WO2014089685A1 - Drainage par gravité assisté par injection de vapeur avec ajout d'oxygène ("sagdox") dans des réservoirs profonds - Google Patents

Drainage par gravité assisté par injection de vapeur avec ajout d'oxygène ("sagdox") dans des réservoirs profonds Download PDF

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Publication number
WO2014089685A1
WO2014089685A1 PCT/CA2013/001034 CA2013001034W WO2014089685A1 WO 2014089685 A1 WO2014089685 A1 WO 2014089685A1 CA 2013001034 W CA2013001034 W CA 2013001034W WO 2014089685 A1 WO2014089685 A1 WO 2014089685A1
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steam
reservoir
oxygen
production well
well
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PCT/CA2013/001034
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English (en)
Inventor
Richard Kelso Kerr
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Nexen Energy Ulc
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Priority claimed from US14/083,106 external-priority patent/US20140076555A1/en
Application filed by Nexen Energy Ulc filed Critical Nexen Energy Ulc
Publication of WO2014089685A1 publication Critical patent/WO2014089685A1/fr

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/243—Combustion in situ
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/2406—Steam assisted gravity drainage [SAGD]
    • E21B43/2408—SAGD in combination with other methods

Definitions

  • SAGD Steam Assisted Gravity Drainage
  • EOR thermal enhanced oil recovery
  • Figure 1 shows the "traditional" SAGD geometry, using twin, parallel horizontal wells 2,4 drilled in the same vertical plane. There is a 5 -metre spacing between the horizontal wells 2,4, which are about 800 metres long with the lower well 1 to 2 metres above the (horizontal) reservoir floor. Circulating steam 6 in both wells starts the SAGD process. After communication is established, the upper well 2 is used to inject steam 6, and the lower well 4 produces hot water and hot bitumen 8. Fluid production is accomplished by natural lift, gas lift, or submersible pump.
  • a steam chamber 10 forms around the injection 2 and production wells 4 where the void space is occupied by steam 6. Steam 6 condenses at the boundaries of the chamber 10, releases latent heat (heat of condensation), and heats bitumen, connate water and the reservoir matrix. Heated bitumen and water 8 drain by gravity to the lower production well 4. The steam chamber 10 grows upward and outward as bitumen is drained.
  • Figure 2 shows how SAGD matures.
  • a "young" steam chamber 10 has bitumen drainage from steep chamber sides and from the chamber ceiling. When the chamber growth hits the top of the reservoir, ceiling drainage stops, bitumen productivity peaks, and the slope of the side walls decreases as lateral growth continues.
  • Produced fluids are near saturated-steam temperature, so it is only the latent heat of steam that contributes to the process in the reservoir. But, some of the sensible heat can be captured from surface heat exchangers (a greater fraction at higher temperatures), so a useful rule-of-thumb for net heat contribution of steam is 1000 BTU/lb. for the P, T range of most SAGD projects ( Figure 3 PRIOR ART).
  • the operational performance of SAGD can be characterized by measurement of the following parameters: 1) saturated steam P, T in the steam chamber ( Figure 4 PRIOR ART); 2) bitumen productivity; 3) SOR, usually at the well head; 4) sub-cool target, the T difference between saturated steam and produced fluids; and 5) Water Recycle Ratio ("WRR"), the ratio of produced water to steam injected.
  • the SAGD operator has two choices to make: 1) the sub-cool target T difference and 2) the operating pressure in the reservoir.
  • a typical sub-cool of about 10 to 30°C is meant to ensure no live steam breaks through to the production well.
  • Process pressure and temperature are linked ( Figure 4 PRIOR ART) and relate mostly to bitumen productivity and process efficiency.
  • Bitumen viscosity is a strong function of temperature ( Figure 5).
  • SAGD productivity is proportional to the square root of the inverse viscosity ( Figure 6 PRIOR ART) (Butler (1991)).
  • pressure (and T) is increased, the latent heat content of steam drops rapidly ( Figure 3). More energy is used to heat the rock matrix and is lost to the overburden or other non-productive areas. So, increased pressure increases bitumen productivity but harms process efficiency (increases SOR). Because economic returns can be dominated by bitumen productivity, the SAGD operator usually opts to target operating pressures higher than native or hydrostatic reservoir pressures.
