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Abstract Ansai field is a typical field with low permeability, low pressure, low production and the water flooding is inefficient. In order to explore an effective developing method for increasing the production and ultimate recovery, we carried out the feasibility studies of natural gas flooding. This paper analyses the feasibility of natural gas flooding from the geological condition of Ansai field at first, then introduces the high pressure slim tube tests for determining MMP of injection gas and reservoir oil and prediction of MMP with published correlation. The high precision correlation has been selected for predicting the composition of injection gas in miscible displacement. The performance of natural gas flooding have been simulated using MVIP simulator. The results shows that Ansai field shares the geologic conditions for natural gas flooding. The MMP of lean gas and Ansai reservoir oil is above 32MPa, and the average reservoir pressure is only 8.81 MPa in Ansai field, so the lean gas flooding is immiscible displacement at Ansai reservoir condition. If accomplishing a miscible displacement at the same condition, the composition of injected gas must be changed by increasing rich gas content, the content is 80%C2H6. The results of numerical computations shows that the recovery ratio of natural gas flooding (26.3%OOIP) is more than of water flooding (20.6%OOIP).Obviously, the natural gas flooding is a hopeful EOR method in Ansai field. These studies provides scientific evidence for the policy of natural gas flooding in Ansai field. P. 371
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Brassey Field (0.99)
- Asia > China > Shaanxi > Ansai Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- (2 more...)
Abstract The paper describes a novel approach to model unstable fluid displacements in porous media. The approach is based on the Karhunen-Loeve (K-L) decomposition which is able to predict the fluid distributions of miscible displacements inside a porous medium. Several first-contact miscible displacement experiments, each with different fluid properties, were conducted, and the fluid distributions inside the porous media were mapped at various times using nuclear magnetic resonance imaging (NMRI). The K-L decomposition is described to identify the coherent spatial structures from spatio-temporal patterns arising from these experiments. It was found that these complex spatiotemporal behavior can be successfully described by few dominant eigen functions. The technique is based on the diagonalization of the covariance or two-point correlation matrix. The K-L decomposition provides information for the successful prediction of Enhanced Oil Recovery (EOR) processes. P. 341
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.68)
Abstract Designing gas injection projects in naturally fractured reservoirs requires special considerations which, in turn, relies on knowledge of the fracture network. Characterization of the fracture network involves delineation of important physical characteristics, such as fracture spacing, fracture orientation, fracture conductivity (of both natural and hydraulically induced fractures). Of equal significance is understanding the transfer mechanisms between oil and gas in the rock matrix and injected water and gas present in the fracture network. Integration of fracture characterization with results obtained during experimental investigation of transfer mechanisms is a key step for history matching and predicting reservoir response to water or gas injection. This paper describes the steps taken in two important areas of 1) fracture characterization and 2) fluid exchange from fracture to matrix as a precursor for design of a 10 acre CO2 pilot in the naturally fractured Spraberry Trend Area. Fracture and matrix characterization are based on oriented vertical and horizontal core taken from Upper Spraberry reservoirs. Fluid exchange mechanisms are investigated in reservoir plugs and whole core at reservoir temperatures and pressures. Results of imbibition/wettability and CO2 gravity drainage experiments are presented. History matching Spraberry waterflood performance and predicting performance. under CO2 injection is presented based on integration of reservoir characterization and laboratory experimentation. P. 325
- North America > United States > Texas > Midland County (1.00)
- North America > United States > Texas > Martin County (1.00)
- North America > United States > Texas > Howard County (1.00)
- North America > United States > Texas > Dawson County (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.31)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract Simulation of multiphase flow in porous media requires knowledge of relative permeability functions. A commonly used unsteady-state method of estimating relative permeability is based on interpreting flow data collected from laboratory displacement experiments. In this paper, refinements are outlined, for improving the accuracy of estimated relative permeability pararmeters by accounting for thermal effects for produced fluids, utilizing pre breakthrough differential pressure data in cases where capillary forces are neglected, elimination of convergence problems in history-matching algorithms, and improving the reliability of injected phase relative permeability estimates. For the gravimetric method of collecting displacement data, the existing procedure of calculating production volumes is improved to account for thermal expansion of fluids in collection vessels, both for imbibition and drainage displacement. The parameter estimation technique is used to determine relative permeability. A semi-analytical procedure, based on the JBN method, utilizes pre-breakthrough differential pressure data, in cases when capillary forces are neglected. This is especially important for low permeability samples, where post-breakthrough production data could be limited. Otherwise, capillary and gravitational forces are accounted for using a finite- difference method. The history matching procedure requires minimizing the objective function, which is a measure of the deviation between simulated and experimental data. The simulated annealing method is used to avoid possible convergence of the minimization routine to a local, rather than the global minimum of the objective function. Interpretation of relative permeability of the injected fluid from displacement experiments is shown to be less precise than for the displaced fluid. The theoretical analysis rationalizes acquisition of more data during early phases of a displacement experiment. Optimization features discussed in this paper are incorporated in a new, relative permeability simulator. P. 77
