The dissolution of calcite in hydrochloric acid was studied with the aid of a rotating disk system at 800 psig in the temperature range-156-25°C. At 25°C the dissolution process is mass transfer limited even at high disk rotation speeds whereas at-156°C both mass transfer and surface reaction rates limit the dissolution rate. The multicomponent coupled ionic diffusive fluxes of reactants and products were defined by using the gradient of the electrochemical potentials as driving forces for the diffusion. The activity coefficients used in calculating the multicomponent diffusivities of the diffusing species were estimated by Hamed's rule. The concentration protiles of the ions in the boundary layer were then determined by numerically integrating the system of coupled convective diffusion equations. The effects of variable density, viscosity, and high mass fluxes on the fluid velocity in the boundary layer were taken into account. The rate of the surface reaction was found to be proportional to the 0.63 power of the surface hydrochloric acid concentration. Analysis of the experiments suggests that the absorption of hydrogen ion (described by a Freundlich adsorption isotherm) on the solid calcite surface and subsequent reaction of the adsorbed hydrogen ion with the solid calcite matrix is the reaction mechanism. lNTRODUC'IlON

Summary This paper discusses the extension of the steamflood process to the recovery of light oil and the state of the art of this emerging technology. A review of the various steamflood mechanisms indicates that distillation will dominate if steam is injected into light-oil reservoirs. The results of light-oil steamflood laboratory studies, computer simulations, and field projects are also reviewed. A rough screening guide for selecting a light- projects are also reviewed. A rough screening guide for selecting a light- oil steamflood candidate is discussed. New areas of advanced steamflooding technology need to be developed and field tested before light-oil steamflooding can be applied on a routine basis, as is currently the case for heavy-oil steamflooding. Introduction Steam injection is the principal EOR method used today, accounting for 75% of oil produced in the U.S. by enhanced recovery methods. Table 1 delineates the U.S. thermal EOR production from 1976 to 1980. Steamdrive- and steamsoak- (huff ‘n' puff) assisted production has steadily increased from 235,000 B/D [37,362 m3/d] in 1976 to 296,000 B/D [47,060 m3/d] in 1980. The most notable development in the growth of steam-assisted recovery is the increase of steamdrive EOR production. Oil recovered by steamflooding technology has increased from 105,000 to 155,500 B/D [16,694 to 24,723 m3/d] in 5 years, a 48% growth rate in the period 1976–80. Steamsoak production remained fairly constant during this same time period. Table 2 summarizes the number of active thermal EOR projects-- combustion, steamsoak, and steamdrive--during the last 10 years. While there may be some question as to what constitutes a "project," it is clear that the number of steam projects has grown steadily while the number of combustion projects has declined. Again, the number of steamdrive projects has increased dramatically during the last 5 years, from 31 projects in 1976 to 61 projects in 1980. This shift to steamdrive is probably attributable to two factors. One is the relatively high ultimate oil recovery of steamdrive compared with that obtainable by cyclic steam. The other is higher oil prices that have made steamdrive projects economically attractive at the relatively higher steam/oil ratios that are characteristic of steamfloods. What types of reservoirs and reservoir oils are candidates for steamdrives? Farouq Ali and Meldau presented a list of successful steamfloods. Of the 15 successful steamflood projects listed, 7 projects had in-situ reservoir oil viscosities of 1,000 cp [1 Pa s] or projects had in-situ reservoir oil viscosities of 1,000 cp [1 Pa s] or higher. All projects except one were completed at a depth of 2,600 ft [792 m] or less. Reservoir pressures were 300 psi [2.1 MPa] or less for all the projects. These properties are typical of heavy-oil reservoirs that are projects. These properties are typical of heavy-oil reservoirs that are prime candidates for thermal methods because of the effectiveness of heat prime candidates for thermal methods because of the effectiveness of heat in lowering oil viscosity. Included in the steamflood projects reported by Farouq Ali and Meldau are three projects (Brea, Coalinga, Smackover) that are or were conducted in reservoirs containing oils with viscosities of 100 cp [0.1 Pa s] or less. These projects were reported to have steam/oil ratios of 2.8 to 4.0. The Brea field (CA) steamdrive was referred to as a test to determine the feasibility of driving a relatively light (24 API [0.91-g/cm3]), low-viscosity (6-cp [0.006-Pa s]), volatile oil with steam. The definition of light and heavy oil based on crude-oil properties is somewhat arbitrary. The U.S. DOE defines heavy oil as having an API gravity of less than 20 [0.93 g/cm3]. At a recent UNITAR meeting in Caracas, the conference proposed a definition of heavy oil as: "Heavy oil has a gas-free viscosity of 100 to 10,000 centipoise inclusive at original reservoir temperature or a density of 20API to 10API inclusive at 60F at atmospheric pressure."Crude oil (other than tar sand oil) not described by this definition would be classified as medium or light crude oil. A review of the steamdrive projects summarized in an EOR survey indicates that two to four steamdrive projects during the last 10 years could be classified as light-oil or medium-oil steamfloods according to the UNITAR heavy-oil definition. These projects are listed separately from the heavy-oil steamflood projects in Table 2. In 1982, the light-oil steamfloods in progress or announced by the oil industry totaled nine projects. Can steamflood technology be extended economically to light-oil projects. Can steamflood technology be extended economically to light-oil reservoirs? What are the dominant recovery mechanisms during a light-oil steamflood? What are some of the reservoir characteristics for the limited number of successful light-oil steamfloods completed? What are some of the economic and technological barriers that need to be overcome before light-oil steamflooding is applied as routinely as heavy-oil steamflooding is today? This paper discusses the extension of the steamflood process to oil recovery from medium- and light-oil reservoirs and addresses some of these questions. JPT p. 1115

