Showing papers in "Spe Reservoir Evaluation & Engineering in 1998"

How Permeability Depends on Stress and Pore Pressure in Coalbeds: A New Model

Abstract: In naturally fractured formations, such as coal, permeability is sensitive to changes in stress or pore pressure (i.e., effective stress). This paper presents a new theoretical model for calculating pore volume compressibility and permeability in coals as a function of effective stress and matrix shrinkage, using a single equation. The equation is appropriate for uniaxial strain conditions, as expected in a reservoir. The model predicts how permeability changes as pressure is decreased (i.e., drawdown). Pore volume compressibility is derived in this theory from fundamental reservoir parameters. It is not constant, as often assumed. Pore volume compressibility is high in coals because porosity is so small. A rebound in permeability can occur at lower drawdown pressures for the highest modulus and matrix shrinkage values. We have also history matched rates from a {open_quotes}boomer{close_quotes} well in the fairway of the San Juan basin using various stress-dependent permeability functions. The best fit stress-permeability function is then compared with the new theory.

Review of wag field experience

Abstract: In recent years there has been an increasing interest in water-alternating-gas (WAG) processes, both miscible and immiscible. WAG injection is an oil recovery method initially aimed to improve sweep efficiency during gas injection. In some recent applications produced hydrocarbon gas has been re-injected in water injection wells with the aim of improving oil recovery and pressure maintenance. Oil recovery by WAG has been attributed to contact of unswept zones, especially recovery of attic or cellar oil by exploiting the segregation of gas to the top or accumulating of water towards the bottom. Since the residual oil after gas flooding is normally lower than the residual oil after water flooding, and three-phase zones may obtain lower remaining oil saturation, water-alternating-gas has potential for increased microscopic displacement efficiency. WAG injection, thus, can lead to improved oil recovery by combining better mobility control and contacting unswept zones, and also leading to improved microscopical displacement. This study is a review of the WAG field experience as it is found in the literature today from the first reported WAG in 1957 in Canada and up to new experience from the North Sea. About 60 fields have been reviewed. Both onshore and offshore projects have been included, as well as WAG with hydrocarbon or non-hydrocarbon gases. Wellspacing is very different from onshore projects (where fine patterns often are applied) to offshore projects (well spacing in the order of 1000 meters). For the fields reviewed, a common trend for the successful injections is an increased oil recovery in the range of 5-10 per cent of the OIIP. Very few field trials have been reported unsuccessful, but operational problems are often comment Though, the injectivity and production problems are generall not detrimental for the WAG process, special attention been given to breakthrough of injected phases (water or gas Improved oil recovery by WAG is discussed as influenced b rock type, injection strategy, miscible/immiscible gas, an well spacing.

Developments in Synchrotron X-Ray Microtomography With Applications to Flow in Porous Media

Abstract: High resolution computed microtomography (CMT) using synchrotron X-ray sources provides the ability to obtain three-dimensional images of specimens with a spatial resolution on the order of micrometers. Microimaging capabilities at Brookhaven National Laboratory`s National Synchrotron Light Source have been enhanced to provide larger and higher resolution 3-D renderings of pore networks in reservoir rocks at a fraction of the time required in previous first generation scanning methods. Such data are used to model single and multiphase flow properties in digital images of real porous media. Pore networks are analyzed for tortuosity and connectivity measures, which have been elusive parameters in transport property models. We present examples of porosimetry simulation via network modeling to produce initial water saturation and residual oil distributions in a water-wet pore system. Furthermore, pore networks can provide the boundary condition framework for more rigorous simulations of displacement, such as in the lattice Boltzmann simulated waterflood example provided. Direct comparison between simulation and experiment is also possible. CMT images of a 6 mm subsection of a one inch diameter reservoir core sample were obtained prior and subsequent to flooding to residual oil. The fluid distributions from CMT, lattice Boltzmann waterflood simulation, and percolation-based network modeling were foundmore » to be highly correlated. Advances in 3-D visualization, implemented in Brookhaven National Laboratory`s 3-D theater, will allow even greater digestion and interpretation of phenomena dependent upon pore interconnectivity and multipore interactions.« less

The relation among porosity, permeability, and specific surface of chalk from the Gorm field, Danish North Sea

Abstract: The origin of the difference in the relationship between permeability and porosity for Danian and Maastrichtian chalk from the Gorm field offshore Denmark has been investigated. The investigation was based on 300 sets of core data (He-expansion porosity and air permeability) from Well Gorm N-22X. On 24 of the core plugs, the specific surface was determined by BET and, on 14 of these samples, image analysis was made. The data were rationalized by the use of the Kozeny equation and it was found that each geologic unit had a characteristic relationship among porosity, permeability, and specific surface. Furthermore, it was found that the nature of porosity (intrafossil, intergranular, etc.) had no significant influence on the air permeability, so that the permeability of the chalk can be calculated from total porosity and specific surface. Kozeny’s empirical constant, c, was determined analytically from a simple porosity model and Poiseuille’s law.

