Summary 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 reinjected in water-injection wells with the aim of improving oil recovery and pressure maintenance. Oil recovery by WAG injection 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 the accumulating of water toward the bottom. Because the residual oil after gasflooding is normally lower than the residual oil after waterflooding, and three-phase zones may obtain lower remaining oil saturation, WAG injection has the potential for increased microscopic displacement efficiency. Thus, WAG injection can lead to improved oil recovery by combining better mobility control and contacting unswept zones, and by leading to improved microscopic displacement. This study is a review of the WAG field experience as it is found in the literature today,1–108 from the first reported WAG injection in 1957 in Canada to the new experience from the North Sea. About 60 fields have been reviewed. Both onshore and offshore projects have been included, as well as WAG injections with hydrocarbon or nonhydrocarbon gases. Well spacing is very different from onshore projects, where fine patterns often are applied, to offshore projects, where well spacing is in the order of 1000 m. For the fields reviewed, a common trend for the successful injections is an increased oil recovery in the range of 5 to 10% of the oil initially in place (OIIP). Very few field trials have been reported as unsuccessful, but operational problems are often noted. Though the injectivity and production problems are generally not detrimental for the WAG process, special attention has been given to breakthrough of injected phases (water or gas). Improved oil recovery by WAG injection is discussed as influenced by rock type, injection strategy, miscible/immiscible gas, and well spacing. Introduction The WAG injection was originally proposed as a method to improve sweep of gas injection, mainly by using the water to control the mobility of the displacement and to stabilize the front. Because the microscopic displacement of the oil by gas is normally better than by water, the WAG injection combines the improved displacement efficiency of the gas flooding with an improved macroscopic sweep by water injection. This has resulted in improved recovery (compared to a pure water injection) for almost all of the field cases reviewed in this work. Although mobility control is an important issue, other advantages of the WAG injection should be noticed as well. Compositional exchanges may give some additional recovery and may influence the fluid densities and viscosities. Reinjection of gas is favorable owing to environmental concerns, enforced restrictions on flaring, and - in some areas - CO2 taxes. The WAG injection results in a complex saturation pattern because two saturations (gas and water) will increase and decrease alternately. This gives special demands for the relative permeability description for the three phases (oil, gas, and water). There are several correlations for calculating three-phase relative permeability in the literature,95 but only recently has an approach been designed for WAG injection using cycle-dependent relative permeability.95 WAG injection has been applied with success in most field trials. The majority of the fields are located in Canada and the U.S., but there are also some fields in the former USSR. WAG injection has been applied since the early 1960's. Both miscible and immiscible injections have been applied, and many different types of gas have been used. This work gives a review of the WAG injection as it is found in the open literature today. Unfortunately, not all field trials are adequately described, and this overview is limited to the publicly accessible data. We have chosen to use an inclusive definition of WAG injection that covers all cases where both gas and water are injected in the same well. A process where one gas slug is followed by a water slug is, by definition, considered a WAG process. In the literature, WAG injection processes are also referred to as combined water/gas injection (CGW).100 Classification of the WAG Process. WAG processes can be grouped in many ways. The most common is to distinguish between miscible and immiscible displacements as a first classification. Miscible WAG Injection. It is difficult to distinguish between miscible and immiscible WAG injections. In many cases a multicontact gas/oil miscibility may have been obtained, but much uncertainty remains about the actual displacement process. In this paper, we have used only the information from the literature and find that most cases have been defined as miscible. It has not been possible to isolate the degree of compositional effect on oil recovery by WAG injection. Miscible projects are mostly found onshore, and the early cases used expensive solvents like propane, which seem to be a less economically favorable process at present. Most of the miscible projects reviewed are repressurized in order to bring the reservoir pressure above the minimum miscibility pressure (MMP) of the fluids. Because of failure to maintain sufficient pressure, meaning loss of miscibility, real field cases may oscillate between miscible and immiscible gas during the life of the oil production. Most miscible WAG injections have been performed on a close well spacing, but recently miscible processes have also been attempted even at offshore-type well spacing.86–90 Immiscible WAG Injection. This type of WAG process has been applied with the aim of improving frontal stability or contacting unswept zones. Applications have been in reservoirs where gravity-stable gas injection cannot be applied because of limited gas resources or reservoir properties like low dip or strong heterogeneity. In addition to sweep, the microscopic displacement efficiency may be improved. Residual oil saturations are generally lower for WAG injection than for a waterflood and sometimes even lower than a gasflood, owing to the effect of three-phase and cycle-dependent relative permeability.96,97 Sometimes the first gas slug dissolves to some degree into the oil. This can cause mass exchange (swelling and stripping) and a favorable change in the fluid viscosity/density relations at the displacement front. The displacement can then become near-miscible. Hybrid WAG Injection. When a large slug of gas is injected, followed by a number of small slugs of water and gas, the process is referred to as hybrid WAG injection.38–42 Others. A process where water and gas are injected simultaneously (SWAG injection) has been tested in a few reservoirs.37,106–108 Although this process is not the main scope of the paper, a few comments are given at the end. A final version of the cyclic injection is in the literature presented as Water Alternating Steam Process (WASP).102 Reviews of field cases will not be included in this paper.

