transport properties, and the optimal operational parameters. This information enables informed choices about future operations, and is valuable in several different ways: (a) to estimate reserves and to predict future production, including expected ultimate recovery and the useful lifetime of the stage or the well; (b) if curve-matching is unsuccessful, to indicate the inadequacy of the mathematical model and the need for more complex numerical model to analyze the system; (c) to verify/validate numerical models, and to identify anomalous behavior or measurement errors in the data. The present approach can be adapted to gas-flow problems in dual-permeability media (hydraulically or naturally fractured) or highly heterogeneous sedimentary rock, as well as to retrograde condensation

Simulation of Gas Production from Multilayered Hydrate-Bearing Media with Fully Coupled Flow, Thermal, Chemical and Geomechanical Processes Using TOUGH+Millstone. Part 3: Production Simulation Results

The TOUGH+Millstone simulator has been developed for the analysis of coupled flow, thermal and geomechanical processes associated with the formation and/or dissociation of CH -hydrates in geological media. It is composed of two constituent codes: (a) a significantly enhanced version of the TOUGH+Hydrate simulator, v2.0, that accounts for all known flow, physical, thermodynamic and chemical processes associated with the evolution of hydrate-bearing systems and includes the most recent physical properties relationships, coupled seamlessly with (b) Millstone v1.0, a new code that addresses the conceptual, computational and mathematical shortcomings of earlier codes used to describe the geomechanical response of these systems. The capabilities of the TOUGH+Millstone code are demonstrated in the simulation and analysis of the system flow, thermal, and geomechanical behavior during gas production from a realistic complex offshore hydrate deposit. In the third paper of this series, we apply the simulators described in parts 1 and 2 to a problem of gas production from a complex, multilayered system of hydrate-bearing sediments in an oceanic environment. We perform flow simulations of constant-pressure production via a vertical well and compare those results to a coupled flow-geomechanical simulation of the same process. The results demonstrate the importance of fully coupled geomechanics when modeling the evolution of reservoir properties during production.

Simulation of Gas Production from Multilayered Hydrate-Bearing Media with Fully Coupled Flow, Thermal, Chemical and Geomechanical Processes Using TOUGH + Millstone. Part 1: Numerical Modeling of Hydrates

TOUGH + Millstone has been developed for the analysis of coupled flow, thermal and geomechanical processes associated with the formation and/or dissociation of CH4-hydrates in geological media. It is composed of two constituent codes: (a) a significantly enhanced version of the TOUGH + HYDRATE simulator, V2.0, that accounts for all known flow, physical, thermodynamic and chemical processes associated with the behavior of hydrate-bearing systems undergoing changes and includes the most recent advances in the description of the system properties, coupled seamlessly with (b) Millstone V1.0, a new code that addresses the conceptual, computational and mathematical shortcomings of earlier codes used to describe the geomechanical response of these systems. The capabilities of TOUGH + Millstone are demonstrated in the simulation and analysis of the system flow, thermal and geomechanical behavior during gas production from a realistic complex offshore hydrate deposit. In the first paper of this series, we discuss the physics underlying the T + H hydrate simulator, the constitutive relationships describing the physical, chemical (equilibrium and kinetic) and thermal processes, the states of the CH + H O system and the sources of critically important data, as well as the mathematical approaches used for the development of the of mass and energy balance equations and their solution. Additionally, we provide verification examples of the hydrate code against numerical results from the simulation of laboratory and field experiments. 4

System response to gas production from a heterogeneous hydrate accumulation at the UBGH2-6 site of the Ulleung basin in the Korean East Sea

We investigate the feasibility of production from a layered marine gas hydrate reservoir using the properties and conditions corresponding to the UBGH2-6 site of the Ulleung Basin in the Korean East Sea. The work expands and furthers previous investigations in support of a proposed field test. The target system is location in deep water and consists of 13 m of alternating hydrate-bearing sand and soft mud layers and will be produced using a vertical well. We assess production potential during a 14-day field test, examine sensitivity to heterogeneity in permeability, porosity, and initial hydrate saturation, and assess the geomechanical response of the system to short-term production. Producing gas from the system appears to be technically feasible, however, low production rates and relatively large water production rates are expected during the field test. Expected subsidence and reservoir compaction is limited given the current data and the short timeframes of the production test

Evaluation of alternative horizontal well designs for gas production from hydrate deposits in the Shenhu area, South China Sea

Gas hydrate deposits were confirmed in the Shenhu Area, the north slope of South China Sea during a drilling expedition in 2007. Hydrate deposits in the area are distributed in disseminated forms in forams-rich clay sediments with permeable overburden and underburden layers. Production of gas from such a type of hydrate deposits is very challenging. In this study, we develop a numerical approach for investigation of gas production strategies by horizontal wells and preliminary estimation of the production potential based on the limited data that are currently available. Numerical models are built to represent the typical hydrate deposits in the area, including the thickness of the Hydrate-Bearing Layer (HBL), hydrate saturation, water depth, temperature at the sea floor, initial thermal gradient and pressure distribution. The models are used to simulate the different production schemes and well designs. In this paper, production strategies of horizontal well system with combination of depressurization and thermal stimulation are investigated through numerical models. Gas production potential from the deposits and effectiveness of the different production methods are evaluated. The simulation results indicate that with current technology, gas production from Shenhu hydrate deposits may not be economically efficient for all the production strategies we have investigated. Copyright 2010, Society of Petroleum Engineers

The use of the bimodal production decline curve for the analysis of hydraulically fractured shale/tight gas reservoirs

The capability to conduct a rapid, near real-time model-based analysis of production data from tight/shale (TS) gas fields is important in determining fracture and matrix properties. Model-based analysis of production can range from simple analytical solutions to complex numerical models. The objective of this study is to develop a simple, Excel-based tool for the analysis of the complex problem of gas production from a fractured TS gas reservoir that is based on a robust model that is faithful to the underlying physics and can provide rapid estimates of the important system parameters. The scientifically robust model used as the basis for this tool is a significant modification and expansion of the bimodal production decline curve of Silin and Kneafsey (2012). The production period is divided into two regimes: an early-time regime before the extent of the stimulated reservoir volume (SRV) is felt, where an analytical similarity solution for gas production rate is obtained, and a late-time regime where the rate can be approximated with an exponential decline or more accurately represented with a numerical integration. Our basic model follows Silin and Kneafsey (2012) and produces the widely observed -½ slope on a log-log plot of early-time production decline curves, while our expanded model generalizes this slope to –n, where 0 < n < 1, to represent non-ideal flow geometries. The expanded model was programmed into an Excel spreadsheet to develop an interactive, user-friendly application for curve matching of well production data to the bimodal curve, from which matrix and fracture properties can be extracted. This tool allows significant insight into the model parameters that control the reservoir behavior and production: the geometry of the hydraulically-induced fracture network, its flow and transport properties, and the optimal operational parameters. This information enables informed choices about future operations, and is valuable in several different ways: (a) to estimate reserves and to predict future production, including expected ultimate recovery and the useful lifetime of the stage or the well; (b) if curve-matching is unsuccessful, to indicate the inadequacy of the mathematical model and the need for more complex numerical model to analyze the system; (c) to verify/validate numerical models, and to identify anomalous behavior or measurement errors in the data. The present approach can be adapted to gas-flow problems in dual-permeability media (hydraulically or naturally fractured) or highly heterogeneous sedimentary rock, as well as to retrograde condensation