Measurement and correlation of gas condensate relative permeability by the steady-state method

Abstract: High pressure core flood experiments using gas condensate fluids in long sandstone cores have been conducted. Steady-state relative permeability points were measured over a wide range of condensate to gas ratio's (CGR), with the velocity and interfacial tension (IFT) being varied between tests in order to observe the effect on relative permeability. The experimental procedures ensured that the fluid distribution in the cores was representative of gas condensate reservoirs. Hysteresis between drainage and imbibition during the steady-state measurements was also investigated, as was the repeatability of the data. A relative permeability rate effect for both gas and condensate phases was observed, with the relative permeability of both phases increasing with an increase in flow rate. The relative permeability rate effect was still evident as the IFT increased by an order of magnitude, with the relative permeability of the gas phase reducing more than the condensate phase. The influence of end effects was shown to be negligible at the IFT conditions used in the tests, with the Reynolds number indicating that flow was well within the so called laminar regime at all test conditions. The observed rate effect was contrary to that of the conventional non-Darcy flow where the effective permeability should decrease with increasing flow rate. A generalised correlation between relative permeability, velocity and IFT has been proposed, which should be more appropriate for condensing fluids than the conventional correlation. The results highlight the need for appropriate experimental methods and relative permeability relations where the distribution of the phases are representative of those in gas condensate reservoirs. This study will be particularly applicable to the vicinity of producing wells, where the rate effect on gas relative permeability can significantly affect well productivity. The findings provide previously unreported data on relative permeability and recovery of gas condensate fluids at realistic conditions.

Compositional and Black Oil Reservoir Simulation

Abstract: This paper describes a three-dimensional, three-phase reservoir simulation model for black oil and compositional applications. Both IMPES and fully implicit formulations are included. The model`s use of a relaxed volume balance concept effectively conserves both mass and volume and reduces Newton iterations. A new implicit well rate calculation method improves IMPES stability. It approximates wellbore crossflow effects with high efficiency and relative simplicity in both IMPES and fully implicit formulations. Multiphase flow in the tubing and near-well turbulent gas flow effects are treated implicitly. Initial saturations are calculated as a function of water-oil and gas-oil capillary pressures which are optimally dependent upon the Leverett J function or initial saturations may be entered as data arrays. A normalization of the relative permeability and capillary pressure curves is used to calculate these terms as a function of rock type and grid block residual saturations. Example problems are presented, including several of the SPE Comparative Solution problems and field simulations. 48 refs.

Parachors based on modern physics and their uses in IFT prediction of reservoir fluids

Abstract: Prediction of interfacial tension (IFT) is essential for modeling many secondary and tertiary oil recovery processes. The parachor method has been widely used to predict IFT. There has been considerable confusion in the literature concerning the parachor method for estimating IFT. The confusion is primarily based upon the lack of clarity concerning the scaling exponent and parachors derived based on this exponent. According to modern physics, the theoretical value of the scaling exponent is 3.88 for all pure substances, although several values may be found in the literature, usually altered to match existing data. This paper addresses: (1) clarification of the confusion about the scaling exponent, (2) derivation of parachors for pure species occurring in petroleum fluids and oil cuts, and (3) verification of the validity of these derived parachors in IFT prediction of reservoir fluids. We have analyzed experimental data for various compounds and compound mixtures occurring in the petroleum fluids and found that the 3.88 is the unique scaling exponent for pure species inside and outside, to some large extension, of the critical region. Taking 3.88 as a fixed scaling exponent, parachors of 139 crude oil components are back-calculated using surface tension and density data obtained from experimentsmore » by previous investigators. These parachors are compared with three selected parachor correlations for IFT predictions of six available crude oil and CO{sub 2} mixtures, and found to be more accurate.« less

Incorporating Seismic Attribute Maps in 3D Reservoir Models

Abstract: We introduce a new geostatistical method to incorporate seismic attribute maps into a 3D reservoir model. The method explicitly honors the difference in vertical resolution between seismic and well log data. The method, called Sequential Gaussian Simulation with Block Kriging (SGSBK), treats the seismic map as a soft estimate of the average reservoir property. Using this method, the average of the cell values in any one vertical column of grid cells is constrained by the value of the seismic map over that column. The result is a model that contains vertical variability driven by well logs and the vertical variogram model and spatial variability driven by the seismic map and the areal variogram model.

