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There is tremendous potential for shale oil reservoirs such as the Bakken formation, Eagle Ford and Niobrara to have a lasting impact on the U.S energy situation due to the multi-billion barrel resource base that these formations contain. Horizontal drilling and multi-stage hydraulic fracturing technologies have allowed significant oil to be produced; however, the primary recovery factors are still less than 10%, which means enhanced oil recovery methods needs to become the next big push in shale oil research. Miscible gas injection may become the most effective method in such lower permeability fields, because conventional water flooding may result in extremely lower injectivity. This work expands on previous research from Shoaib and Hoffman (2009) which focused on the Elm Coulee field in Eastern Montana and showed miscible gas injection may be a possible solution for shale oil reservoirs. The wells in their study had longitudinal hydraulic fractures, whereas today most wells have transverse fractures. The significance of this research is to evaluate the reservoir performance of the CO2 flooding with different hydraulic fracture orientations and recommends the best hydraulic fracture orientation which can maximize the oil production.
In this paper, separate simulation models with multiple transverse hydraulic fractures wells and longitudinal hydraulic fractures wells have been built based on a sector of the Elm Coulee field. Two different grid models (uniform grid models and local grid refinement (LGR) models) have been applied for the two types of hydraulic fracture for primary recovery and secondary recovery. Breakthrough time, total oil production, ultimate recovery factor and injection effectiveness for different cases have been determined and compared to find the best hydraulic fracture orientation in Elm Coulee field. Hydraulic fracture permeability sensitivity and bottom hole pressure (BHP) sensitivity analysis have also been made based on the LGR CO2 injection models.
Results show that both transverse and longitudinal fractures produce similar amounts of oil, but with transverse fractures, the CO2 breakthrough time is much earlier, and the CO2 production rate and cumulative production are much higher. Thus, the injection quantities are much greater for the transverse cases, and its overall injection efficiency is less.
This work forms the foundation to begin understanding how to best perform CO2 injection enhanced oil recovery (EOR) in Bakken shale oil reservoirs.
Summary Many stimulated shale‐gas wells experience surprisingly low fracturing‐fluid recoveries. Fracture closure, gravity segregation, proppant distribution, and shut‐in (soaking) time have been widely postulated to be the contributing factors. This study examines the effects of these factors on fracturing‐fluid distribution and subsequent well performance using flow and geomechanical simulations. In the end, two real‐field examples are used to validate the findings in this study. Geomechanical simulation is used to capture the complex post‐closure fracture geometry caused by nonuniform proppant distribution. The geometry is then passed into a series of 3D numerical flow models that are constructed using petrophysical parameters, fluid properties, and operational constraints representative of the Horn River shale‐gas reservoir. Within the flow simulation, the hydraulic fracture is represented explicitly in the computational domain by means of local‐grid refinement, and the physical process of fracture closure during shut‐in and production periods is modeled by adjusting the fracture volume and fracture conductivity dynamically. Non‐Darcy behavior caused by high gas velocity in the fracture and matrix desorption are considered. The results of the geomechanical simulation confirm the formation of a residual opening above the proppant pack in a partially propped fracture. The residual opening offers a highly conductive flow path for the gas, which is much more mobile than the water‐based fracturing fluid, and this difference in mobility further aggravates gravity segregation. Gravity segregation might lead to water accumulating near the bottom of a vertical planar fracture, but reduced fracture conductivity could limit the segregation and promote a more uniform fluid distribution. Water uptake into the matrix is influenced by forced and spontaneous imbibition caused by the large pressure differential across the matrix/fracture interface and matrix capillarity. Additional water is displaced into the matrix as pressure depletes and the fracture closes. Fracturing‐fluid‐penetration depth increases with shut‐in time, resulting in an enhancement in the initial gas rate, but lower late‐time production is also observed. Analysis of the residual opening of a partially propped fracture and its role in fracturing‐fluid distribution in three dimensions is novel. Field examples suggest that considering the various physical mechanisms investigated in this study could improve the accuracy of the numerical model for history matching and the reliability of the ensuing production forecasting. The findings in this study might provide a better understanding of fracturing‐fluid distribution, which is useful for optimizing production strategies and operations concerning hydraulically fractured shale‐gas reservoirs.
