Several recent studies have reported that proppant "bridging" (blocking) occurs at the interface between primary and secondary fractures. Such bridging blocks flow and significantly reduces the efficiency of proppant placement. The prevention of bridging is of great importance, but the criteria for bridging formation have yet to be determined. In this numerical study of proppant transport, we propose bridging formation criteria and analyze the associated distribution correlations that quantify the amount of proppant that migrates into the secondary fractures.
To model the complex interactions between proppant particles, fracturing fluids, and fracture walls, we use the discrete element method (DEM) coupled with computational fluid dynamics (CFD). We calibrate our model using widely accepted bed-load transport measurements. The simulation domain involves a "T-type" intersection of primary and secondary fractures. We investigate the effects of various proppant sizes and concentrations on bridging formation. In all cases, we investigate the occurrence of bridging and we quantify its impact by estimating the corresponding percentage of proppant reaching the secondary fractures.
Our simulation results show that the efficiency of proppant placement in the secondary fractures depends on the flow regime. In the suspension regime, proppant particles can be easily mobilized by the fluid drag force. This leads to a relative high proppant placement efficiency in the secondary fractures. When proppants are in the bed-load transport regime, kinetic energy transferred from the fluid drag force is dissipated by inter-particle collisions and the friction force. In this case, the amount of proppants entering the secondary fractures and the distance that proppants can cover are restricted compared to the case of proppants associated with suspension transport.
Our investigation reveals that two parameters are critical for the occurrence of proppant bridging (blocking) at the secondary fracture interface. These parameters are — the proppant concentration
Yin, Zhenyuan (National University of Singapore, Lloyds Register Global Technology Centre) | Moridis, George (Lawrence Berkeley National Laboratory, Texas A&M University) | Tan, Hoon Kiang (Lloyds Register Global Technology Centre) | Linga, Praveen (National University of Singapore)
Due to its increasing abundance, cleaner and lower emissions upon combustion, natural gas (NG) has been considered as the best transition fuel away from coal and oil to a carbon-constrained world. Methane gas is the major component in NG accounting for 70-90%, and is also the major constituent found in natural gas hydrates (NGHs). The amount of CH4 preserved in NGHs is vast and estimated to be 20,000 trillion cubic meter (TCM) worldwide. This outweighs the proved NG reserve on earth, which is 865.4 TCM, and doubles the combined reserve of all fossil fuels. Thus, NGHs have been considered as a potential future energy source. Extensive geological surveys and drilling programs have been carried out during the past two decades at various countries (Canada, USA, Japan, S. Korea, India, China, etc.) to identify the location of these NGH reservoirs, to quantify the amount of gas deposited and to recover hydrate cores to analyze their thermophysical and geomechanical properties. Extensive research have also been carried out in laboratories to synthesis gas hydrate mimicking marine and permafrost conditions, and to study their fundamental behavior of formation and dissociation. In this study, we numerically analyzed an experiment of methane hydrate bearing sediment (
O.M. Olorode and C.M. Freeman, Texas A&M University; G.J. Moridis, SPE, Lawrence Berkeley National Laboratory; and T.A. Blasingame, SPE, Texas A&M University Summary Various models featuring horizontal wells with multiple fractures have been proposed to characterize flow behavior over time in tight gas systems and shale-gas systems. Currently, little is known about the effects of nonideal fracture patterns and coupled primary-/secondary-fracture interactions on reservoir performance in unconventional gas reservoirs. We also developed a numerical simulator of gas flow through tight porous media, and used several Voronoi grids to assess the potential performance of such irregular fractures on gas production from unconventional gas reservoirs. Our simulations involved up to a half-million cells, and we considered production periods that are orders of magnitude longer than the expected productive life of wells and reservoirs. Our aim was to describe a wide range of flow regimes that can be observed in irregular fracture patterns, and to fully assess even nuances in flow behavior. We investigated coupled primary/secondary fractures, with multiple/vertical hydraulic fractures intersecting horizontal secondary "stress-release" fractures. We studied irregular fracture patterns to show the effect of fracture angularity and nonplanar fracture configurations on production. The results indicate that the presence of high-conductivity secondary fractures results in the highest increase in production, whereas, contrary to expectations, strictly planar and orthogonal fractures yield better production performance than nonplanar and nonorthogonal fractures with equivalent propped-fracture lengths.