  • SAGD Despite becoming the dominant thermal EOR process, SAGD has some limitations and detractions.
  • the requirements for a good SAGD project are:
  • SAGD can be impaired, as follows:
  • the preferred dominant production mechanism is gravity drainage, and the lower production well is horizontal. If the reservoir is slanted, a horizontal production well will strand significant resources.
  • the SAGD steam-swept zone has significant residual bitumen content that is not recovered, particularly for heavier bitumens and low pressure steam (Figure 7). For example with a 20% residual bitumen (pore saturation) and a 70% initial saturation, the recovery factor is only 71 %, not including stranded bitumen below the production well or in the wedge zone between recovery patterns.
  • Pressure targets cannot (always) be increased to improve SAGD productivity and SAGD economics. If the reservoir is "leaky", as pressure is increased beyond native or hydrostatic pressures, the SAGD process can lose water or steam to zones outside the SAGD steam chamber. If fluids are lost, the Water Recycle Ratio (WRR) decreases, and the process requires significant water make-up volumes. If steam is also lost, process efficiency drops and SOR increases. Ultimately, if pressures are too high, if the reservoir is shallow, and if the high pressure is retained for too long, a surface breakthrough of steam, sand, and water can occur (Roche, P., "Beyond Steam", New Tech. Mag., Sept 201 1).
  • SAGD has the following issues:
  • thermal packer Another way to reduce heat losses is to place a thermal packer downhole to isolate the annulus and steam tubulars.
  • the packer can prevent steam from entering the annulus.
  • Packers are best for cyclic steam processes (CSS) where the packer can reduce casing temperature increases and reduce the chance of casing failure.
  • thermal packers are expensive and are known to leak (Satter, A. "Heat Losses During Flow of Steam Down a Wellbore," Journal of Petroleum Technology July 1965) (Willhite, G.P. et al. "Wellbore Refluxing in Steam Injection Wells," The Journal of Petroleum Technology March 1987).
  • a potential solution to reduce reflux heat losses is to install a packer to isolate steam tubulars from the annulus and to fill the annulus with a (pressurized) gas (e.g. nitrogen) that has low heat conductivity.
  • a gas e.g. nitrogen
  • the purpose of the gas is to have a lower heat transfer than steam and to keep steam out of the annulus.
  • packers have some leakage, and field experience shows that the annulus did not dry out for such systems. Water continued to reflux in the annulus (Willhite (1987)).
  • a potential further solution is to continuously inject inert gas (e.g. nitrogen) into the annulus, with or without a packer or insulated tubing, to dry out the annulus. This can minimize annular water reflux heat losses and dry out insulation (if used).
  • inert gas e.g. nitrogen
  • Carbon dioxide (“C0 2 ”) is the primary non-condensable gas product of in situ combustion (excluding inert N 2 in air). C0 2 is partially soluble in reservoir fluids (oil and water). Deep heavy oil reservoirs have higher native pressures than shallow resources. For example, a 2000-metre deep reservoir has a hydrostatic pressure of about 3280 psi (22.5 MPa), while a 200-metre deep reservoir has a hydrostatic pressure of only 328 psi (2.3 MPa).
  • Figures 10, 1 1 , and 12 show that C0 2 is much more soluble in water than other gases by a factor of about 25 compared to methane.
  • Figure 14 shows that for elevated pressures and temperatures (above about 3000 psia or 20.5 MPa), CO 2 solubility in water is expected to be more than 160 SCF/bbl (Lake, L.W. "Enhanced Oil Recovery,” Prenctice Hall 1989). For deep thermal EOR processes involving C0 2 production, dissolution of C0 2 in water can be a significant sink.
  • C0 2 is also soluble in oil and dissolved C0 2 can significantly reduce oil viscosity to improve oil mobility.
  • Figures 15, 16, 17, 18, 19 shows that C0 2 solubility in oils (including heavy oils) is expected to be about double the solubility in water (Issever, K. et al. "Use of C0 2 to Enhance Heavy Oil Recovery,” No.1998. 14.1 , 1998), (Bennion, D.B. et al "The Use of C0 2 as EOR Agent for Heavy Oil,” Joint Canadian Bulgaria Heavy Oil Symposium, March 1993), (Lake (1989)).
  • dissolution of C0 2 in oil can be a significant sink for C0 2 ( Figure 20).