Profit, M. L. (Rockfield Global Technologies) | Dutko, M. (Rockfield Global Technologies) | Yu, J. (Rockfield Global Technologies) | Armstrong, J. (Rockfield Global Technologies) | Parfitt, D. (Rockfield Global Technologies) | Mutlu, U. (Rockfield Global Technologies America LLC)
This paper presents a number of emerging applications of hydraulic fracture initiation, propagation and interaction models. In the oil industry fracture design engineers often model hydraulic fracturing using 2D approximations but the physical process is inherently 3D and some very important aspects are lost during the model simplification, such as the means to impose a full 3D initial stress state and the capability of the fracture to propagate and potentially curve in an evolving complex stress state. A mode-1 3D hydraulic fracturing methodology is developed within an adaptive Finite Element Method (FEM) and Discrete Element Method (DEM) framework for generic fracture shapes. The fracture insertion process is based on a geometry update procedure rather than the more traditional DE approach of splitting elements along their edges or through the element itself. This leads to better control of the mesh quality and an improved performance of the numerical scheme. The applications include curving fracture paths and potentially connecting fractures from a multi-well stimulation stage.
Hydraulic fracturing is a complex engineering process (Economides and Nolte, 2000) and understanding its key aspects are essential to a fracking design engineer whose main goal is to obtain a designed fracture complexity in the target reservoir (Cipolla et al, 2010; Economides and Nolte, 2000). A number of the complexities are inherent to hydraulic fracturing; such as material heterogeneity, local variations in stress and inadequacies in knowing the precise location of potentially several pre-existing fracture sets (King, 2010). Within a numerical framework (such as adaptive Finite Element (FE) (Zienkiewicz et al, 2005; Belytschko et al, 2000) and Discrete Element (DE) (Munjiza, 2004) methods) each of these knowledge gaps can be explored and their role in hydraulic fracturing better understood. In this paper enhanced production refers to the increase in fracture complexity.
The first attempts at quantifying hydraulic fracture almost exclusively centered on analytical schemes which provide a way of understanding some simple relationships between key variables such as fluid pressures and fracture widths (Yew and Weng, 2015). This simplicity comes at the cost of ignoring some of the major complexities which are observed in many hydraulic fracture jobs.
Cui, Mingyue (Research Inst. of Expl./Devel.) | Shan, Wenwen (Langfang Branch of RIPED) | Jin, Liang (Shell E&P Asia Pacific) | Ding, Yansheng (Institute of mechanics, IMECH) | Ding, Yunhong (Langfang Branch of RIPED) | Chen, Li (Institute of mechanics, IMECH) | Liu, Ping (Langfang Branch of RIPED) | Xu, Zhihe (PetroChina Co. Ltd.)