Grover, Tarun (Petroleum Engineering Department, Texas A&M University College Station, Texas, USA) | Holditch, Stephen A. (Petroleum Engineering Department, Texas A&M University College Station, Texas, USA) | Moridis, George (Earth Sciences Department, Lawrence Berkeley National Laboraotry 1 Cyclotron Road, Berkeley, CA)
Blasingame, Thomas (Texas A&M University) | Olorode, Olufemi (Afren Resources) | Odunowo, Tioluwanimi Oluwagbemiga (Texas A&M University) | Moridis, George (Lawrence Berkeley National Laboratory) | Freeman, Craig Matthew (Texas A&M University)
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the Unconventional Resources Conference-USA held in The Woodlands, Texas, USA, 10-12 April 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Low to ultralow permeability formations require "special" treatments/stimulation to make them produce economical quantities of hydrocarbon and at the moment, multistage hydraulic fracturing (MSHF or MHF) is the most commonly used stimulation method for enhancing the exploitation of these reservoirs. Recently, the slot-drill (SD) completion technique was proposed as an alternative treatment method in such formations (Carter 2009).
The exploitation of unconventional reservoirs complements the practice of hydraulic fracturing, and with an ever-increasing demand in energy, this practice is set to experience significant growth in the coming years. Sophisticated analytic models are needed to accurately describe fluid flow in a hydraulic fracture, and the problem has been approached from different directions in the past 3 decades--starting with the work of Gringarten et al. (1974) for an infinite-conductivity case, followed by contributions from Cinco-Ley et al. (1978), Lee and Brockenbrough (1986), Ozkan and Raghavan (1991), and Blasingame and Poe (1993) for a finite-conductivity case. This topic remains an active area of research and, for the more-complicated physical scenarios such as multiple transverse fractures in ultratight reservoirs, answers are currently being sought.
Starting with the seminal work of Chang and Yortsos (1990), fractal theory has been successfully applied to pressure-transient testing, although with an emphasis on the effects of natural fractures in pressure/rate behavior. In this paper, we begin by performing a rigorous analytical and numerical study of the fractal diffusivity equation (FDE), and we show that it is more fundamental than the classic linear and radial diffusivity equations. Thus, we combine the FDE with the trilinear flow model (Lee and Brockenbrough 1986), culminating in a new semianalytic solution for flow in a finite-conductivity vertical fracture that we name the "fractal-fracture solution (FFS)." This new solution is instantaneous and comparable in accuracy with the Blasingame and Poe solution (1993). In addition, this is the first time that fractal theory is used in fluid flow in a porous medium to address a problem not related to reservoir heterogeneity. Ultimately, this project is a demonstration of the untapped potential of fractal theory; our approach is flexible, and we believe that the same methodology could be extended to different applications.
One objective of this work is to develop a fast and accurate semianalytical solution for flow in a single vertical fracture that fully penetrates a homogeneous infinite-acting reservoir. This would be the first time that fractal theory is used to study a problem that is not related to naturally fractured reservoirs or reservoir heterogeneity. In addition, as part of the development process, we revisit the fundamentals of fractals in reservoir engineering and show that the underlying FDE possesses some interesting qualities that have not yet been comprehensively addressed in the literature.
Coupled flow and geomechanics play an important role in the analysis of gas-hydrate reservoirs under production. The stiffness of the rock skeleton and the deformation of the reservoir, as well as porosity and permeability, are directly influenced by (and interrelated with) changes in pressure and temperature and in fluid- (water and gas) and solid- (hydrate and ice) phase saturations. Fluid and solid phases may coexist, which, coupled with steep temperature and pressure gradients, results in strong nonlinearities in the coupled flow and mechanics processes, making the description of system behavior in dissociating hydrate deposits exceptionally complicated.
In previous studies, the geological stability of hydrate-bearing sediments was investigated using one-way coupled analysis, in which the changes in fluid properties affect mechanics within the gas-hydrate reservoirs, but with no feedback from geomechanics to fluid flow. In this paper, we develop and test a rigorous two-way coupling between fluid flow and geomechanics, in which the solutions from mechanics are reflected in the solution of the flow problem through the adjustment of affected hydraulic properties. We employ the fixed-stress split method, which results in a convergent sequential implicit scheme.
