Reservoir Engineering Applications Research Articles

Tomographic imaging of three-phase flow experiments

The medical x-ray computerized tomography (CT) scanner has proved to be a useful tool for studies of fluid flow in porous media, with particular applications in reservoir engineering and enhanced oil recovery. This paper explains how CT is used to measure the volume fraction of pore space occupied by up to three discrete phases, such as oil, water, and gas. The image processing system, x-ray transparent high-pressure flow equipment, choice of fluid dopants, and x-ray energies are described for scanning of core flood experiments. Examples are given of tertiary miscible carbon dioxide displacements in Berea sandstone.

Reservoir Engineering Applications for Development and Exploitation of Geothermal Fields in the Philippines: ABSTRACT

After a geothermal well is completed, several tests and downhole measurements are conducted to help evaluate the subsurface fluid and reservoir properties intersected. From these tests, a conceptual model of the well can be developed by integrating data from the various parts of the field. This paper presents the completion techniques applied in geothermal wells, as well as the role of reservoir engineering science in delineating a field for development. Monitoring techniques and other reservoir engineering aspects of a field under exploitation are also discussed, with examples from the Philippines.

Analytical Representation of the van Everdingen-Hurst Aquifer Influence Functions for Reservoir Simulation

Abstract Linear regression analysis has been used to develop some simple analytical expressions for the van Everdingen-Hurst aquifer influx influence functions. Regression results are presented for a variety of aquifer radius/reservoir radius ratios. The regression equations are designed for use in reservoir engineering applications, especially reservoir simulation.

Simulation of High Relief Reservoirs, Rainbow Field, Alberta, Canada

A comparison of the three-dimensional and one-dimensional models for both natural depletion and crestal gas injection shows that for high relief reservoirs, a one-dimensional model is adequate for many reservoir engineering applications. Introduction The Rainbow field of northwestern Alberta was discovered in 1965 and currently contains 44 separate reef reservoirs with areal extents up to 4,600 acres, and productive oil pay zones up to 600 ft. Production is from the Rainbow member of the middle Devonian Keg River formation, which occurs at a depth of approximately 6,000 ft. Average porosity values range from 4 to 15 percent and typical average values of vertical and horizontal permeability are 40 and 200 md, respectively. Excellent reservoir communication has allowed wide well spacing ranging from 160 to 640 acres. Oil in place varies from less than 10 million bbl in the smaller pinnacle reefs to 260 million bbl in the larger atolls. Reef buildups in the Rainbow area are shown schematically in Fig. 1. In the Rainbow field, many different types of secondary recovery projects have been initiated, including bottom-water drive, projects have been initiated, including bottom-water drive, crestal gas injection and vertical downward miscible slug displacement. Gravity drainage controls all recovery mechanisms, and typical predicted recovery factors are 55 percent for natural depletion, 65 percent for gas or water injection and 95 percent for percent for gas or water injection and 95 percent for miscible displacement. Under the Alberta oil proration system, allowables are distributed among pools on the basis of recoverable reserves. Therefore, to define allowables in the Rainbow reservoirs it is necessary to evaluate accurately the recoverable reserves for both primary depletion and secondary recovery projects. To perform these studies, several mathematical reservoir simulators were used. These included one-, two- and three-dimensional, three-phase, compressible and incompressible models. The use of these different models for studying various depletion mechanisms for many different reservoirs offered a unique opportunity to evaluate their speed, cost and areas of application. This paper discusses the use of geology in defining the spatial distribution of reservoir properties; some particular problems that arose in the simulation of particular problems that arose in the simulation of Rainbow-type reefs and the methods used to solve some of these problems. The functional steps in the multidimensional simulation of performance are shown graphically in Fig. 2. Use of Geological Studies to Define the Spatial Distribution of Reservoir Properties The wide well spacing in the Rainbow area led to extensive use of geological studies to define the spatial distribution of reservoir rock properties (porosity, permeability, capillary pressure, relative permeability) for use in mathematical models. Detailed permeability) for use in mathematical models. Detailed studies have been performed on the reefs in the Rainbow area, including the examination of data from 45 wells in 13 separate reservoirs and 15,000 ft of core. These studies revealed the presence of 14 geological rock types or lithofacies. The 14 rock types represent six depositional environments: basin, forereef, organic reef, backreef, lagoon and shoal. JPT P. 1399