Abstract Low permeability reservoirs take a large portion of the newly discovered hydrocarbon reservoirs. Stimulating low and ultra low permeability reservoirs faces more technical challenges. Unlike other stimulation techniques such as "well shooting", "nuclear explosion", and "high energy fracturing", the concept of in fracture explosion (IFE) is to create a fracture hydraulically, convey solid explosives deep into the fracture and place them in the fracture. Then ignite the explosives in the fracture to generate crushed zones or shear fractures near the main fracture while keeping the well bore intact. In such a way, the well productivity is increased. For complex tight gas reservoirs, especially those that tend to develop multi fractures and shear fractures by conventional hydraulic fracturing making the placement of proppant difficult, this technology has irreplaceable advantage. Fracturing fluid for in fracture explosion has two functions - to carry solid explosives while create hydraulic fractures, and to propagate ignition. This study has found such a fluid system that can meet both general requirements for hydraulic fracturing fluid and the realization of lighting, transmit fire, ignition, and propagate explosion under simulated reservoir conditions. The fluid system was tested successfully in a narrow fracture simulator. Expected explosion realized in this simulation. The simulated fracture has a length of 2300 mm with variable width of 0–50 mm. The process of squeezing, igniting, and explosion of 300g TNT equivalent was tested. This fluid system has the following properties: Rheology at reservoir temperature can be adjusted according specific requirement. Viscosity ranges from 10 to 50 mPa.s. Wall building leak off coefficient is 3.6x10–4 m/min0.5 and spurt loss is 0.25 ml/cm2. Combined with a regular fracturing fluid as a lead (pad), such properties allow the fluid to satisfy the requirements of generating deep fractures and transport/place explosives in the fractures. This paper will provide details of the study and discuss the potential applications for tight gas reservoir stimulation. Introduction Hydraulic fractures are usually simplified as ones with double-wing, symmetric geometry. Recent study of off-balance growth of fractures1–4 indicates that for some reservoirs, acid and hydraulic fractures have extremely complex shapes. For some of the difficult reservoirs, due to the characteristics of the formation and rock mechanic behavior, it is impossible to place proppant in the fractures generated hydraulically. Certain effort should be paid to optimize the treating fluids. Multiple Fracture Diagnostic and Its Effect on Optimum Design of Stimulation Fluids During real stimulation operations, it is very often to see high treating pressures. Factors that cause high fracturing pressures include:The creation of multiple fractures due to main fracture torture. Once multiple fractures (branch fractures) are created, the mechanism of fracture propagation will change. Fractures will no longer be perpendicular to minimum horizontal stress. The slippages on the branch fracture faces generate additional friction leading to higher fluid pressure to open the fractures. Multiple fractures can also be created by perforating a long section along the wellbore. Multiple fractures will be generated on the same direction. They are parallel to each other, competing against each other for the limited fracture width. Because each individual fracture is very narrow, the resistance to fluid flow becomes high, causing high treating pressure. Fracture tip effects. Several factors belong to this category:During fracture propagation, due to fluid leak off and the increase in proppant concentration caused by leak off, the effective viscosity of the fluid in the fracture increases shown as additional resistance; The rough surface of newly created fracture face causes turbulence;
Zheng, Shuang (The University of Texas at Austin) | Kumar, Ashish (The University of Texas at Austin) | Gala, Deepen P. (The University of Texas at Austin) | Shrivastava, Kaustubh (The University of Texas at Austin) | Sharma, Mukul M. (The University of Texas at Austin)
Abstract Simulating production from complex fracture networks is complicated due to different rates of closure of propped and unpropped fractures in a heterogenous time-varying stress field. Most of the existing models for simulating production from such hydraulic fractures do not consider geomechanics or use pressure as a proxy for changing the fracture conductivity. The closure of the unpropped fracture portion loses conductivity promptly, resulting in a fast decline rate in unconventional wells. However, most of the existing models are not capable of distinguishing the difference of propped and unpropped region in the fracture network. In this work, we developed a fully coupled, compositional, geomechanical fracturing and reservoir simulation model for simulating fracture propagation, proppant transport, proppant settling, flowback and fracture closure in complex fracture networks and applied this to field cases in the tight oil shale reservoirs. Our numerical model implicitly handles reservoir deformation and compositional multiphase fluid flow in rock matrix and propped/unpropped fractures. The simulation process consists of fracture creation during hydraulic fracturing and then modeling the shut-in and fracture closure followed by flowback over a period of several years. Total and effective stresses during production are calculated considering both pore pressure changes and mechanical opening of fractures. Closure of propped/unpropped fractures is modeled using an improved Barton-Bandis contact model. Previously published lab-measurements (Wu et al., 2017) for conductivity of propped and unpropped fractures as a function of effective stress are used as inputs for the closure model. The effects of proppant distribution, proppant size and different rates of fracture closure in propped and unpropped portions of the fracture are studied in using both planar fracture and complex fracture network. We show that the productivity of a fractured well is directly related to the proppant placement in the fractures. Achieving uniform proppant placement and reducing the proppant settling is beneficial in improving the fractured well productivity. This work will enable a better understanding of fracture closure during production, improving the accuracy of production forecasts and understanding inter-well interference.