Gas injection gas production

IMMISCIBLE AND MISCIBLE GAS INJECTION F Verga Politecnico di Torino OIL RECOVERY OIL RECOVERY Traditionally, oil recovery was subdivided into three stages which described the production from a reservoir in a chronological sense: ! Primary recovery – production existing in a reservoir due to energy naturally ! Secondary recovery – water flooding (and gas injection) for pressure maintenance ! Tertiary recovery – processes that use miscible gas, chemicals, and/or thermal energy to displace additional oil after secondary recovery processes become uneconomical However, many reservoir production operations are not conducted in the specified order Thus, the designation of Enhanced Oil Recovery became more accepted instead of the term “tertiary recovery” in the petroleum engineering literature RECOVERY FACTOR Percentage of displaced oil by the applied process with respect to the oil in place at the start of the process: η = ηMDEηSEηCF ηMDE: Microscopic Displacement Efficiency ηSE ηCF: Macroscopic Displacement Efficiency ηSE: Sweep Efficiency ηCF: Conformance Factor η RECOVERY FACTOR MAGNITUDE Strictly influenced by technical, economical, regulation issues, such as: • Reservoir nature (rock, fluids,…) • Production technologies already available and tested at industrial scale • Oil price • Investment strategy, extraction costs,… • taxation, contract terms and conditions, … WATER AND GAS INJECTION Water or/and immiscible gas injection can be applied for pressure maintenance so as: " To avoid, or to reduce, gas liberation in the reservoir " To avoid, or to reduce, gas flaring " To avoid, or to reduce, artificial lifting to produce oil at the wells INJECTION RATE Water or/and immiscible gas injection should maintain the reservoir pressure slightly above the saturation pressure: Qw,iBw,i = QoBo + Qw,pBw,p + Qg,fBg,f Gas injection rate: Qg,iBg,i = QoBo + Qw,pBw,p + Qg,fBg,f Productivity Index Water injection rate: Pressure (MPa) MICROSCOPIC DISPLACEMENT EFFICIENCY Fraction of the oil initially in place that is recovered from the reservoir volume due to displacement by an immiscible fluid in those places in the rock where the displacing fluid contacts the oil PORE SCALE The microscopic displacement efficiency is reflected in the magnitude of the residual oil saturation MACROSCOPIC DISPLACEMENT EFFICIENCY Pore volume contacted by the displacing fluid divided by the total pore volume of a portion of the reservoir of interest ηSE : Areal Sweep Efficiency Portion of reservoir area contacted by the displacing fluid ηCF : Invasion Efficiency or Conformance Factor Cross-sectional area contacted by the displacing fluid divided by the cross-sectional area enclosed in all layers behind the injected fluid front DISPLACEMENT EFFICIENCY The oil recovery for a water or gas injection exploitation strategy mainly depends on the displacement (sweep) efficiency The oil displacement mechanism depends heterogeneity of the porous media both at the: " Pore scale " Reservoir scale on the PSEUDOTERNARY DIAGRAM Light components (C1, N2) System in which miscibility conditions exist both between primary slug and crude oil, and between primary slug and secondary slug Best displacement process 2-phase area a Point a gives the maximum composition of light component in a primary slug that would be miscible with the oil Range of primary slug compositions that would be miscible with the Oil Oil Heavy components (C7+) Secondary Slug Intermediate components (C2-6) Primary Slug FCM processes A FCM process involves injection of a displacement fluid that forms only a single phase upon first contact when mixed in all proportions with the oil in place (i.e.: butane and crude oil) If the process is used after injection of water with the oil at waterflood residual saturation, the injected solvent must first displace the water phase to contact the residual oil and then the oil as a single-phase mixture A FCM process consists in injecting a relatively small primary slug that is miscible with the crude oil at first contact The primary slug is followed by the injection of a larger and less expensive secondary slug The sizes of the primary slug are determined from economical considerations Ideally, the secondary slug should be miscible with the primary slug Otherwise, a residual saturation of the primary slug material will be trapped in the displacement process MISCIBILITY Atmospheric conditions 2000 PSIA 150° F Mixture Methane Immiscible Oil Propane Miscible Oil Methane Propane Miscible MCM processes In a MCM process the condition of miscibility is generated through in-situ composition alteration of both residual oil in place and injected solvent, resulting from mass transfer between the fluids to such a degree that they become miscible as the solvent moves through the reservoir So in MCM processes, miscibility does not exist initially but is dynamically developed as the process continues The multiple-contact processes are classified in: • Vaporizing-gas displacements • Condensing-gas displacements • CO2 displacements MCM processes • Vaporizing-gas process: the injected fluid is generally a relatively lean gas: low-molecular weight