Abstract The analytical description of oil displacement by water in porous media is a complex problem of interest in secondary oil recovery by waterflooding. Due to its complexity, most of the studies in this area are restricted to one-dimensional cases. In this paper, the radial two-dimensional case is treated. For the experimental work, a transparent porous cell built with two ground circular glass plates was used. This cell has the advantage of allowing direct visualization of the movement of fluids. Based on the experimental results, a theoretical model was developed to explain the radial displacement of oil by water in a porous medium. The theory considers that:water tends to follow preferential paths where the motion is essentially longitudinal and of the convective type; at the same time, there is a lateral motion of dispersive type which tends to widen the preferential paths. Introduction Oil displacement by water within porous media is a very complex process that has been studied by reservoir engineers for more than fifty years. The complexity of the process is due to the simultaneous action of several factors, primarily viscous forces, capillary forces and pore volume geometry. For describing this process, some simple theoretical models have been proposed. Frequently, these models do not represent in a reasonable way the reservoir behavior. Recently, immiscible displacement of oil by water within a porous medium has had a renewed interest at some research centers. For the study of this flow problem, besides conventional techniques, some non-conventional such as X- and gamma-ray tomography and nuclear magnetic resonance have been used. Because of its transparency, that allows direct visualization of fluid movement, the use of two-dimensional transparent cells has been of particular interest. The purpose of this paper is to describe a new two-dimensional transparent porous cell, which has proved to be a versatile research tool. Based upon experimental results obtained with this cell, a theoretical model that explains in a reasonable way the mechanics of oil displacement by water through porous media is proposed. Experimental Work Experimental work was carried out with a two-dimensional porous cell. This cell is constructed with two glass plates. One of the faces of each plate is roughened by using an appropriate abrasive. Upon placing one roughened surface against the other, we obtain a two-dimensional porous medium whose matrix has a random distribution of pores. Fig. 1 shows the components of a circular cell, with an inlet port at the center of the cell. The operation of the cell is as follows: when the porous space is occupied by air, the cell is translucent, but when it is saturated with oil it becomes transparent, because the refraction indices of the glass and of the oil used in the experiments are similar. However, when water is injected to displace oil, the invaded area becomes translucent because water has a refraction index smaller than that of glass. In this way, the water front can be followed in detail. The experiments of this paper were carried out with circular, square and hexagonal cells. The circular cell has 20 cm (7.9 in) in diameter. The glass plates, 0.6 cm (0.24 in) thick, were treated with an abrasive that yielded 0.01 cm (0.0049 in) pores. The inlet port consists of a stainless steel tube of 0.05cm (0.020 in) of interior diameter. To carry out the displacements runs, the cell was saturated completely with heavy oil of 100 cp (0.1 Pa.s) viscosity; then it was placed on the arrangement shown on Fig. 2. Afterwards, water was injected at the center of the cell, at a constant rate of 0.23 cm3/min (0.014 in3/min). Fingering effects appeared immediately. P. 115
Abstract In this paper we present the results obtained from a cross-well seismic tomography experiment carried out in an oil producing field of the West Permian Basin, Texas, U.S.A. Three fundamental stages can be identified from the tomographic method: Field data acquisition, data conditioning, and the actual tomographic process including forward modeling and inversion. For our case, we present a synopsis of each. The resulting Vp and Vs tomograms show a dear separation of high and low velocity zones that are in agreement with sonic logs. From the final tomograms, we computed images of Vp/Vs ratio, Poisson ratio, porosity and density using well known empirical formulas. Introduction Tomography is a term applied to particular processes developed to image some physical properties of an object under study. The technique known as seismic travel time tomography using cross-well data has been used recenfly to obtain the seismic velocity and attenuation distribution of the plane space between wells or boreholes. Amongst the advantages the tomographic method, its capability for generating higher resolution images than the ones produced from surface seismics stands out. This enhanced power of resolution has proven to be effective for detailed structural representation of the subsurface, monitoring the advance of injection fluids, and reservoir characterization (Bregman et al.; Harris et al.; Justice et al.) The results attained from the experiment provide an idea of the potential usefulness of the tomographic method as an alternative for in-field exploration and detailed characterization of hydrocarbon producing reservoirs. In this paper we aim to describe the field data acquisition, pre-proces sing and tom ographic inversion methods that we used to image the compressional and shear wave velocities (Vp and Vs) of the medium. From these results we present the reconstructed images of Vp/Vs ratio, Poisson ratio, porosity and density of the plane space between two oil producing wells. P. 61^
