Experimental Study of Gas Injection in a Surfactant-Alternating-Gas
- Q. Xu (U. of Texas at Austin) | W.R. Rossen (U. of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- December 2004
- Document Type
- Journal Paper
- 438 - 448
- 2004. Society of Petroleum Engineers
- 1.6.9 Coring, Fishing, 4.1.4 Gas Processing, 1.8 Formation Damage, 5.4.2 Gas Injection Methods, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.5 Reservoir Simulation, 5.3.1 Flow in Porous Media, 5.3.2 Multiphase Flow, 5.5.3 Scaling Methods, 4.1.2 Separation and Treating, 5.4 Enhanced Recovery, 4.3.4 Scale
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Fractional-flow methods have been shown to be accurate and successful in modeling surfactant-alternating-gas (SAG) foam processes. Fractional-flow theory indicates that the success of gas diversion in a SAG process depends on steady-state foam behavior at very low water fractional flow fw(very high foam quality). Previous simulation studies of these processes have relied on extrapolating steady-state data taken at much higher values of fw. Radically different results are predicted depending on how these extrapolations are made. Data are needed at very low fw to predict SAG performance in the field.
Laboratory coreflood experiments were conducted to obtain the needed fractional-flow curves. For each value of fw, constant water- and gas-injection rates were imposed and maintained until the system reached steady state. The corresponding average water saturation in the core was determined by weighing the core continuously during the experiment. Experimental fractional-flow curves are presented for two surfactant formulations in Berea sandstone core, with no oil present, at extremely high foam quality.
Results are then scaled up using fractional-flow theory to a hypothetical field-scale application. In both cases, the data scale up to successful mobility control on the field scale. In one case, foam suffered an abrupt decline from stronger foam to coarser foam with increasing foam quality, with a multivalued fractional-flow function, in agreement with some earlier experimental and theoretical results.
Foams for gas diversion can be placed in the reservoir by continuous coinjection of surfactant solution and gas or by injecting alternating slugs of surfactant solution and gas (SAG injection). Different foam-injection strategies have been used in field trials because of stratigraphic differences, foam behavior, and operational concerns. Shan and Rossen1 list 11 foam field trials with CO2, N2, air, or hydrocarbon/gas foams using different injection strategies. Blaker et al.2 and Skauge et al.3 have reported the more recent, successful SAG injection field trial in the Snorre field.
The main operational conclusion from the field trials is that SAG injection is preferable to coinjection. Skauge et al.3 estimate that the SAG treatment in the Snorre field has contributed approximately U.S. $44 million worth of oil at a hypothetical treatment cost (i.e., if repeated routinely) of approximately U.S. $1 million for this project.
SAG injection has several advantages over coinjection. It minimizes contact between water and gas in surface facilities and piping, which can be important if the gas (for instance, CO2) forms an acid upon contact with water.4,5 Alternating injection of small slugs of gas and water can promote foam generation in the near-well region.6 SAG injection also improves injectivity; as water is displaced from the near-well region during gas injection, foam weakens there, gas mobility rises, and injectivity increases.1,7
If foam has disappeared from the entire formation rather than merely weakened in the near-well region, however, the process fails. This could occur if foam generation fails late in the process. Some studies find that foam generation requires high pressure gradients normally attainable only in the near-well region6,8,9 (although other studies disagree10). The minimum pressure gradient for foam generation depends on gas/water interfacial tension,6 which is much lower for CO2 foams than for the N2 foams used in many laboratory studies of foam generation.11 In fact, the minimum pressure gradient for generation of CO2 foam is even lower than predicted on the basis of its lower surface tension.9 Therefore, this effect may not be as important for CO2 foams used in SAG processes. Moreover, a fixed-pressure SAG process focuses most of the well-to-well pressure drop on the displacement front where foam forms,1 so large pressure gradients are feasible far from the injection well. Therefore, in this study we assume that foam generation is not a limiting factor.
Another reason for concern is that high-mobility gas near the well may finger through or override lower-mobility foam during gas injection. In a homogeneous formation, gravity override represents the worst case of fingering, with gravity and density differences, in addition to viscous instability, driving finger formation at the top of the reservoir. Simulation studies1,7 suggest that at fixed injection rates, high mobility near the injection well promotes gravity override in a SAG process. However, a SAG process at fixed, maximum injection pressure better controls gravity override in homogeneous reservoirs than either continuous foam injection or a fixed-injection-rate SAG process.1,7 Both gas and water should be injected at maximum allowable injection pressure to minimize segregation and reduce surfactant slumping.1 In this way, gravity segregation can be minimized.
The success of SAG processes depends on many factors. Injectivity of the liquid slug was critical in one pilot test, for instance.12 However, foam behavior and possible collapse during gas injection is a major concern. Fractional-flow methods illustrate this concern, as discussed next.
Compared to simulation, fractional-flow methods1,7,12-17 are easy to use and capable of unraveling the essential mechanisms of displacements. With fractional-flow methods, one constructs a "time/distance" diagram for the displacement process from the fractional-flow function fw(S w). The saturation of the aqueous phase (called "water" for simplicity below) Sw at any specific position at any time is indicated on this diagram. Details of fractional-flow methods applied to foam are given elsewhere. 1,7,16,17
Fractional-flow methods make various simplifying assumptions, including immediate attainment of local steady state, absence of viscous fingering, incompressible phases, 1D displacement, Newtonian fluids (mobilities independent of total superficial velocity), and absence of chemical dispersion and significant gradients of capillary pressure. Even in cases in which the assumptions in fractional-flow theory do not apply quantitatively, fractional-flow methods help in unraveling the mechanisms of the success or failure of foam processes.1,16,17 Fractional-flow methods proved accurate and provided key insights into a SAG field test at the Snorre field.12 Fractional-flow methods can accommodate oil along with gas, water, and surfactant,18 but for simplicity here, we consider SAG foam displacements in the absence of oil.
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