  • Figure 16 shows that the saturate (paraffinic) fractions of oil are more effective dissolving C0 2 , so one would expect that paraffinic crudes would have the highest C0 2 solubility (Marufuzzanan, M. "Solubility and Diffusivity of Carbon Dioxide, Ethane, and Propane in Heavy Oil” University of Regina, M.A.Sc. Thesis November 2010).
  • Figure 21 shows the combined effects of heat and C0 2 dissolution to reduce bitumen viscosity (Bennion (1993)). As temperature is increased, C0 2 solubility is decreased, so that viscosity reductions due to C0 2 decrease.
  • the current invention involves application and simplification of the SAGDOX process applied to deep, high-pressure bitumen reservoirs.
  • Shallow ( ⁇ 500 metres) average depth reservoirs employing SAGDOX processes require separate removal of non-condensable combustion gases (mostly CO2) using vent gas wells or segregated vent gas sites.
  • the non-condensable vent gas generated by the SAGDOX process may be left to dissolve in the reservoir or production fluids, so that separate (non- condensable) gas removal is not necessary.
  • C0 2 dissolution in bitumen can reduce viscosity and increase bitumen productivity.
  • said hydrocarbon reservoir comprises at least one characteristic selected from the group consisting of: i) an average depth greater than about 500 metres;
  • the horizontal production well is used to produce water and liquid hydrocarbons and is completed within 2 metres of the reservoir bottom;
  • oxygen gas is injected into the hydrocarbon reservoir within 50 metres from the horizontal production well and with a perforation (reservoir contact) zone less than 50 metres in length;
  • the process pressure (in the reservoir) is greater than 800 psia.
  • the oxygen to steam injected is controlled so that produced water to oil (v/v liquid) has a ratio greater than 0.5, preferably the ratio of produced water to oil (v/v liquid) is between 0.5 and 2.0.
  • the hydrocarbon reservoir is positioned at least 500 metres below the ground surface.
  • said steam is injected within 10 metres from the horizontal well, preferably said steam is injected using a parallel horizontal well in the same vertical plane as the horizontal production well and located about 3 metres to 8 metres above the well, more preferably said steam is injected into the reservoir using at least one substantially vertical well selected from the group consisting of a single well or a plurality of substantially vertical wells.
  • said oxygen is injected into the reservoir using at least one well selected from the group consisting of a single substantially vertical well or a plurality of substantially vertical wells.
  • said steam and oxygen are comingled on the surface and injected into the reservoir.
  • said steam and oxygen are segregated, preferably using packers, and injected separately into the reservoir, preferably said steam and oxygen are segregated using concentric tubing and packers with steam in a central tubing of said concentric tubing surrounded by oxygen in an adjacent annulus and said oxygen is injected at a higher elevation of said steam injected into the reservoir.
  • said steam and oxygen are injected into said reservoir using a single substantially vertical well, wherein said single substantially vertical well is completed within 50 metres from the toe of the horizontal production well.
  • the pressures of the process are sufficient so that substantially no free C0 2 is produced in the liquid production well. More preferably, the operating in situ pressure and the ratio of oxygen/steam (v/v) are adjusted so there is substantially no free C0 2 gas found in the horizontal section of the horizontal production well. 4
  • Figure 1 illustrates the "traditional" SAGD geometry.
  • FIG. 2 schematically illustrates the SAGD life cycle.
  • FIG. 3 illustrates the properties of saturated steam.
  • FIG. 4 illustrates saturated steam conditions.
  • Figure 5 illustrates bitumen viscosity vs. temperature.
  • Figure 6 shows the equation for SAGD bitumen productivity.
  • Figure 7 depicts residual bitumen in the steam swept zone.
  • FIG. 8 schematically illustrates the hydraulic limitations of the SAGD Process.
  • Figure 9 illustrates the properties of saturated steam.
  • Figure 10 illustrates Carbon monoxide solubility in water at different temperatures.
  • Figure 1 1 illustrates Methane solubility in water at different temperatures.
  • Figure 12 illustrates Carbon dioxide solubility in water at different temperatures.
  • Figure 13 illustrates Nitrogen solubility in water at different temperatures.
  • Figure 14 illustrates Carbon dioxide solubility in water at different pressures.
  • Figure 15 illustrates Carbon dioxide solubility in bitumen at different pressures.
