Dual-porosity Reservoir Simulation Research Articles

Modeling of Matrix/Fracture Transfer with Nonuniform-Block Distributions in Low-Permeability Fractured Reservoirs

Summary Unconventional shale–gas and tight oil reservoirs are commonly naturally fractured, and developing these kinds of reservoirs requires stimulation by means of hydraulic fracturing to create conductive fluid–flow paths through open–fracture networks for practical exploitation. The presence of the multiscale–fracture network, including hydraulic fractures, stimulated and nonstimulated natural fractures, and microfractures, increases the complexity of the reservoir simulation. The matrix–block sizes are not uniform and can vary in a very wide range, from several tens of centimeters to meters. In such a reservoir, the matrix provides most of the pore volume for storage but makes only a small contribution to the global flow; the fracture supplies the flow, but with negligible contributions to reservoir porosity. The hydrocarbon is mainly produced from matrix/fracture interaction. So, it is essential to accurately model the matrix/fracture transfers with a reservoir simulator. For the fluid–flow simulation in shale–gas and tight oil reservoirs, dual–porosity models are widely used. In a commonly used dual–porosity–reservoir simulator, fractures are homogenized from a discrete–fracture network, and a shape factor based on the homogenized–matrix–block size is applied to model the matrix/fracture transfer. Even for the embedded discrete–fracture model (EDFM), the matrix/fracture interaction is also commonly modeled using the dual–porosity concept with a constant shape factor (or matrix/fracture transmissibility). However, in real cases, the discrete–fracture networks are very complex and nonuniformly distributed. It is difficult to determine an equivalent shape factor to compute matrix/fracture transfer in a multiple–block system. So, a dual–porosity approach might not be accurate for the simulation of shale-gas and tight oil reservoirs because of the presence of complex multiscale–fracture networks. In this paper, we study the multiple–interacting–continua (MINC) method for flow modeling in fractured reservoirs. MINC is commonly considered as an improvement of the dual–porosity model. However, a standard MINC approach, using transmissibilities derived from the MINC proximity function, cannot always correctly handle the matrix/fracture transfers when the matrix–block sizes are not uniformly distributed. To overcome this insufficiency, some new approaches for the MINC subdivision and the transmissibility computations are presented in this paper. Several examples are presented to show that using the new approaches significantly improves the dual–porosity model and the standard MINC method for nonuniform–block–size distributions.

Fractured Reservoir Simulation: a Challenging and Rewarding Issue

The recent years have seen a growing awareness of the role played by fractures in petroleum reservoirs production and recovery. Hence, much effort was devoted to the diagnosis of fracture presence and impact on production. However, turning that diagnosis into field development decisions goes through reservoir simulation. This paper addresses some of the specificities of fractured reservoirs that make that their simulation is both challenging and rewarding. Indeed, the integration of fractures into a flow simulation model is not straightforward because of the existing gap between the geological fault/fracture network and the fingerprint of that network on often-complex recovery mechanisms. Considering that fractures may impede or enhance production, fractured reservoir simulation may be seen as a technical challenge with potentially-high reward. This paper underlines that specific framework as an introduction to two technical articles dedicated to dual-porosity reservoir simulation. Although it constitutes another major aspect of any fractured reservoir study, the geological characterization of fractures is not discussed herein, but only evoked because of more and more integration of static and dynamic aspects.

Upscaling Fracture Networks for Simulation of Horizontal Wells Using a Dual-Porosity Reservoir Simulator

Summary One difficulty in fracture upscaling for field-scale dual-porosity reservoir simulation is the determination of equivalent gridblock fracture permeability, which depends on the type of boundary conditions imposed on the discrete-fracture-network (DFN) simulation. Actually, classical upscaling procedures usually are based on linearly varying pressure boundary conditions, which cannot capture the near-well flow behavior. As a result, the well productivity calculated by a dual-porosity flow simulator can be very different from that calculated on a DFN model. This paper proposes a near-well fracture-upscaling procedure based on the geological DFN model to improve the accuracy of well productivity in fractured-reservoir simulators. This procedure enables us to represent the actual flow through the fractures and the exchanges between matrix and fractures in the well vicinity. On the basis of the computed near-well flow pattern, equivalent fracture transmissibilities as well as numerical well indices are determined and assigned to the gridblocks of the dual-porosity reservoir simulator. The reliability and necessity of using the near-well upscaling procedure are demonstrated by examples. Introduction Advanced characterization methodologies are now able to provide realistic models of geological fracture networks (Cacas et al. 2001). In addition, production logging and transient well tests can be simulated with DFN models to validate the geological fracture-network geometry and calibrate the hydraulic properties of fractures (Sarda et al. 2002). However, because of computational limitations, the complex geological DFN model cannot be used straightforwardly to simulate a multiphase-flow production scenario at field scale (Bourbiaux et al. 2002). For such simulations, a dual-porosity reservoir simulator is typically used. The dual-porosity reservoir model, using large gridblocks to discretize the whole reservoir, is a conceptual representation of the actual geology of the fractured medium. The flow properties of the fracture network are then homogenized on gridblocks through upscaling procedures. The upscaling of fracture properties is the problem of translating the geological and hydraulic description of fracture networks into reservoir-simulation parameters. The dual-porosity model requires the determination of equivalent fracture permeability and equivalent matrix-block dimensions or shape factors (Bourbiaux et al. 1997; Sarda et al. 1997). This paper discusses methodologies for upscaling the permeability of a fracture network, especially in the vicinity of the well. Upscaling of fracture permeability has been studied extensively. The commonly used method is numerical, based on flow simulation on a model of the actual fracture network with specific boundary conditions to compute an equivalent gridblock permeability (Sarda et al. 1997). Other methods were also developed; for example, Oda (1985) proposed an analytical equation to calculate the fracture-permeability tensor, and Lough et al. (1997) presented an approach using the boundary-element method, which integrates the contribution of matrix in the equivalent permeability of the fractured medium. When using a numerical approach to determine the equivalent permeability of a fracture network, the upscaled result depends on the type of boundary conditions imposed in the flow simulation. Actually, classical upscaling procedures are usually based on flow simulation in a parallelepipedic model with linear-type pressure boundary conditions, which cannot capture the near-well flow behavior. As a result, the well productivity calculated by a dual-porosity flow simulator can be very different from that calculated on a near-wellbore DFN model.

