WAG May Improve Gas-Condensate Recovery
- A.S. Cullick (Mobil E and P Technical Center) | H.S. Lu (Mobil E and P Technical Center) | L.G. Jones (Mobil E and P Technical Center) | M.F. Cohen (Mobil E and P Technical Center) | J.P. Watson (Mobil E and P Technical Center)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- August 1993
- Document Type
- Journal Paper
- 207 - 213
- 1993. Society of Petroleum Engineers
- 5.6.4 Drillstem/Well Testing, 2.4.3 Sand/Solids Control, 5.8.8 Gas-condensate reservoirs, 5.4.3 Gas Cycling, 5.2.1 Phase Behavior and PVT Measurements, 5.1.1 Exploration, Development, Structural Geology, 6.5.2 Water use, produced water discharge and disposal, 5.3.2 Multiphase Flow, 5.5 Reservoir Simulation, 3 Production and Well Operations, 1.10 Drilling Equipment, 5.4.9 Miscible Methods, 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 5.6.1 Open hole/cased hole log analysis, 4.2 Pipelines, Flowlines and Risers, 1.6.9 Coring, Fishing, 5.7.2 Recovery Factors, 4.6 Natural Gas, 4.1.5 Processing Equipment, 5.2.2 Fluid Modeling, Equations of State, 5.4.1 Waterflooding, 5.4.2 Gas Injection Methods, 5.4 Enhanced Recovery
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This paper shows that the water-alternating-gas (WAG) process may improvesweep efficiency and gas-condensate recovery process may improve sweepefficiency and gas-condensate recovery compared with continuous cycling inhighly stratified reservoirs. The study used extensive numerical simulation toinvestigate the sensitivity of the process to several variables, includingreservoir layering, permeability, relative permeability, capillary pressure,and trapped gas. The process mechanics were confirmed by pressure, and trappedgas. The process mechanics were confirmed by laboratory displacements inlayered core.
Many WAG process applications have been proposed and applied to improvesweep efficiency of injected gas in miscible and immiscible floods in oilreservoirs. Use of WAG to improve sweep efficiency in a gas-cycling,pressure-maintenance process in a gas-condensate reservoir has not beenreported. Gas injected to maintain pressure in gas-condensate reservoirs canlead to early gas breakthrough, low sweep efficiency, disappointing condensateyield, and high compression costs because of gas channeling inhigh-permeability strata. In this computer simulation study, we show that theWAG process improves gas sweep and ultimate recovery. Water increases recoveryby acting as a diverting agent by preferentially entering high-permeabilitychannels and diverting injected dry gas to lower-permeability channels, bysweeping gas condensate out of the low-permeability strata through imbibitionand because of the water's favorable mobility, and by preferentially sweepingthe lower part of the reservoir that is preferentially sweeping the lower partof the reservoir that is unswept by gas. In conventional practice, water is notinjected into a gas-condensate reservoir because of the possibilities of losingreserves to trapped gas condensate, killing wells with water invasion, andreducing injectivity. In contrast to a waterflood, in a WAG process, waterfollows and traps dry gas, not gas condensate; water production can be avoidedby 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. Wepresent detailed results of a fully compositional reservoir simulation of asynthetic layered system and discuss the effects of reservoir and processparameters on WAG performance. We address concerns about potential adverseeffects from water injection and present laboratory displacement data thatdemonstrate the process present laboratory displacement data that demonstratethe process in a two-layer core with different permeabilities.
The purpose of the simulations is to use synthetic, prototype models tostudy process mechanisms in general, not for a particular reservoir. Ourresults from one cross-sectional model compare pressure maintenance operationsby continuous gas injection with pressure maintenance operations by continuousgas injection with those from the WAG process. The model has three strata andapproximately represents a 160-acre inverted five-spot pattern. We use a fullycompositional simulator that incorporates a Peng-Robinson equation of state(EOS) for fluid properties. The Peng-Robinson equation of state (EOS) for fluidproperties. The simulator was described previously.
Model Configuration. The model, called the "three-permeability layermodel," is a "layer-cake" model with three different permeabilitylayers (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 datathat were averaged into three permeability strata (high, moderate, and lowpermeability) by taking a geometric average within the permeability ranges. Thehigh-permeability layer is 8% of the total thickness and has averagepermeability ratios of 100:1 and 10: 1 compared with the low andmoderate-permeability strata, respectively. The 2D cross-sectional model has ahorizontal, 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-welldistance] representing an inverted five-spot well pattern (with constant ydimension) of 160 acres. Continuous gas injection was 82,500 scf/D and reacheda cumulative total of 1.22 HCPV after 23 years. Injection was balanced byproduction. WAG consisted of injecting water at a reservoir volume equal to thegas (240 days of 76-B/D water slug injection) alternately with the gas,beginning the first water cycle after initial gas breakthrough. Each water slugwas 0.035 % HCPV, and the gas/water ratio was 0.92. Fifteen WAG cycles wereperformed during the 23 years. performed during the 23 years. Fluid and RockProperties. Fluids representative of three typical gas-cycling projects werechosen. Table 1 compares the fluid characteristics with those in representativegas-cycling projects. The gas condensate and dry gas were three-componentsynthetic fluids of ethane, propane, and butane. They were assumed to be firstcontact miscible because the pressure was maintained above the gas-condensatedewpoint pressure; the hydrocarbons therefore remained single phase throughoutthe simulation (except for the blowdown sensitivity case). In addition torelative permeability, fluid viscosity and density ratios determine fluid flowcharacteristics (i.e., relative mobility and gravity segregation). For the basecase, 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 Chiericiet al. to be representative of an outcrop limestone. Fig. 2 shows the relativepermeability 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 HCPVinjection; 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 contributeto this improvement. Injected water preferentially enters the 100-md layer atthe injection wellbore, preferentially enters the 100-md layer at the injectionwellbore, reducing gas relative permeability in that stratum. Injected dry gastherefore 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 stratumefficiently and displaces the dry gas from the gas-swept regions; gas useefficiency is increased significantly with WAG. Water also crossbows into thebottom 1-md layers because of gravity. At 1 HCPV total injection, WAG required40% less gas than continuous injection, but recovered 28% more originalcondensate. Fig. 4 compares the fraction of gas condensate remaining at 1 HCPVinjection 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% withcontinuous gas injection.
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