fax 01-972-952-9435. AbstractIn recent years there hos been an increasing interest in wateralternating-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 tie bottom."" Since the residu~l oil after gas flooding is normally lower than the residud oil after water flooding, and three-phase zones may obtain lower remaining oil saturation, wateraltemating-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. _Bo@__on:hore and offshore projects have Mea 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 as unsuccessful, but operational problems are often commented. Though, the infectivity and production problems are generally not detrimental for the WAG process, special attention has been given to breakthrough of injected phases (water or gas). '__@proved oil recovery by WAG is discussed as influenced byreek type, injection strategy, miscible/immiscible gas, and "'wellspacing,

This paper describes a new technique to decrease the computational times of thermal simulations. Effectively, thermal processes are based on the displacement of a thermal front (combustion front, steam chamber interface), around which most fluid flows will take place. Thus, we propose a dynamic gridding approach, to keep a fine scale representation around the thermal front, and a coarser grid away from the front, thus leading to cheaper computations. We will first describe the principles of this dynamic gridding. Simulations will start with an original fine grid, but will reamalgamate its cells, while keeping some regions (for example around wells) always finely gridded. The gridding will then identify the moving front through large gradients of specific properties (temperatures, fluid saturations and compositions). In the front vicinity, it will de-amalgamate the originally amalgamated cells, and later on re-amalgamate them once the front has passed. Amalgamated cells are assigned up-scaled properties, this upscaling being based upon classical averaging techniques. We will illustrate this dynamic gridding technique with simulation examples, as it has been successfully implemented in a thermal simulator, STARS, a product of Computer Modelling Group Ltd (CMG). Using examples on combustion and SAGD simulations, we will show that it can divide the CPU time of thermal simulations by a factor of 2 to 3, without loss of accuracy. Introduction Reservoir flow must be represented accurately when modelling processes such as combustion and SAGD (steam-assisted gravity drainage) in a reservoir simulator. These thermal processes involve convective, diffusive and dispersive flows of fluids and energy, which lead to the formation of fluid banks and fronts moving in the reservoir. Some of these fronts represent interfaces between mobilized oil, which is hot and has had its viscosity reduced, and the more viscous oils which are as yet untouched by heat. Other fronts occur between phases, such as where a leading edge of hot combustion gas moves into an uncontacted oil. These interfaces are thin when compared to the typical cell sizes used to model EOR processes in a simulator, so there will always be problems in properly representing important fluid physics near interfaces. For instance, the choice made for upscaling could depend on the fronts being generated by a process and where they are positioned in the upscaled reservoir cell, while the use of fine scale computational cells throughout the reservoir would be prohibitively expensive. A technique has been presented(1) to address these problems. It suggests using dynamic grid refinement and amalgamation to choose an appropriate cell size near important regions, while using larger cells elsewhere. The ongoing simulation is reviewed periodically and the cells are re-sized depending on the current fluid distribution. The technique is applicable to simulators using sparse matrix solvers and only involves regenerating pointers and properties at selected times during the simulation. Dynamic grid refinement and amalgamation can result in obtaining a several fold decrease in run time while leaving the results unchanged. User-specified thresholds are used to control when to do grid amalgamation or de-amalgamation. The methods described in this paper will be based on differences in property values between amalgamated cells and their neighbours, or differences among values in a finely divided region. The properties chosen will be designed to find fronts, and include saturations and various compositions. Temperature related thresholds will also be used to give an "early warning" for the leading edge of a front. Pressure related differences are not considered, as different pressure levels do not cause difficulties unless they result in front movement, which would be trapped by the thresholds just described The thresholds should be relatively small so that a buffer region of finer cells is maintained around regions of high activity. This choice sacrifices some speed, but maintains accuracy. Note that the simulator requires some kind of efficient adaptive (or fully) implicit formulation to make good use of these techniques, as smaller cells could have high throughputs that require implicitness without resort to small time steps.