Waterflood and CO2 Flood of the Fractured Midale Field (includes associated paper 22947 )

Summary The considerable remaining oil target in the naturally fractured Midale field prompted a major reservoir and recovery mechanism study in the mid-1980's. Included in the study were the detailed evaluation of 20+ years of waterflood history and the implementation and analysis of a tertiary miscible CO2-flood pilot. The study showed that tertiary miscible flooding should not necessarily be precluded for naturally fractured reservoirs. Introduction The 500-million-bbl Midale oil field is part of a trend of large Mississippian oil accumulations located in southeastern Saskatchewan along the northern margin of the Williston basin. The field was discovered in 1953 and developed on 80-acre spacing. In 1962, Midale was unitized for waterflooding, with eighty-three 320-acre inverted nine-spot patterns (Fig. 1). The reservoir section in Midale consists of a heavily fractured vuggy limestone overlain by a less fractured chalky dolomite. Waterflood performance is dominated by these oriented vertical fractures, which typically are spaced 1 to 4 ft apart. Production wells located "on-trend" from injectors(aligned with the fractures) showed sharp early response to waterflood. In contrast, response of "off-trend" producers was smooth and delayed. Oil produced to date represents recovery of 20% of the original oil in place(OOIP); ultimate waterflood recovery is predicted to be only 24% OOIP. The current water cut in the mature operation is about 80% (Fig. 2). Although the reservoir is fractured, well productivities are modest, with average production rates of 75 to 100 STB/D-well. Typical EOR screening criteria suggest that naturally fractured reservoirs are poor candidates for miscible CO2 flooding. Despite this rule of thumb, the favorable reservoir geology combined with the substantial EOR target at Midale persuaded the field owners to study implementation of CO2-flood technology. A 4.4-acre tertiary miscible CO2-flood pilot was conducted during 1984–89. Field-scale waterflood and pilot-scale CO2-flood results were history matched with a dual-porosity reservoir simulator. Field-scale CO2-flood recoveries are predicted to be an incremental 20% OOIP. The high CO2-flood recovery results from the favorable interaction of the different layers within the reservoir. The bulk of the large tertiary target is trapped in the chalky dolomites in the upper reservoir section. Although most of the CO2 is injected into the underlying heavily fractured limestones, gravity forces cause the CO2 to rise and come in contact with the oil in the dolomites. Based on pilot results and simulation studies, a $40-million commercial-scale CO2 flood began in Feb. 1992 in 10% of the unit. Geology The 4,600-ft-deep, gently dipping productive carbonates are overlain and underlain by impervious anhydrite beds.1The productive interval typically consists of a limestone (the Vuggy) overlain by a dolomite (the Marly), as shown in the type log in Fig. 3. The Marly zone has a layered geometry with good lateral continuity between wells. The Vuggy is less layered and more laterally discontinuous. The average gross thicknesses for the Vuggy and Marly zones are 40 and 30 ft, respectively; reservoir development is 20 ft in the Vuggy and 10 ft in the Marly. The reservoir is quite consistent in total thickness, varying from 60 to 80 ft across the majority of the unit. Internally, however, the Vuggy/Marly thickness ratio does vary considerably. The Vuggy zone contains two distinct rock types, intershoal and shoal. The intershoal Vuggy is present over the entire unit, while shoals have limited areal extent. Indeed, the majority of the unit is devoid of shoal Vuggy. However, where shoal Vuggy does exist, it dominates performance because of its high permeability. Intershoal Vuggy consists primarily of peloidal and bioclastic packstones containing mostly interparticle porosity. The shoal Vuggy consists of peloidal grainstones that display visually dramatic vugular and interparticle porosity. Despite these large pores, porosity values in the shoal and intershoal are very similar, ranging from 10% to 15%. Typical intershoal permeabilities are 1 to 10 md, with shoal permeabilities an order of magnitude higher. The Marly zone consists primarily of dolomitic wackestones and mudstones, with the mudstones forming the best reservoir rock. Porosity, which ranges from 20% to 35%, is predominantly intercrystalline with secondary amounts of pinpoint vuggy porosity. Marly permeability ranges from 1 to 10 md.