In this study of several hydrate-reservoir cases, we find noticeable differences between the results from one- and two-way couplings. The nature of the elliptic boundary value problem of quasistatic mechanics results in instantaneous compaction or dilation over the domain through loading from reservoir-fluid production. This induces a pressure rise or drop at early times (low-pressure diffusion), and consequently changes the effective stress instantaneously, possibly causing geological instability. Additionally, the pressure and temperature regime affects the various phase saturations, the rock stiffness, porosity, and permeability, thus affecting the fluid-flow regime. These changes are not captured accurately by the simpler one-way coupling. The tightly coupled sequential approach we propose provides a rigorous, two-way coupling model that captures the interrelationship between geomechanical and flow properties and processes, accurately describes the system behavior, and can be readily applied to large-scale problems of hydrate behavior in geologic media.
Moridis, George (Lawrence Berkeley National Laboratory) | Collett, Timothy S. (U.S. Geological Survey) | Pooladi-Darvish, Mehran (University of Calgary) | Hancock, Steven H. (RPS Group) | Santamarina, Carlos (Georgia Institute of Technology) | Boswell, Ray (US Department of Energy) | Kneafsey, Timothy J. (Lawrence Berkeley National Laboratory) | Rutqvist, Jonny (Lawrence Berkeley National Laboratory) | Kowalsky, Michael B. (Lawrence Berkeley National Laboratory) | Reagan, Matthew T. (Lawrence Berkeley National Laboratory) | Sloan, E. Dendy (Colorado School of Mines) | Sum, Amadeu (Colorado School of Mines) | Koh, Carolyn (Colorado School of Mines)
The current paper complements the Moridis et al. (2009) review of the status of the effort toward commercial gas production from hydrates. We aim to describe the concept of the gas-hydrate (GH) petroleum system; to discuss advances, requirements, and suggested practices in GH prospecting and GH deposit characterization; and to review the associated technical, economic, and environmental challenges and uncertainties, which include the following: accurate assessment of producible fractions of the GH resource; development of methods for identifying suitable production targets; sampling of hydrate-bearing sediments (HBS) and sample analysis; analysis and interpretation of geophysical surveys of GH reservoirs; well-testing methods; interpretation of well-testing results; geomechanical and reservoir/well stability concerns; well design, operation, and installation; field operations and extending production beyond sand-dominated GH reservoirs; monitoring production and geomechanical stability; laboratory investigations; fundamental knowledge of hydrate behavior; the economics of commercial gas production from hydrates; and associated environmental concerns.
Many studies involving the application of geophysical methods in the field of gas hydrates have focused on determining rock-physics relationships for hydrate-bearing sediments, with the goal being to delineate the boundaries of gas-hydrate accumulations and to estimate the quantities of gas hydrate that such accumulations contain using remote-sensing techniques. However, the potential for using time-lapse geophysical methods to monitor the evolution of hydrate accumulations during production and, thus, to manage production has not been investigated. In this work, we begin to examine the feasibility of using time-lapse seismic methods--specifically, the vertical-seismic-profiling (VSP) method--for monitoring changes in hydrate accumulations that are predicted to occur during production of natural gas. A feasibility study of this nature is made possible through the coupled simulation of large-scale production in hydrate accumulations and time-lapse geophysical (seismic) surveys. We consider a hydrate accumulation in the Gulf of Mexico that may represent a promising target for production. Although the current study focuses on one seismic method (VSP), this approach can be extended easily to other geophysical methods, including other seismic methods (e.g., surface seismic or crosshole measurements) and electromagnetic surveys. In addition to examining the sensitivity of seismic attributes and parameters to the changing conditions in hydrate accumulations, our long-term goals in this work are to determine optimal sampling strategies (e.g., source frequency, time interval for data acquisition) and measurement configurations (e.g., source and receiver spacing for VSP), while taking into account uncertainties in rock-physics relationships. The numerical-modeling strategy demonstrated in this study may be used in the future to help design cost-effective geophysical surveys to track the evolution of hydrate properties. Here, we describe the modeling procedure and present some preliminary results.