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Karimaie and Torsaeter (2008) performed experiments to investigate gas injection in fractured This paper describes the results of several experiments that were carbonate rock. They mainly investigated the effect of gas carried out to investigate the block-to-block interaction in fractured injection on the gravity-drainage process. This study showed that limestone reservoirs for both gas/oil and solvent/oil systems the recovery of oil increased significantly by repressurization in by use of carbonate cores. The focus of this research was to understand the gravity-drainage process. They also demonstrated that lowinterfacial-tension gravity drainage, reinfiltration, and mixing in fractured systems gravity drainage is capable of recovering a significant with a set of laboratory experiments. The designed setup portion of oil in fractured reservoirs even after water included three kinds of models (i.e., a transparent rectangular box injection. Boerrigter et al. (2007) presented a dual-permeability filled with a glass-bead pack and two cylindrical models with single simulation formulation capable of handling gas and oil gravity and stacked carbonate blocks inside to cover all important drainage (GOGD) and expansion-imbibition processes, impact of cases in this area); then, several factors are defined to correlate fracture spacing, block height, GOGD of sub-gridblock effects, the results of glass-bead-pack model with the two other kinds of and reimbibition effects and interaction of GOGD with enhancedoil-recovery models.
A two-dimensional (2D) analytical model is presented for gas/oil gravity drainage in a homogeneous, dipping reservoir. The sensitivity of gas/oil gravity drainage to key variables such as injection rate, oil relative permeability, and permeability anisotropy can be determined quickly with this model. Example calculations show that miscible-like recovery efficiencies are possible with immiscible gas injection into high-permeability dipping reservoirs with light oil. A procedure based on the analytical model has been developed to simulate immiscible gas injection into highly stratified reservoirs accurately. This simulation procedure allows a great deal of geological detail to be incorporated into reservoir models, because it permits relatively coarse grids. Application of the simulation procedure to a reservoir containing many discontinuous shales reveals that the presence of shales may favorably affect the recovery efficiency of an immiscible gas-injection process.
Gas injection increasingly is being applied as a secondary or tertiary recovery process. High-permeability, light-oil reservoirs with a reasonable reservoir dip are particularly suitable candidates for gas injection. In these reservoirs, a gravity-stable injection scheme is often possible, leading to high sweep efficiencies. If the injection process is carried out at sufficiently high pressure, process is carried out at sufficiently high pressure, favorable phase behavior between reservoir fluid and injection gas can contribute significantly to the recovery of oil. Miscibility, however, is by no means always necessary to obtain high displacement efficiencies. Even in the case of an entirely immiscible displacement, a high displacement efficiency is possible if gravity drainage is the dominant production mechanism. Laboratory experiments have shown that, the residual oil saturation after gas invasion, is virtually zero in highly permeable sandstone cores containing connate water. The ultimate recovery of an immiscible process is then close to 100%. Whether oil saturations process is then close to 100%. Whether oil saturations in the gas-invaded zone will approach the residual value within the lifetime of a particular reservoir depends on the rate of gravity drainage for this reservoir. This problem, which is the main subject of this paper, has been studied by both analytical means and numerical simulation. In the following, first a 2D analytical model is introduced for gas/oil gravity drainage in a homogeneous, dipping reservoir. The model combines aspects from both one-dimensional (1D) vertical Buckley-Leverett drainage theory and Dietz' segregated flow theory for dipping reservoirs. Assumptions underlying the model have been verified by 2D cross-sectional simulations. Second, a procedure based on the analytical gravity-drainage procedure based on the analytical gravity-drainage model has been developed to simulate immiscible secondary gas injection into a highly stratified reservoir accurately. This is illustrated with an example of gas injection into a reservoir containing discontinuous shale layers.
