The CO2 flooding is a proven enhanced oil recovery technique to obtain high oil recovery from complicated formations and can be applied to various types of oil reservoirs. It can be injected as immiscible or miscible flooding but immiscible flooding is less effective than miscible flooding. Two types of miscibility can occur: first contact miscibility and multiple contact miscibility. First contact miscibility happens when a single phase is formed when CO2 is mixed with the crude oil. Multiple contact miscibility occurs when miscible conditions are developed in situ, through composition alteration of the CO2 or crude oil as CO2 moves through the reservoir. The miscible flooding process involves complex phase behavior, which depends on the temperature, pressure and fluid properties of the oil reservoir. The CO2 increases oil recovery by oil swelling, reduction of oil viscosity and density, the acidization of carbonate formations and miscibility effects. Multiple-contact miscibility between the injected CO2 and oil can be achieved at pressures above the minimum miscibility pressure (MMP). MMP is the pressure at which the reservoir fluid develops miscibility with CO2 and is a very important parameter in a well-designed CO2 flood project. Some reservoirs are considered tight because of poor rock or fluid characteristics. The main objective of this study is to investigate the performance of CO2 miscible flooding in tight oil reservoirs. This includes determination of minimum miscibility pressure (MMP) involving carbon dioxide and crude oil and miscible CO2 core flooding. This paper addresses the results of CO2 miscible flooding applied to a known reservoir. Several CO2 miscible flooding experiments were conducted using live oil at reservoir temperature and pressure above the MMP on composite cores of known reservoir. The MMP was determined experimentally using the slim tube. High oil recovery from these experiments indicates that the MMP determined from slim tube studies was correct and such a high recovery is only possible if full miscibility occurs during the displacement. The analytical correlation also gave a MMP consistent with MMP determined from slim tube experiments. Introduction Certain reservoirs have been classified "tight" at the time of their discovery, simply because of poor reservoir characteristics. The exploitation of these reservoirs was judged uneconomical at that time because of their low production rate. In fact, the decision whether to produce or not from a reservoir that has been judged "tight" depends not only on the economical context at the time this decision is taken but also on the state of technology prevalent at the time of this decision. It is natural that any change in the price of oil, or any breakthrough in technology especially in drilling, production engineering and enhanced oil recovery can affect significantly the feasibility of developing these tight reservoirs. Reservoirs that have been judged tight on the basis of thirty year old technology may become economical when modern recovery techniques are applied. Both the economical context and the state of new technologies in the domain of enhanced oil recovery, drilling and production engineering have a significant effect on the feasibility of developing these reservoirs.
Summary We developed an experimental method to obtain the Biot elastic constant of rocks from laboratory dynamic and static measurements. The Biot constant often has been calculated with various empirical equations. The experimental determination of the Biot elastic constant is very important to engineering problems associated with sand control, hydraulic fracturing, wellbore stability, earth stresses, sonic porosity, and estimation of compressional-, P, and shear-, S, wave velocity. Both the dynamic and static moduli of actual reservoir sandstone core samples, jacketed and mounted in a triaxial cell under vacuum, were measured at various confining and overburden stresses. The results obtained show that the Biot constant is a complex function of porosity, permeability, pore-size distribution, and overburden and confining stress, which means that it is not really a constant. Also, the static Biot constant is greater than the dynamic one and their difference increases with increasing overburden stress according to the equation astatic =[1+0.05*(sz)ef]*adynamic (where sz is in Ksi). Moreover, both the experimental static and dynamic Biot constants may be significantly different from values calculated with empirical equations. This study suggests that quantifying the Biot constant in the laboratory may enhance the determination of rock-strength/fracturing, earth stresses, rock subsidence, sanding predictions, P- and S-wave velocities, porosity, and pore fluid from sonic and seismic data. Introduction The Biot1–7 elastic constant, a, of a rock is an important poroelastic parameter that relates stress and pore pressure and describes how compressible the dry skeletal frame is with respect to the solid material composing the dry skeletal frame of the rock. Biot1 measures the ratio of the fluid volume squeezed out to the volume change of the rock if the latter is compressed while allowing the fluid to escape. It is described as Because the petroleum-related rocks are usually saturated, it is important to know how the saturation and pore pressure affect their mechanical and flow properties. Terzaghi's8 effective-stress principle for soils states that we can obtain the effective stress by simply subtracting the fluid pressure from the total stress; i.e., se=st -ap, which means that a=1. This implies that increasing the external stress by some amount produces the same volume change of the porous material as reducing the pore pressure with the same amount. This principle appears to be valid for most properties of soils. However, in petroleum-related rocks, Terzaghi's effective-stress principle may not be valid. Then, a modified effective stress is a function of the Biot constant, a, and given by sef=st -ap. Despite the great