  • Figure 16 illustrates Carbon dioxide solubility in heavy oil at different pressures.
  • Figure 17 illustrates Carbon dioxide solubility and viscosity reduction.
  • Figure 18 illustrates Carbon dioxide solubility in bitumen.
  • Figure 19 illustrates Carbon dioxide solubility in oil.
  • Figure 20 illustrates CSS retention of Carbon dioxide.
  • Figure 21 illustrates bitumen viscosity dependent on Carbon dioxide.
  • Figure 22 illustrates CSS using steam and Carbon dioxide.
  • Figure 23 illustrates In Situ combustion minimum air flux rates.
  • Figure 24 depicts SAGDOX mechanisms.
  • Figure 25A,B,C depicts SWSAGDOX piping schemes using centralized packers.
  • Figure 26 illustrates the connection of Oxygen requirements on peak temperature.
  • Figure 27 illustrates correlation between Oxygen Pressure and Carbon gas content.
  • Figure 28 illustrates a preferred SAGDOX geometry.
  • Figure 29 illustrates a preferred SAGDOX geometry.
  • Figure 30 illustrates the basic geometry of a SAGDOX process.
  • Figure 31 illustrates the basic geometry of a SAGDOX process with packers.
  • Figure 32 illustrates a preferred geometry of a SAGDOX process with packers on the injection and production wells.
  • Figure 33 illustrates a first preferred embodiment of the Deep well SAGDOX geometry with packers on the injector well.
  • Figure 34 illustrates a second preferred embodiment of the Deep well SAGDOX geometry.
  • Figure 35 illustrates a combustion heat release chart.
  • SAGDOX is an improved thermal enhanced oil recovery (EOR) process for bitumen recovery.
  • the process can use geometry similar to SAGD ( Figure 31), but it also has versions with separate vertical wells or segregated sites for oxygen injection and/or non- condensable vent gas removal ( Figures 28, 29, 30, and 32).
  • the process can be considered as a hybrid SAGD + ISC process.
  • SAGDOX One objective of SAGDOX is to reduce reservoir energy injection costs, while maintaining good efficiency and productivity.
  • Oxygen combustion produces in situ heat at a rate of about 480 BTU/SCF oxygen, independent of fuel combusted (Figure 35 Butler (1991)).
  • Combustion temperatures are independent of pressure and they are higher than saturated steam temperatures ( Figures 3, 26).
  • the higher temperature from combustion vaporizes connate water and refluxes some steam.
  • Steam delivers EOR energy from latent heat released by condensation with a net value, including surface heat recovery of about 1000 BTU/lb. (Figure 3).
  • Table 1 presents thermal properties of steam + oxygen mixtures. Per unit heat delivered to the reservoir, oxygen volumes are ten times less than steam, and oxygen costs including capital charges are one half to one third the cost of steam.
  • the recovery mechanisms are more complex for SAGDOX than for SAGD.
  • the combustion zone is contained within the steam-swept zone 170. Residual bitumen, in the steam-swept zone 170, is heated, fractionated and pyrolyzed by hot combustion gases to produce coke that is the actual fuel for combustion.
  • a gas chamber is formed containing steam combustion gases, vaporized connate water, and other gases (Figure 24). The large gas chamber can be subdivided into a combustion-swept zone 100, a combustion-zone, a pyrolysis zone 120, a hot bitumen bank 130, a superheated steam zone 140 and a saturated steam zone 50 ( Figure 24). Condensed steam drains from the saturated steam zone 150 and from the ceiling and walls of the gas chamber.
  • Hot bitumen drains from the ceiling and walls of the chamber and from the hot bitumen zone 130 at the edge of the combustion front 1 10 (Figure 24). Condensed water and hot bitumen 8 are collected by the lower horizontal well 4 and conveyed (or pumped) to the surface ( Figure 30).
  • vent gas 22 wells or at segregated vent gas sites are collected and removed by vent gas 22 wells or at segregated vent gas sites ( Figures 29, 30, 31 , 32). Process pressures can be controlled (partially) by vent gas 22 production, independent of fluid production rates. Vent gas 22 production can also be used to influence direction and rate of gas chamber growth.
  • SAGDOX delivers both steam and oxygen energy and oxygen gas has 10 times the energy density as steam (Table 1)
  • pipe/tubing sizes for SAGDOX can be smaller (and less costly) than SAGD or other steam EOR processes. This can also reflect on production well sizes because reduced steam injection (with SAGDOX) results in less water production compared to SAGD.