Tight-Sand Development Potential in the Southern Rulison Area, Garfield County, Colorado

Summary Reservoir characterization and simulation of natural gas production were used to assess the production potential for an extension area within the Piceance Creek basin (Garfield County, CO). Many of the basin's reservoirs are lenticular sands characterized as having low porosities, low permeabilities, and relatively high water saturations. One such horizon is the Mesaverde group, which consists of discontinuous sandstone lenses distributed within a shale matrix and is present throughout the Piceance Creek basin. Prior studies of the commercial Rulison field in the east-central portion of the basin indicated that compressional forces created an anticlinal nose aligned northwest/southeast through part of the field. These forces created a conductive natural fracture system that enhances the permeability of the Mesaverde. This paper shows a relationship between Rulison field and an area south of Rulison that encompasses about 36 sq miles [93.2 km]. The area has been sparsely drilled (averaging one well per two sections and nonuniformly spaced); thus, the possibility exists for further commercial development through infill drilling. The southern Rulison area is characterized in structure, percent sand, and critical reservoir parameters including permeability. Production rates, cumulative gas production, and drilling and completion data are used to infer permeabilities by history matching with a dual-porosity reservoir simulator. Results include a reservoir description of the area and economic evaluations of several investment scenarios that will help to assess the potential resource. Introduction The Piceance Creek basin of northwest Colorado contains an estimated 33 Tcf [934 × 10–9 m3] of maximum recoverable gas and is the setting for the U.S. DOE's Multiwell Experiment (MWX). The Natl. Petroleum Council estimated the volume of recoverable gas at 12.9 Tcf [365 × 10–9 m3), assuming a gas price of $2.50/Mcf [$8.83/100 M], a 15% discounted cash flow rate of return, and the current level of technology. The basin comprises Garfield, Mesa, and Rio Blanco counties with minor extension into Delta, Gunnison, and Moffat counties. The Tertiary Age Wasatch formation and Cretaceous are Mesaverde group are typically the gas-productive horizons throughout the basin. Situated near the center of the basin in Garfield County is the Rulison field. Discovery of the field and its early development occurred in the late 1950's and early 1960's, with sparse drilling in the southern sections of Township 6 South, Range 94 West (T6S, R94W) and scattered drilling throughout T7S, R94W and T7S, R95W. Wasatch completions have generally been restricted to T6S, R94W with development on 160 acres/well [65 ha/well]. The Mesaverde has been drilled on 320 acres/well [130 ha/well] and is the focus of this study. Most of these wells penetrated the entire lenticular section of the Mesaverde (Williams Fork), with a few deeper wells reaching the marginal marine deposits in the lowermost Mesaverde. Northwest Exploration (now part of the Williams Co.) further developed the area during the early 1980's. Thirteen Mesaverde wells were completed in T6S, R94W. For this investigation, T6S, R94W will be referred to as the Rulison field and T7S, R94W and T7S, R95W as the southern area. The geology and natural gas production of the study area were evaluated to determine why the southern area had not been developed to the extent of the Rulison field. The Rulison field has been well characterized; therefore, the present effort concentrates on the southern area. In appraising the southern area as a developmental prospect, similarities to the Rulison field are identified and quan-tified. Fig. 1 is a generalized map of the study area, the two townships of interest are southwest of Rifle, just south of the Colorado River.

Case Study of Gas Migration in the Wasatch and Mesaverde Formations of the Piceance Basin, Colorado

Summary The U.S. DOE Morgantown Energy Technology Center (METC) conducted a reservoir simulation study and an engineering analysis on gas migration for two tight lenticular sandstone units, the Wasatch formation and the Mesaverde group, in Garfield County, CO. The study quantified potential gas loss through migration from the Naval Oil Shale Reserve (NOSR) No. 3 (Fig. 1) to nearby producing wells located in the Rulison field and forecasted production for proposed NOSR No. 3 offset wells located at previously selected sites, offsetting commercial wells outside the reserve. After the reservoirs were characterized, production was forecasted by use of a reservoir simulator to history match actual production. A dual-porosity reservoir simulator, developed specifically for naturally fractured gas-producing reservoirs, and reservoir engineering calculations were used in the study. The study followed two extensive DOE field testing programs, a nearby multiwell experiment (MWX), and a special Mesaverde test well (1XM9) drilled in NOSR No. 3 (see Figs. 1 and 2). These DOE field tests provided geologic information and values for reservoir parameters that control production from this unconventional gas resource. In addition to the results from the two field experiments, the study used a detailed geologic analysis and production data from nearby industry wells to characterize the producing formations.