significance of a, only a limited amount of laboratory work on its determination has been reported in the literature.9–13 The failure criteria for a saturated rock with a pore pressure are obtained by introducing the effective stress into the dry form of the failure criteria. This means that all rock failure and sand-production prediction models require a known static Biot constant value. So far, researchers, engineers, and geophysicists quite often assume that a=1 (Terzaghi's principle), which is not necessarily true. Alternatively, for the determination of a, they may use various empirical equations.14–17 These equations, however, yield different values that may vary by up to 100% or more depending on the equation used. The primary objective of this study was to determine the Biot elastic constant experimentally, both by dynamic and static measurements, and to establish a correlation between the dynamic and static a. Another objective was to identify any rock properties controlling the Biot elastic constant. Experimental Determination of the Biot Constant In this experimental method, we determined both the dynamic and static moduli of actual reservoir sandstone core samples under high vacuum (<0.15 mbar) and at various confining (s2=s3=sx) and axial (s1=sx) stresses. The vacuum was obtained and maintained in-situ while the rock sample was mounted and tested with a triaxial system. The rock sample is prepared, jacketed, and mounted in the triaxial cell. Then, the cell is closed firmly to prevent leaks and filled with the confining fluid. Vacuum is then pulled out of the sample with a high-power vacuum pump. Once the desired vacuum condition (<0.15 mbar) is established, a multistage triaxial compression test is performed, as discussed in details elsewhere.18 Axial and confining stresses were applied hydraulically. The dynamic and static data were generated at various axial and confining stresses. At each confining-stress stage, several P and S waveforms were recorded as the axial (overburden) stress was increased. The measured P - and S-wave velocities were used to calculate the dynamic Poisson's ratio and the dynamic Bulk, Shear, and Young's moduli of the dry skeletal frame of the rock, Ksk.
A detailed physical characterization of tar from a carbonate reservoir in Saudi Arabia was made to evaluate its mobility and ways of establishing contact between the lighter oil and its aquifer. Density and viscosity measurements were carried out on several tar samples, under simulated reservoir conditions of pressure and temperature. Other physical parameters such as simulated distillation, pour point and penetration index were also experimentally determined. Tar physical properties were found to vary with depth and area within the same field. The obtained experimental results showed a gradual increase in density and viscosity from the tar/oil contact towards the tar/water contact. This increase was much more pronounced in the neighborhood of the tar/water contact. Density and viscosity of tar diluted with toluene were in excellent agreement with those of pure tar. The density of non preserved tar varied between 0.956 g/cc at 200°F and 1.008 g/cc at 76°F while that of preserved tar varied between 0.944 g/cc at 200°F and 0. 991 g/cc at 76°F. The tar samples analyzed appear to behave as Newtonian fluids. Introduction The present paper discusses detailed physical characterization of several extracted and RFT bottom hole tar samples obtained from a carbonate reservoir in Saudi Arabia. The chemical aspect has already been presented elsewhere [1]. Tar is defined as extra heavy oil with a gravity ranging between 29 and 9°API albeit the distinction between heavy oil and tar is rather shady. Tar mat is present in abundance in the Middle East, Africa and elsewhere. In recent publications Kaufman et al. [2] mentionned the presence of a tar zone at the water/oil contact in Burgan field. This has been known for a long time. However, to ascertain lateral and vertical delineation of the tar zones appear to be still unresolved. Thick tar zones identified through visual observation and Latroscan analyses of weathered core samples were reported in the Raudhatain field [3]. A tar mat is generally a thick column laying between an aquifer underneath and a much lighter oil reservoir above. This peculiar location poses a host of challenging problems for an efficient management of the lighter oil and ultimately for a proper management of the tar zone itself [4]. In this study, density of tar was measured with a digital Anton Parr densiometer having a maximum temperature range of 300°F and a pressure limit of 6000 psi. Based on these measurements, specific gravity and API gravity were determined. A rolling ball viscometer was used to measure tars viscosity at elevated pressures and various temperatures. The effect of visbreaking or permanent viscosity reduction due to thermal alteration has also been examined.
T his article provides the results of the implementation of the Amott-Harvey method (quantitative) and the visual method (qualitative) to determine the wettability of the rock in core samples from the Mugrosa Formation of the Colorado Field, in order to learn about the distribution of fluids in the reservoir, as this property affects various aspects of the production performance thereof. Wettability is determined first by restoring the wettability of the samples, for 200 hours and 1000 hours at reservoir conditions (T = 144°F and P = 1350 psi). After that, rock wettability is calculated using the Amott-Harvey method, obtaining results of neutral wettability. It is then determined by the visual method for comparison purposes, in order to conclude that rock wettability is neutral. It is important to emphasize that the visual method is of great relevance, because it provides a real view of how the fluids are distributed within the rock to obtain representative results, in order to make decisions that optimizes the production of the field under study.
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