In situ combustion is a possible method for producing heavy oil when other methods such as SAGD are not adequate (e.g., in thin beds, or when CO2 emission for steam generation is unacceptable). Previous field trials of this process have often been unsuccessful. However, in recent years, several new well implementations have been proposed (COSH, THAI), exploiting the more advanced drilling capabilities now available. Simulations of such configurations require a reliable representation at field scale of the oxy-combustion reactions, which is not available at the present time. The objective of the work described in this paper is to illustrate some improvements in the description of oxy-combustion reactions both at the experimental level and in the simulation models. A "ramped temperature" experiment has been conducted on an extra heavy stock tank oil (10,000 cP at reservoir conditions). This experiment has been successfully matched using a commercial simulator. The improvement over classical adiabatic reactor experiments is significant: two combustion reactions are clearly observed, and the Arrhenius parameters are determined with increased accuracy. The reliability of the inferred parameter values is checked by applying them to simulations of previous adiabatic disk reactor experiments conducted under a variety of conditions. The final part of the paper is dedicated to illustrating the impact of the new reaction scheme on the simulation results at field scale. Introduction With the more advanced drilling capabilities now available, such as horizontal wells, several new well configurations have recently been proposed for in situ combustion applied to heavy oil [COSH(1), THAI(2)]. To assess the potential of these new configurations by simulation, a reliable representation of the oxy-combustion reactions is required. These reactions govern the oxygen consumption and the time of oxygen breakthrough. Consequently, they will directly influence the efficiency of the recovery process in any given well configuration. Previous authors have addressed the topic of oxy-combustion reactions and kinetics, and a number of publications are available in the literature(3–15). One of the major literature contributors is the University of Calgary, notably due to their work in determining/ proving the presence of the high/low temperature oxidation zones(3, 4). On our side, in order to improve the description of the oxy-combustion reaction scheme both at the experimental level and at the numerical simulation level, we have conducted and simulated a new type of ramped temperature experiment with an extra heavy oil. This new type of experiment has been successfully matched on a commercial simulator (STARSTM from CMG) and has led us to develop a new reaction scheme with two combustion reactions. In the final part of the paper, the impact of this new reaction scheme is evaluated at field scale by comparing numerical simulations made with the old and with the new reaction schemes. Ramped Temperature Experiment Motivations Before developing the ramped temperature experiment, two types of experiments had been developed in Total's Thermal Methods Laboratory in order to determine the kinetic parameters of the oxy-combustion reactions for light oils(9):

Evaluation of compositional effects and fluid flow description on near-miscible (water-alternating-gas) WAG modeling have been studied for a North Sea oil field starting production in 1998. A sector model with four wells was applied to simulate a heterogeneous sandstone reservoir, and a compositional model was used to compare different production strategies e.g. waterflooding and a near-miscible (WAG) injection. In the WAG scheme both dry and wet (rich) hydrocarbon gases have been considered for injection. The phase behaviour was quantified by comparing the performance of the different injection gases. Result obtained shows the WAG injection gives improved recovery compared to water injection, due to better sweep and lower residual oil saturation. Simulations with and without relative permeability hysteresis (two-phase model) were compared. The effect of trapped gas on oil recovery does not seem significant with the compositional model. The WAG process has been optimized with respect to slug size and the water-gas ratio. A black-oil-model was generated tuned to fit the results from the compositional simulations. A WAG three-phase relative permeability hysteresis model using cycle dependent relative permeabilities for both wetting and non-wetting phases, have been compared to the standard two-phase Killough and Carlson hysteresis models. The results show significant lower gas ratio and a higher oil recovery for the WAG injection when using cycle dependent relative permeabilities. The simulations show sensitivity toward the three-phase model whereas Carlsen/Killough type hysteresis has little/no influence on the oil recovery. Simulations indicates that the recovery by WAG-injection may be underestimated in the compositional model due to lack of possibility for cycle dependent relative permeability hysteresis, whereas the black oil model underestimates the phase behaviour effect. The results indicate that the WAG- injection might have an upside potential with respect to the influence of combined phase behaviour and relative permeability effects. P. 233