Summary A compositional steam injection simulator was used to study the effects of noncondensable gas injection on oil recovery by steam flooding. Steam flooding oil recoveries resulting from injection of various mixtures of gas and steam were investigated for both light- and heavy-oil reservoirs. The results indicate that noncondensable gas injection with steam can accelerate production significantly early in the life of a typical heavy-oil project, but the cumulative recovery over a 5-year steam injection period is about the same as that obtainable with steam injection alone. The early production increase was seen to result mainly from the additional sweep of the reservoir provided by the injected gas. In a typical light-oil reservoir, the injection of non-condensable gas was seen to accelerate the oil recovery as a result of increased volume of the displacing gas phase and lowering of the oil viscosity by gas dissolution in the oil. There also was a small (6 to 7%) increase in oil recovery over a 5-year steam injection period. This increase is attributable to enhanced steam distillation and viscosity reduction of the oil by oil-soluble gas. Introduction A number of new processes for generating steam, including downhole steam generators, involve injection of noncondensable gas with steam into the reservoir-notably, the downhole steam generator developed by Sandia Natl. Laboratories and Zimpro's surface-operated direct wet air oxidation process. Companies marketing steam generation systems involving simultaneous injection of steam and noncondensable gas (CO2 and N2) have suggested that improved oil production resulting from the presence of a noncondensing production resulting from the presence of a noncondensing gas phase in the reservoir might be possible. Many mechanistic theories have been advanced to support this improved recovery, and some limited laboratory experiments tend to corroborate these theories. However, how oil recovery is affected by a complex, three-phase (water/oil/gas), multicomponent environment generated by gas/steam injection has not been studied in detail. More recently, reservoir simulation studies have evaluated the effects of noncondensable gas injection with steam on heavy-oil recovery. Some of these have shown dramatically accelerated oil recovery when CO2 is injected with steam as compared with steam injection alone. Other studies, however, show that the acceleration is only marginal-not enough to justify the additional costs of noncondensable gas injection. The results of these studies indicate that the response to noncondensable gas injection depends on reservoir and operating conditions and that a more comprehensive study is needed to determine the true potential of gas-steam injection to improve steamflood performance. Our study was carried out to determine if noncondensable gas injection can indeed accelerate and/or increase oil recovery and, if so, which recovery mechanisms contribute to the improved steam flood performance. A thermal compositional simulator was used for this study. Reservoir and Fluid Models Reservoir Grid. The reservoir model was an areal 7 × 4 grid system representing one-eighth of a repeated five-spot pattern (Fig. 1). The area is 5.3 acres [21 450 m 2]; the distance between the injector and producer is 340 ft [ 104 m]. The area was divided into seven blocks in the x direction, parallel to the line between the injecter and the producer, and four blocks in the y direction. Apex cells in the three corners of the triangle were combined with blocks adjoining them, resulting in a total of 22 active blocks in each layer. The massive 100-ft [31-m] sand was divided equally into four layers, all of which were open to injection and production. production. Reservoir Properties. Two types of reservoirs were considered for this study: heavy oil and light oil. The heavy-oil reservoir is characterized by shallow depth (less than 1,000 ft [305 m]), high permeability (4,000 md), and a spongy formation (compressibility: 2 × 10 -3 psi -1 [2.9 × 10–4 kPa -1). The initial oil saturation is 60 %; the initial oil in place (OIP) in the one-eighth of a five-spot is 100,000 bbl [15 900 m3] for the 100-ft [31-m] thick sand. The light-oil reservoir, on the other hand, is typified by a greater depth (more than 2,500 ft [762 m]), lower permeability (40 md), and a less compressible formation permeability (40 md), and a less compressible formation (compressibility: 5 × 10 -5 psi -1 [7.25 × 10 -6 kPa -1 ]). The initial oil saturation is 40%; the initial OIP is 64,500 bbl [10 250 m3] for the 100-ft [31-m]-thick sand. Table 1 shows important reservoir parameters used in the simulation study for both reservoir types. In all cases, the reservoir properties were assumed uniform. The vertical permeability was assumed to be 50% of the horizontal permeability. permeability. JPT P. 2160

The experimental variables that atfect the acidixation of sandstone cores in a permeameter are discussed. It was found that as HCl/HF acid mixtures are injected into porous sandstone cores a reaction front between selective minerals and the acid is formed. This reaction front and a corresponding permeability front move through the core with a constant axial velocity. The time for the permeability front to move through the core is detined as the breakthrough time. The breakthrough time is directly proportional to the core length but inversely proportional to the HP acid concentration and the rate of injection, 0 dimensionless time, t/T p fluid viscosity, centipoise 4 porosity v stoichiometric coefficient 7 space time (time to fill one pore volume of core), min RFJEIWNCES

The chemical kinetics of solid-liquid reaction rate limited and depends reactions were studied for different on both the HF and HC1 concentrations mud acid-mineral systems in a rotating in the mud acid. disk apparatus.The minerals studied included calcite, dolomite, microcline,