Analytical Model for Gravity Drainage
Description of the Model. In this section, an approximate analytical model is formulated for immiscible, gravity-stable gas/oil displacement in a homogeneous, dipping layer. Fig. 1 shows a schematic cross section of the draining reservoir with some relevant flow characteristics. In this model, oil is assumed to be produced from downdip wells near the oil/water contact at a rate that ensures a gravity-stable displacement, while gas is injected in updip wells near the crest to fill the voidage. This causes the gas/oil contact (GOC) to move downward gradually. Behind the GOC some oil will be left, the amount of which depends on the oil relative permeability and on the tilt and rate of descent of the GOC. The gas-invaded region will continue to produce oil by after-drainage; this oil will collect at the bottom of the reservoir in a thin oil layer, which flows to the producers with the along-dip component of gravity as driving force. To make the essentially 2D model amenable to analytical calculation, the following assumptions are introduced. 1. The model has infinite gas mobility. 2. The model has negligible gas/oil capillary pressure. pressure. 3. The GOC moves at a constant velocity, v GOC,x, and at a constant tilt angle, , given by Dietz' theory for gravity-stable segregated flow in dipping reservoirs (evaluated for infinite gas mobility) as
with u max,x being the maximum along-dip gravity drainage ratei.e., in the direction of bulk fluid flow. This rate is defined as
Summary The Schönkirchen Tief oil field is located in the Vienna basin in Austria. It is a pervasively fractured dolomite reservoir that has been produced for more than 50 years. The field is at the tail end of production, the wells are perforated close to the top of the reservoir, and water is injected downdip. Because of the location of the field close to one of the main gas pipelines in Austria, it is planned to convert the field into high-performance underground gas storage (UGS). The field is characterized by a highly permeable fracture system and a less-permeable matrix system. It is expected that some incremental oil can be recovered because of gas/oil gravity drainage from the matrix. In addition to gas/oil gravity drainage, diffusion will have an effect on the oil recovery. The injected gas is leaner than the equilibrium gas in the reservoir. Hence, gas components diffuse from the fracture system into the matrix and components of the oil diffuse toward the fracture system. This results in a modification of the properties of the oil affected by diffusion. This type of gas injection results in a zone of decreased oil viscosity for gases such as CO2 and CH4 at the interface of the gas and the oil in the matrix. This zone of lower oil viscosity increases the gas/oil gravity-drainage rates. The results show that the effect of diffusion can increase cumulative oil production up to 25% compared with a case neglecting the effect of diffusion. The effect of diffusion could be determined for various parameters such as permeability, porosity, fracture spacing, and matrix-block height. While for some of the parameters the effect of diffusion scales with the square root of time (e.g., permeability), for others an exponential relationship has been determined (fracture spacing). The results derived for the example reservoir can be used more generally to screen whether the effect of diffusion should be incorporated into reservoir studies concerning nonequilibrium-gas injection and to determine how large the error could be in the case where diffusion is neglected.
The scope and constraints for enhanced oil recovery in the North Sea have been widely recognised. North Sea reservoirs are in general over-pressured and are highly permeable. They contain a 35-40 "API crude which exhibits a wide range of compositional variations. The present development of fields in the hostile environment of the North Sea does not permit a close spacing of wells which is in generai desirable for enhanced oil recovery. A review is presented of the theoretical and experimental laboratory studies and field test results aimed at optimizing recovery with various enhanced recovery methods. Laboratory studies and field test results indicate that for several major North Sea reservoirs, miscible gas injection may lead to higher recoveries than water injection. Miscible gases that are being considered are hydrocarbon gas and nitrogen. A miscible hydrocarbon gas drive test has already been initiated in the Statfjord reservoir of the Brent field. Laboratory studies have also indicated that the oil remaining after waterñood can be recovered by nitrogen injection, which may lead to very low residual oil saturations.
This chapter concerns gas injection into oil reservoirs to increase oil recovery by immiscible displacement. The use of gas, either of a designed composition or at high-enough pressure, to result in the miscible displacement of oil is not discussed here; for a discussion of that topic, see the chapter on miscible flooding in this section of the Handbook. A variety of gases can and have been used for immiscible gas displacement, with lean hydrocarbon gas used for most applications to date. Historically, immiscible gas injection was first used for reservoir pressure maintenance. The first such projects were initiated in the 1930s and used lean hydrocarbon gas (e.g., Oklahoma City field and Cunningham pool in the United States and Bahrain field in Bahrain). Over the decades, a considerable number of immiscible gas injection projects have been undertaken, some with excellent results and others with poor performance. Reasons for this range of performance are discussed in this chapter. At the end of this chapter, a variety of case studies are presented that briefly describe several of the successful immiscible gas injection projects. Gas injection projects are undertaken when and where there is a readily available supply of gas. This gas supply typically comes from produced solution gas or gas-cap gas, gas produced from a deeper gas-filled reservoir, or gas from a relatively close gas field. The primary physical mechanisms that occur as a result of gas injection are (1) partial or complete maintenance of reservoir pressure, (2) displacement of oil by gas both horizontally and vertically, (3) vaporization of the liquid hydrocarbon components from the oil column and possibly from the gas cap if retrograde condensation has occurred or if the original gas cap contains a relict oil saturation, and (4) swelling of the oil if the oil at original reservoir conditions was very undersaturated with gas. Gas injection is particularly effective in high-relief reservoirs where the process is called "gravity drainage" because the vertical/gravity aspects increase the efficiency of the process and enhance recovery of updip oil residing above the uppermost oil-zone perforations. The decision to apply immiscible gas injection is based on a combination of technical and economic factors. Deferral of gas sales is a significant economic deterrent for many potential gas injection projects if an outlet for immediate gas sales is available.