  • Table 5 shows calculated pipe diameters for various SAGD and SAGDOX streams. Design criteria are presented in the table. When fluids use concentric pipe systems and annular flow, the total size of the combined pipe is indicated by brackets. Often pipe costs are proportional to the diameter of the pipe. The total of pipe diameters can also be proportional to total costs. Table 5 shows total pipe diameters can be reduced by using SAGDOX and related processes.
  • Preferred parameters in SAGDOX geometries include:
  • Well pipes/tubing is smaller and oxygen can be transported further distances from a central plant site.
  • ISC In situ combustion
  • Vent gas using oxygen, is mostly C0 2 and may be used for sequestration.
  • vent gas well (or site) is near the top of the reservoir, far from the oxygen injection site
  • vent gas well should be far from the oxygen injector to allow time/space for combustion.
  • Vent gas should not be produced with significant oxygen content
  • Steam is also a superior heat transfer agent in the reservoir.
  • hot combustion gases mostly C0 2
  • steam the heat transfer advantages of steam are evident.
  • the heat available from cooling combustion gases from 500°C to 200°C is about 16 BTU/SCF.
  • the same volume of saturated steam contains 39 BTU/SCF of latent heat - more than twice the energy content of combustion gases.
  • hot combustion gases cool, they become effective insulators impeding further heat transfer.
  • steam condenses to deliver latent heat it creates a transient low-pressure that draws in more steam-a heat pump, without the plumbing. The kinetics also favour steam/water.
  • combustion gas is about 0.31 (mW/cmK) compared to the heat conductivity of water of about 6.8 (mW/cmK) - a factor of 20 higher.
  • SAGDOX sets a steam minimum by a maximum oxygen/steam (v/v) ratio of 1.0 or alternately 50% (v/v) oxygen in the steam and oxygen mix.
  • Figures 28b (THSAGDOX) and 28c (SWSAGDOX) are most preferred for thinner pay resources, with only one horizontal well required. Compared to SAGD, THSAGDOX and SWSAGDOX have a reduced well count and lower drilling costs. Also, internal tubulars and packers should be usable for multiple applications.
  • thermal EOR processes operate close to native reservoir pressures (Roche (201 1 ). As reservoirs become deeper, there is less risk of surface blowouts, but fluid losses can still be an issue.
  • Carbon dioxide is produced as a result of in situ combustion. If oxygen gas is used, C0 2 /0 2 ratios varying from about 0.85 to 0.96 are expected, depending on the fuel consumed and the reaction stoichiometry (Table 4). Some carbon monoxide may form, but it is likely to be converted to C0 2 in the reservoir ( Figure 10).
  • C0 2 will dissolve into bitumen to reduce its viscosity and increase bitumen productivity.
  • C0 2 can reduce bitumen (heavy oil) viscosity by about an order of magnitude (Figure 17). If C0 2 dissolution is combined with heat, it can still contribute to bitumen viscosity reduction, particularly in the periphery of the reservoir where heat has not fully penetrated ( Figure 21).
  • High operating pressures can drive gases (non-condensable gases) into solution in reservoir fluids (bitumen and water).
  • gases non-condensable gases
  • reservoir fluids bitumen and water.
  • IMMBTU of combustion energy per bbl bitumen produced Per MMBTU of combustion energy injected into the reservoir, 2083 SCF of oxygen is injected, and 1910 SCF C0 2 (in the worst case assuming a fuel consumed as CH 5 (Table 4)) is produced.
  • C0 2 solubility in produced hot water is expected to be about 160 SCF/bbl hot water ( Figure 14, at -4000 psi.) (27MPa), and C0 2 solubility in produced bitumen is expected to be about 200 SCF/bbl or more ( Figures 15, 17).
  • 1910 SCF C0 2 for IMMBTU of combustion energy is produced, and our produced fluids can remove about 440 SCF C0 2. This leaves 1470 SCF C0 2 that either resides in the gas chamber in the reservoir, or more likely dissolves in remaining reservoir fluids that are on the periphery of the gas chamber.
  • Figure 20 shows a C0 2 gas retention in the reservoir of about 1500 SCF/bbl bitumen produced (or more) for a lower pressure (-2000 psia) process.
  • undissolved CO should either be controllable or should not build up to levels that inhibit injectivity.
  • SAGDOX has at least one vent gas well to remove non-condensable combustion gases; SAGDOX for deep reservoirs does not require same;
  • the target is deep, high pressure reservoirs (>500 m average depth or >800 psia average pressure);
  • Non-condensable gas preferably C0 2 is dissolved in bitumen; SAGDOX prefers venting of said gas.
  • SAGDOX for deep reservoirs allows for the following:

