WAG May Improve Gas-Condensate Recovery

Abstract

Summary This paper shows that the water-alternating-gas (WAG) process may improve sweep efficiency and gas-condensate recovery process may improve sweep efficiency and gas-condensate recovery compared with continuous cycling in highly stratified reservoirs. The study used extensive numerical simulation to investigate the sensitivity of the process to several variables, including reservoir layering, permeability, relative permeability, capillary pressure, and trapped gas. The process mechanics were confirmed by pressure, and trapped gas. The process mechanics were confirmed by laboratory displacements in layered core. Introduction Many WAG process applications have been proposed and applied to improve sweep efficiency of injected gas in miscible and immiscible floods in oil reservoirs. Use of WAG to improve sweep efficiency in a gas-cycling, pressure-maintenance process in a gas-condensate reservoir has not been reported. Gas injected to maintain pressure in gas-condensate reservoirs can lead to early gas breakthrough, low sweep efficiency, disappointing condensate yield, and high compression costs because of gas channeling in high-permeability strata. In this computer simulation study, we show that the WAG process improves gas sweep and ultimate recovery. Water increases recovery by acting as a diverting agent by preferentially entering high-permeability channels and diverting injected dry gas to lower-permeability channels, by sweeping gas condensate out of the low-permeability strata through imbibition and because of the water's favorable mobility, and by preferentially sweeping the lower part of the reservoir that is preferentially sweeping the lower part of the reservoir that is unswept by gas. In conventional practice, water is notinjected into a gas-condensate reservoir because of the possibilities of losing reserves to trapped gas condensate, killing wells with water invasion, and reducing injectivity. In contrast to a waterflood, in a WAG process, waterfollows and traps dry gas, not gas condensate; water production can be avoided by designing the process so that only small water slugs and a small total waterprocess so that only small water slugs and a small total water volume are used. Gas injectivity essentially is restored after each water slug injection. We present detailed results of a fully compositional reservoir simulation of asynthetic layered system and discuss the effects of reservoir and process parameters on WAG performance. We address concerns about potential adverse effects from water injection and present laboratory displacement data that demonstrate the process present laboratory displacement data that demonstrate the process in a two-layer core with different permeabilities. Simulation The purpose of the simulations is to use synthetic, prototype models to study process mechanisms in general, not for a particular reservoir. Our results from one cross-sectional model compare pressure maintenance operations by continuous gas injection with pressure maintenance operations by continuous gas injection with those from the WAG process. The model has three strata and approximately represents a 160-acre inverted five-spot pattern. We use a fully compositional simulator that incorporates a Peng-Robinson equation of state(EOS) for fluid properties. The Peng-Robinson equation of state (EOS) for fluid properties. The simulator was described previously. Model Configuration. The model, called the "three-permeability layermodel," is a "layer-cake" model with three different permeability layers (Fig. 1). The model is a prototype developed permeability layers (Fig.1). The model is a prototype developed from reservoir kh core and well-log data that were averaged into three permeability strata (high, moderate, and low permeability) by taking a geometric average within the permeability ranges. The high-permeability layer is 8% of the total thickness and has average permeability ratios of 100:1 and 10: 1 compared with the low and moderate-permeability strata, respectively. The 2D cross-sectional model has a horizontal, 69-ft-thick, 10-md moderate-permeability stratum at the top; an8-ft-thick, 100-md high-permeability stratum in the middle; and a 23-ft-thick,1-md low-permeability stratum at the bottom. Fig. 1 shows the"basecase" model [110 cells (22 X 5) and a 1,870-ft well-to-well distance] representing an inverted five-spot well pattern (with constant ydimension) of 160 acres. Continuous gas injection was 82,500 scf/D and reached a cumulative total of 1.22 HCPV after 23 years. Injection was balanced by production. WAG consisted of injecting water at a reservoir volume equal to the gas (240 days of 76-B/D water slug injection) alternately with the gas, beginning the first water cycle after initial gas breakthrough. Each water slug was 0.035 % HCPV, and the gas/water ratio was 0.92. Fifteen WAG cycles were performed during the 23 years. performed during the 23 years. Fluid and Rock Properties. Fluids representative of three typical gas-cycling projects were chosen. Table 1 compares the fluid characteristics with those in representative gas-cycling projects. The gas condensate and dry gas were three-component synthetic fluids of ethane, propane, and butane. They were assumed to be first contact miscible because the pressure was maintained above the gas-condensate dewpoint pressure; the hydrocarbons therefore remained single phase throughout the simulation (except for the blowdown sensitivity case). In addition to relative permeability, fluid viscosity and density ratios determine fluid flow characteristics (i.e., relative mobility and gravity segregation). For the base case, initial saturations were assumed to be 75% gas condensate and 25% water;trapped gas saturation by water was 28%. The saturation endpoints and 0.1 waterrelative permeability at trapped gas saturation used were reported by Chierici et al. to be representative of an outcrop limestone. Fig. 2 shows the relative permeability curve. Porosity was 12%, and kV/kH was assumed to be 0.5. Base-Case Simulator Results. Fig. 3 shows the recovery curves at 1 HCPV injection; WAG recovery is 78 % of original hydrocarbon in place (OHIP) after19.7 years compared with 61% for gas injection after 19.1 years (a 28%increase. Initial gas breakthrough is at 3.3 years (i.e., at 0.17 HCPV).Relative permeability, viscosity (mobility), and gravity mechanisms contribute to this improvement. Injected water preferentially enters the 100-md layer at the injection wellbore, preferentially enters the 100-md layer at the injection wellbore, reducing gas relative permeability in that stratum. Injected dry gas therefore is diverted to the top 10-md stratum, where it sweeps that stratum. Because of a favorable mobility ratio, injected water sweeps the 100-md stratum efficiently and displaces the dry gas from the gas-swept regions; gas use efficiency is increased significantly with WAG. Water also crossbows into the bottom 1-md layers because of gravity. At 1 HCPV total injection, WAG required40% less gas than continuous injection, but recovered 28% more original condensate. Fig. 4 compares the fraction of gas condensate remaining at 1 HCPV injection for both cases and illustrates the superior sweep achieved with WAG. Almost 90% of the top layer is swept by dry gas in WAG compared with 80% with continuous gas injection. SPERE P. 207