hydrocarbons or inert gases (N2) The composition of the injected gas is modified as it moves through the reservoir so that it becomes miscible with the original reservoir oil; the injected fluid is enriched in composition through multiple contacts with the oil, during which oil intermediate components are vaporized into the injected gas Under proper conditions, the injected fluid of modified composition become miscible with the oil at some point in the reservoir and a miscible displacement will start occurring MCM processes • Condensing-gas process: the injected fluid contains larger amounts of intermediate-molecular-weight hydrocarbons and thus is more expensive Reservoir oil near the injection well is enriched in composition: light hydrocarbon components are condensed from the injected fluid into the oil Under proper conditions, the oil is sufficiently modified in composition to become miscible with additional injected fluid, and a miscible displacement will ensue Typically, this process can be operated at a lower pressure than the vaporizing process MCM processes • CO2 displacement process: miscibility between CO2 and oil develop according to a sort of condensing/vaporizing mechanism CO2 condenses into the oil making it lighter and driving the lighter components out of it These lighter components of the oil vaporize into the CO2 phase making it denser and thus more easily soluble in the oil Mass transfer continues until the resulting two mixtures of CO2enriched-oil and oil-enriched-CO2 become indistinguishable and no interface between the two fluids exists anymore Advantages of CO2 as a solvent In particular, CO2 is effective in improving oil recovery for two reasons: 0.09 0.9 0.08 0.7 CO2 0.6 CH4 0.07 0.06 N2 0.5 Viscosity, cP Density, g/cm3 0.8 0.4 0.3 0.03 0.1 0.01 500 1000 1500 2000 2500 3000 3500 4000 0 500 1000 1500 2000 2500 3000 3500 Pressure, psia Pressure, psia density N2 0.04 0.02 CH4 0.05 0.2 CO2 and viscosity at high pressure, CO2 forms a phase whose density is close to that of a liquid, and much greater than that of either methane or nitrogen, even though its viscosity remains quite low, especially with respect to liquids 4000 MME determination For specified dynamic conditions, the primary slug fluid properties at which miscibility will occur must be determined Miscibility can occur between the solvent gas and crude oil only if the gas has been sufficiently enriched of hydrocarbon components The injected-fluid composition at which miscibility is achieved between solvent gas and crude oil in a multiple contact process, is defined as the Minimum Miscibility gas Enrichment (MME) 100% Oil recovery T=Tr =constant p=pr =constant MME C2+ Mole Fraction MMP determination For specified fluid properties, the dynamic conditions at which miscibility will occur must be determined Miscibility can occur between the displacing gas and oil only if pressure is high enough to liquefy the primary slug The pressure at which miscibility between the solvent gas and crude oil is verified, is defined as the thermodynamic Minimum Miscibility Pressure (MMP) 100% Oil recovery T=Tr =constant constant fluid composition Pressure MMP SLIM-TUBE EXPERIMENT Constant T Air Bath x Cooler Liquid CO2 Oil Constant volume High pressure Pump Vapor Back-pressure regulator SLIM TUBE: • Stainless steel • ID 5/16 in • L 40 ft The best source of thermodynamic MMP is the routine laboratory slim-tube test CO2 EMPLOY IN THE OIL INDUSTRY Economical issues: " Incremental EOR oil production through CO2 miscible displacement of the residual oil in place " Among miscible displacing fluids, CO2 is one of the most abundant and available Environmental issues: " Sequestration of CO2 from carbon dioxide emissions in the atmosphere " Kyoto protocol (1997) constraints due to “greenhouse effect" " Underground storage of CO2 CO2 FLOODS LOCATION CO2 injection has proven to be one of the most efficient EOR methods since it was first tried in 1972 in Scurry County, Texas Since then, CO2 injection has been used successfully throughout the Permian Basin of west Texas and eastern New Mexico, the most intensely CO2 flooded area worldwide ∼ 50% of all the CO2 floods in the world (from U.S DOE, Office of Fossil Energy) CO2 FLOODING APPLICATIONS WORLDWIDE Worldwide % USA/ World 77 88 % Incremental oil production due to CO2 injection [bbl/day] ∼ 170 000 95 % Total incremental oil (EOR) production [bbl/day] ∼ 230 000 90 % CO2 flood Projects (from Oil & Gas Journal, 2002) Effect of wettability on oil recovery by CO2 injection Oil Recovered, % of Hydrocarbon Pore Volume 100 80 60 Oil-Wet Core 40 Water-Wet Core Lineare (Oil-Wet Core) 20 Lineare (Water-Wet Core) 0 20 40 60 80 Vol % Water Simultaneously Injected with CO2 When subjected to simultaneous CO2 /water injection (WAG mode), water-wet cores exhibit reduced oil recovery whereas oil-wet cores not In water-wet rocks, water shields the globules of residual oil from the CO2 “water blocking” effect This microscopic phenomenon can seriously impact the success of a CO2 flood in strongly water-wet formations [...]... displacing front is correspondingly reduced ∂p c 0 if 0 ° < α < 180 ° EFFECT OF OIL VISCOSITY ON fw