A Pilot Test of Polymer Flooding in an Elevated-Temperature Reservoir

Abstract: A pilot test of polymer flooding has been conducted in Shuanghe reservoir located in southeast Henan oil field, China. The target reservoir has a net thickness of 15.56 meters (50 ft), an average permeability of 420 md, and temperature of 75{degrees}C (167{degrees}F). The polymers used are two types of modified partially hydrolyzed polyacrylamides, named S525 and S625, which have molecular weights of 16,700,000 and 19,670,000 daltons, respectively. The objective of this pilot test is to investigate the feasibility of polymer flooding for improving oil recovery in an elevated-temperature reservoir. The polymer flooding started in February 1994. Up through December 1995, a total of 246 tons (about 0.5 x 106 lb) of dry polymer had been used with an injection concentration of 900-1100 ppm. The pore volume injected reached 0.2164. As a result, oil production increased by 22,000 tons (184,000 bbl) and water production decreased by 153,000 tons (962,000 bbl), which accounts for the incremental oil recovery of 3.8% and water-cut reduction of 5.6% in the test block. It is estimated that by the end of this project, the ultimate increase in oil production will exceed 63,000 tons (528,000 bbl) with the enhanced oil recovery going up to 9.8%. The yieldmore » is 0.2 tons more oil produced per kilogram of polymer injected or 0.7 barrel of oil produced per pound of polymer. The success of the pilot test is attributed to a few techniques used during the implementation of the flooding, including prevention of polymer thermal degradation, good reservoir description, and the profile modification carried out before and after the polymer injection. This pilot test illustrates a case where polymers with extra-high molecular weight are successfully injected in an elevated-temperature reservoir to control the mobility ratio and modify the permeability profile.« less

Quantification of Reservoir Connectivity for Reservoir Description Applications

Abstract: This study investigates means for indirectly incorporating dynamic production data constraints into geostatistically-derived reservoir descriptions. Simulated primary and waterflood performance for two-dimensional vertical, three-phase, black oil reservoir systems are used to identify and quantify spatial characteristics which control well performance. The paper focuses on the development of reservoir connectivity parameters and the estimation of well performance characteristics based on this parameter. This approach is considered to be an indirect method because the reservoir connectivity parameter is computed from static spatial reservoir properties rather than from dynamic production data, thus simplifying the process of obtaining a realistic reservoir description. The reservoir connectivity parameter was found to correlate strongly with : (1) secondary recovery efficiency, (2) drainable hydrocarbon pore volume and (3) floodable hydrocarbon pore volume. Mobility ratio sensitivities show that, given a reservoir description, the water breakthrough time can be estimated using the reservoir connectivity parameter. This can be achieved using 3-5 orders of magnitude less computational time than required for comparable flow simulations.

Correlation and Prediction of Residual Oil Saturation for Gas Injection EOR Processes

Abstract: A promising correlation has been developed that can be used to predict miscible or near-miscible residual oil saturation, S orm , for a wide range of injected gases, crude oils, temperature, and pressure conditions. The correlation is based on representation of the chemical and physical properties of the crude oil and the injected gas through Hildebrand solubility parameters. This approach has the advantage that characteristics of both the injected gas and crude oil are included in the correlation, in contrast to correlations based solely on properties of the injected gas. The correlation was developed using available experimental data for tertiary recovery of eight crude oils in carbonate and sandstone cores with common EOR gases (CO 2 , N 2 , CH 4 , CH 4 + liquefied petroleum gas). Results for 45 coreflood tests at reservoir conditions collapsed along a band when S orm was plotted as a function of the difference in solubility parameter between the injected gas and the crude oil. Results for a pure oil, decane, with CO 2 lay along the same band. The success of this correlation scheme may be due to the basic characterization of the fluids and to a relationship between solubility parameters and interfacial tension. Use of the correlation requires knowledge of only injected gas composition, injected gas density, oil average molecular weight, and temperature. This empirical correlation should have utility in screening studies or in process simulation as a simple means to forecast residual oil saturations as measured in coreflood tests. The correlation can be used to predict roughly the effects of changes in pressure, temperature, or injected gas composition on residual oil saturation. A new method to predict minimum miscibility pressure based on the solubility parameter concept is also described.