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract This paper presents results of petrophysical whole core analyses carried out in highly permeable dolomite cores, intensively vugular and fractured. The estimated parameters were: multi-directional permeability tests kH and kV, matrix mab and fracture porosity fb, the high velocity flow coefficient, relative permeabilities to oil and water, the effective oil permeability (as a function of effective stress), capillary functions, and the variation of absolute permeability with temperature. The temperature and effective hydrostatic stress used ranged up to 150 C and 20 000 psi, respectively. Several sleeve materials were tested, finding that silicon withstood successfully the test conditions. Stainless steel was used for the flow screens needed for the horizontal permeability measurements. The fluids used in these tests were nitrogen, helium, and brine. As an example of the values estimated for some of these parameters, the ratios for horizontal to vertical permeabilities at an standard effective stress of 400 psi were kh0 /kV=117, kh90 /kV=19, and kh0 /kh90 =6.87. The ratio of matrix to fracture porosities mab/ fb=9.15 and for the compressibilities cfb/cmab=5.56. Finally, specific values of matrix porosity and multidirectional permeabilities for an increment of the effective stress conditions from 1000 to 8000 psi, resulted in a decrease of 23% for the total porosity, 61% for the horizontal kh0 permeability and 78% for vertical permeability. A new correlation for the high-velocity coefficient is presented for conditions of these highly macro vugular formations, which approximately is parallel 1.6 log cycles above the Firoozabadi and Katz correlation. Introduction Currently reservoir characterization plays a very important role in the reservoir management projects, aimed at optimizing the exploitation of a reservoir. Petrophysical studies are a very important part of the characterization effort, and are especially advantageous when complex reservoirs, such as vuggy and fractured carbonates, are to be developed. The main purpose of core analysis is to obtain data representative of in-situ formation properties. Coring technology has advanced significantly in recent years in order to achieve the goal of optimal development. The petroleum industry has been during the last years evaluating and producing fractured and vuggy reservoirs with increasing frequency. This increase is caused with increasing frequency. This increase is caused partly by the necessity to explore in continuously poorer quality reservoirs with time, and also by an increase awareness of the existance and the effect of fractures in subsurface formations. This is especially true when dealing with secondary and tertiary recovery projects in these systems. P. 71^
- North America > Mexico (0.68)
- North America > United States > Texas (0.46)
- North America > United States > California (0.28)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Abkatun-Pol-Chuc Field (0.99)
- North America > United States > New Mexico > San Juan Basin > Media Field (0.93)
Abstract The definitive work on fracture relative permeability was performed by E.S. Romm in 1966. His research concluded that relative permeability is a linear function of saturation. Since that time very few attempts have been made to calculate relative permeability in fractures. This paper presents the results of an independent experimental investigation to test the validity of Romm's results. The research was conducted with the same kerosene and water systems in a parallel glass plate fracture applying modern day techniques. The technique of video- imaging was used for measuring saturations in the fracture. Relative permeability ratios were computed using Welge's interpretation of the Buckley-Levrett theory after fractional flow was obtained from the displacement. Results indicated that relative permeability is not a linear function of saturation as was shown in the past. Introduction Fluid flow in fractured geologic formations is of interest to petroleum engineers, to geologists in groundwater movement and to environmental engineers in assessing movement of hazardous wastes into ground water. In the petroleum industry, hydrocarbon from fractured reservoirs represents a significant portion of the oil and gas produced in the United States each year. With the recent widespread use of horizontal wells to drain naturally fractured reservoirs, a basic understanding of fluid flow in fractures has become a necessity Relative permeability data is critical in predicting the flow-rate of one phase in the presence of another. P. 333^
- North America > United States > Colorado (0.30)
- Europe > Norway > Norwegian Sea (0.24)
Abstract A numerical approach was developed for the dynamic simulation of fracture rocks and wave propagation. Based on some ideas of "percolation theory and fractal growth", a network of particles and springs represent the rock model. To simulate an inhomogeneous medium, the particles and springs have random distributed elastic parameters and are implemented in the dynamic Navier equation. Some of the springs snap with criteria based on the confined stress applied, therefore creating a fractured rock consistent with the physical environment. The basic purpose of this research was to provide a method to construct a fractured rock with confined stress conditions as well as the wave propagation imposed in the model. Such models provide a better understanding of the behavior of wave propagation in fractured media. The synthetic seismic data obtained henceforth, can be used as a tool to develop methods for characterizing fractured rocks by means of geophysical inference. Introduction The elastodynamic problem of cracked rocks has been studied extensively by several authors, either theoretically or numerically. However, our understanding of many physical phenomena is limited due to the lack of a proper theoretical representation of a fractured rock. Generally, it is applied some approximation in order to have a treatable theory (including the difficulty of treating nonlinear phenomena). It has been proved, for example, that a crack velocity propagation cannot exceed the Rayleigh wave velocity of the medium. This has been confirmed experimentally as well as theoretically, e.g. by Griffith's model. Meaning these theories have some universal features. The model is based on a network of particles or nodes connected to springs or bonds. A uniform triangular network is used in the initial configuration, having a relative Poisson ratio of about 0.25. The elastic parameters are implemented by using the dynamic Navier equation. The fractures appear in the model by breaking the springs that surpass (either by contraction or by expansion of the spring) some threshold criteria. P. 597^