Use of Well Log Temperatures to Evaluate Regional Geothermal Gradients

Abstract A previously untested technique of using maximum recorded temperatures while logging to total depth is used to study regional geothermal gradient variations in Oklahoma. A theoretical analysis of the mud temperature build-up is made to support this new method which shows that maximum logged temperatures, when properly recorded, provide better basic data than previously realized. Data obtained from searching through "More than 50,000 well logs are presented in the form of a regional geothermal map. A second-order polynomial surface is fitted to the data to study regional trends and deviations. Geological and other correlations are included only to establish the validity of the technique. Results of the study enable estimation of geothermal gradients in areas which are not presently covered by existing geothermal gradient maps. Introduction The thermal condition existing within the early is of fundamental importance to geological and geophysical theory. Knowledge of subsurface temperatures is also of interest to the oil industry, particularly in recent years because of higher temperatures associated with deeper drilling and the drilling of geothermal wells. Subsurface temperature information is useful when considering potential oil and gas exploration areas, drilling mud, lost circulation and cementing materials, casing design, logging programs, optimum location of geothermal wells and in reservoir engineering applications. A basic hypothesis of geophysics is that a correlation should exist between heat flow and major geologic and topographic features. This theory, while generally adhered to, has not been adequately tested because of the limited number of reliable determinations of heat flow through earth strata. The problem is manifested by the directional conductivity exhibited by shales, slates and some sandstones as shown by the observation that in situ conductivity determined in a single borehole through anisotropic material is not the conductivity parallel to the borehole. An alternate and useful approach in studying earth temperatures has been to determine the average rate of increase of temperature with depth (although locally temperatures may differ by a factor of 10 in different places and the gradients may differ at different depths along any given vertical). This technique has been used in studying local temperature anomalies over salt domes and anticlines and in proposed theories on the accumulation of hydrocarbons. It has been effectively applied to oil and gas exploration, showing that temperature variations usually conform to the subsurface structure at greater depths. Studies associated with geothermal gradients have shown thatthe gradient as determined from boreholes does not necessarily extrapolate back to the mean surface temperature;correlations of decreasing porosity with higher thermal gradients can be explained by differential compaction of sediments by tectonic forces;the spatial distribution of aquifer temperatures may be used to determine its flow characteristics;reservoirs with high original pressures are usually associated with geothermal highs; andlow geothermal gradients may exist over basin or platform-located oil reservoirs. Good subsurface temperature data are not readily available. Nichols and Moses selected temperatures measured in conjunction with pressure build-up surveys in preparing the only published regional geothermal gradient maps. Lyons extended this work in a map that is now available. Temperatures obtained while logging were excluded in these earlier works because it was expected that temperatures measured after circulation of drilling fluids would not be representative of true formation temperatures. Several authors have consistently discouraged the use of bottom-hole temperatures recorded when logging, on the assumption that the temperatures would not be correct because the wells were not in thermal equilibrium. An expedient solution to the problem of obtaining fairly reliable data over extensive areas is available in the logging files if logged temperature data are restricted to the maximum recorded temperatures in those wells logged to total depth. This technique has been shown to give bottom-hole temperature data that are representative of the true geothermal gradient. JPT P. 667ˆ

Calculation of Relative Permeability from Displacement Experiments

Published in Petroleum Transactions, AIME, Vol. 216, 1959, pages 370–372. A method is presented for calculating individual gas and oil or water and oil relative permeabilities from data obtained during a gas drive or a waterflood experiment performed on a linear porous body. The method has been tested and found both rapid and reliable for normal-sized core samples. Introduction Individual oil and gas or oil and water relative permeabilities are required for a number of reservoir engineering applications. Chief among these is the evaluation of oil displacement under conditions where gravitational effects are significant, such as a water drive or crestal gas injection in a steeply dipping oil reservoir. Numerous proposed methods of obtaining relative permeability data on reservoir core samples have been too tedious and time consuming for practical use, or have yielded questionable and sometimes inconsistent results. A method bas been developed by which the individual relative permeability curves can be calculated from data collected during a displacement test. The method is based on sound. Using this method, with a properly designed experimental procedure, relative permeability curves can be obtained using core samples of normal size (i.e., 2 to 3 in. in length and 1 to 2 in. in diameter) within a few days after receipt of the core. In a recent publication D. A. Efros describes an approach to the calculation of individual relative permeabilities that is based on the same theoretical considerations. We believe the approach described in the present paper is more adaptable to practical application than the method implied by Efros. In addition, comparisons with independently determined relative permeabilities are furnished to substantiate the reliability of the new method.