Abstract

L'invention concerne un procédé permettant de récupérer des hydrocarbures, en provenance d'un réservoir d'hydrocarbures ayant un fond, utilisant un puits de production sensiblement horizontal, le puits de production sensiblement horizontal ayant un pied et une ouverture, le procédé comprenant : (a) l'étape consistant à injecter de l'oxygène dans le réservoir d'hydrocarbures, le puits de production horizontal ayant au moins une zone de perforation à des fins de contact avec le réservoir ; (b) l'étape consistant à injecter de la vapeur dans le réservoir d'hydrocarbures ; l'oxygène produisant de la chaleur in situ et du dioxyde de carbone in situ par combustion et la vapeur produisant de la chaleur in situ par conduction et condensation ; le dioxyde de carbone in situ se dissolvant dans l'hydrocarbure liquide, et abaissant sa viscosité ; (c) l'étape consistant à récupérer les hydrocarbures liquides du réservoir de viscosité réduite en utilisant le puits de production sensiblement horizontal ; et (d) éventuellement l'étape consistant à transporter les hydrocarbures liquides récupérés jusqu'à la surface ; quand le procédé est absent, une étape de retrait de tout gaz non condensable en provenance du réservoir.
PCT/CA2013/001034 2012-12-14 2013-12-12 Drainage par gravité assisté par injection de vapeur avec ajout d'oxygène ("sagdox") dans des réservoirs profonds WO2014089685A1 (fr)

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US201261737327P 2012-12-14 2012-12-14
US61/737,327 2012-12-14
US14/083,106 2013-11-18
US14/083,106 US20140076555A1 (en) 2012-05-15 2013-11-18 Method and system of optimized steam-assisted gravity drainage with oxygen ("sagdoxo") for oil recovery

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CN109339753A (zh) * 2018-09-14 2019-02-15 山东石大油田技术服务股份有限公司 一种采用定向侧钻调整注水井靶点位置重塑井网的方法
CN112302598A (zh) * 2020-11-20 2021-02-02 西南石油大学 一种超深层稠油油藏井下产生蒸汽的系统及方法
CN114427428A (zh) * 2020-10-14 2022-05-03 中国石油化工股份有限公司 底水稠油油藏稳压控水提高采收率方法

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CN112459752A (zh) * 2020-11-15 2021-03-09 五矿盐湖有限公司 空气驱动采卤法中确定空气驱动距离的方法

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WO2008060311A2 (fr) * 2006-02-15 2008-05-22 Pfefferte, William, C. Procédé de récupération cagd de pétrole lourd
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CN102758603A (zh) * 2012-07-10 2012-10-31 中国石油天然气股份有限公司 一种超稠油油藏sagd开采后期注空气开采方法

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US4006778A (en) * 1974-06-21 1977-02-08 Texaco Exploration Canada Ltd. Thermal recovery of hydrocarbon from tar sands
US4512403A (en) * 1980-08-01 1985-04-23 Air Products And Chemicals, Inc. In situ coal gasification
WO2008060311A2 (fr) * 2006-02-15 2008-05-22 Pfefferte, William, C. Procédé de récupération cagd de pétrole lourd
WO2012001008A1 (fr) * 2010-06-28 2012-01-05 Statoil Asa Procédé de combustion in situ à émissions de co2 réduites
CN102758603A (zh) * 2012-07-10 2012-10-31 中国石油天然气股份有限公司 一种超稠油油藏sagd开采后期注空气开采方法

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* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN109339753A (zh) * 2018-09-14 2019-02-15 山东石大油田技术服务股份有限公司 一种采用定向侧钻调整注水井靶点位置重塑井网的方法
CN114427428A (zh) * 2020-10-14 2022-05-03 中国石油化工股份有限公司 底水稠油油藏稳压控水提高采收率方法
CN112302598A (zh) * 2020-11-20 2021-02-02 西南石油大学 一种超深层稠油油藏井下产生蒸汽的系统及方法

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