Making Sense of Water Injection Fractures in the Dan Field

Abstract: Water injection above fracture propagation pressure is used in the Dan field, a low permeability chalk oil field, to provide improved recovery. A pilot scheme began in 1990 and by 1995 the decision was taken to further develop most of the field using this concept. The pilot scheme indicated that the induced fractures have a general north-south orientation and a fracture length in some cases exceeding 4000ft. Several monitoring techniques have been applied to evaluate fracture height, length, orientation and injector/producer interaction, including: open hole and through casing saturation logging, tracer injection, producer water cut monitoring and falloff surveys in injection wells. To gain the maximum information from this data, a model of fracture growth was developed to integrate the different forms of data. Application of the model has resulted in an improved estimate of fracture height, length and near fracture permeability enhancement and has lead to a more comprehensive understanding of fracture growth mechanics in Dan. This paper presents the different monitoring techniques, the model development and various examples of the way the model has been used to enhance the understanding of field data.

Integrated Reservoir Characterization Study of a Carbonate Ramp Reservoir: Seminole San Andres Unit, Gaines County, Texas

Abstract: An integrated reservoir characterization of Seminole San Andres Unit was conducted using outcrop and subsurface data. The high frequency cycles and rock-fabric facies identified on outcrop and cores were used to correlate wireline logs. Reservoir and simulation models of the outcrop and a two-section area of the Seminole San Andres field were constructed using rock-fabric units within high-frequency cycles (HFC`s) as a geologic framework. Simulations were performed using these models to investigate critical factors affecting recovery. High-frequency cycles and rock-fabric units are the two critical scales for modeling shallow-water carbonate ramp reservoirs. Descriptions of rock-fabric facies stacked within high-frequency cycles provide the most accurate framework for constructing geologic and reservoir models because discrete petrophysical functions can be fit to rock fabrics and fluid flow can be approximated by the k{sub vh} ratios among rock-fabric flow units. Permeability is calculated using rock-fabric-specific transforms between interparticle porosity and permeability. Core analysis data showed that separate-vug porosity has a very strong effect on relative permeability and capillary pressure measurements. The stratigraphic features of carbonates can be observed in stochastic realizations only when they are constrained by rock-fabric flow units. Simulation results from these realizations are similar in recovery but different in production andmore » injection rates. Scale-up of permeability in the vertical direction was investigated in terms of the ratio of vertical permeability to horizontal permeability (k{sub vh}). This ratio decreases exponentially with the vertical grid-block size up to the average cycle size of 20 ft (6.1 m) and remains at a value of 0.06 for a grid-block size of more than 20 ft (>6.1 m), which is the average thickness of high-frequency cycles.« less

Application of wavelet analysis to upscaling of rock properties

Abstract: Although numerous upscaling techniques are reported in the literature, efficiently computing reasonably accurate equivalent rock properties from geological data at fine scale remains difficult. This is especially true for facies with multiple lithologies under multiphase flow conditions. Due to the nature of multiscale heterogeneity inherent in petroleum reservoirs, the equivalent rock and flow properties will vary with the scales of heterogeneity. Therefore, upscaled properties under multiphase flow conditions cannot be estimated without reference to the absolute scales of heterogeneity. Wavelet analysis is a multiresolution framework and, thus, it is well suited for upscaling rock and flow properties in a multiscale heterogeneous reservoir. The compact support property of the wavelet transform assures efficient computation. Choice of regularity provides a flexible way to control the smoothness of the resulting upscaling properties. In this study, a new procedure was developed to significantly improve the computational efficiency and accuracy of upscaling for generating equivalent rock and rock-fluid properties under various geological and flow conditions based on multiresolution analysis of wavelet transforms. Additionally, a wavelet reconstruction method was explored to provide a basis for downsampling fine-scale rock property fields from information at various levels of coarser scale. The beauty of the method is that sincemore » the equivalent properties at different length scales are computed recursively, the interdependent influences of the heterogeneities on the scales are included effectively. The method is demonstrated by successfully applying it to upscale interbedset and interfacies outcrop petrophysical data.« less