EP0144203A2 - Gewinnung und Reformierung von ultraschweren Teeren und Öllagerstätten - Google Patents

Gewinnung und Reformierung von ultraschweren Teeren und Öllagerstätten Download PDF

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Publication number
EP0144203A2
EP0144203A2 EP84308156A EP84308156A EP0144203A2 EP 0144203 A2 EP0144203 A2 EP 0144203A2 EP 84308156 A EP84308156 A EP 84308156A EP 84308156 A EP84308156 A EP 84308156A EP 0144203 A2 EP0144203 A2 EP 0144203A2
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EP
European Patent Office
Prior art keywords
flue gases
well
solvent
hydrocarbons
bore
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Application number
EP84308156A
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English (en)
French (fr)
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EP0144203B1 (de
EP0144203A3 (en
Inventor
Bohdan M. Dr. Zakiewicz
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Publication of EP0144203A3 publication Critical patent/EP0144203A3/en
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Publication of EP0144203B1 publication Critical patent/EP0144203B1/de
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E21B43/121—Lifting well fluids
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B43/30—Specific pattern of wells, e.g. optimising the spacing of wells
    • E21B43/305—Specific pattern of wells, e.g. optimising the spacing of wells comprising at least one inclined or horizontal well
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B43/34—Arrangements for separating materials produced by the well
    • E21B43/40—Separation associated with re-injection of separated materials

Definitions

  • This invention relates to the recovery and conversion by reforming of ultra heavy tars and oils from both shallow and deep deposits.
  • Some of those techniques have received limited application in the recovery of medium heavy oil, API gravity in a range between 10° - 22°, with viscosity not much greater than 200 cp (both at 60°F) (16°C) and for a deposit with a medium thickness of 50 - 100 feet (15 - 30 metres).
  • medium-heavy oils just referred to are, by their nature, mobile to a degree in the deposit, but their velocity of gravitational mobility is very low and can be increased by decreasing their viscosity.
  • Two basic thermal techniques of recovery are known for these medium-heavy-oils.
  • steam-drive One technique is usually referred to as “steam-drive”, wherein steam is continuously injected into a formation by means of an injection well.
  • the injected steam heats the formation and medium-viscous hydrocarbons and drives the heated hydrocarbons toward one or more adjacent vertical production wells which are employed to withdraw them to the surface.
  • steam driving process such as:
  • steam, heated gases, combustion gases, or a combination of them is injected into the formation through a single injection well in a batch quantity for a selected period (huff phase).
  • the formation is allowed to "soak", during which time the heat permeates, heating a larger volume of the hydrocarbon reservoir, and the heated mobile hydrocarbons are supposed then to be withdrawable from the formation through the same well during an extraction period (puff phase).
  • the "huff and puff” technique has arisen due to the known inefficiency of the steam and hot water driving methods, in an attempt to deal with heavier oils and thicker deposits.
  • this process basically contradicts the logic of the use of driving forces in the formation, as commonly applied in the production of liquids from boreholes; it delivers small quantities of melted, heated product, and only in the case of a formation thick enough to allow some product to flow into the injection well from the inverted cone region of the formation that is heated by the injection and soak.
  • the major portion of the heated, melted hydrocarbon is repelled in the "huff phase" into peripheral parts of the well region where it impregnates, solidifies in and plugs the pores of the formation.
  • a process for the recovery of heavy and ultra-heavy hydrocarbons from formations containing petroleum deposits comprising: injecting into the formation either concurrently or cyclically:-
  • the recovery is performed in a 'daisy' well having a main central bore and a plurality of slant bores with their lower terminations lying in an array surrounding the central bore.
  • the flue gases are injected at high pressure down the slant bores, the solvent is injected at a lower pressure down the main central bore, and the gas lift is generated in a casing of the main central bore.
  • the flue gases may be obtained from the furnace of a thermochemical reforming plant employed to reform the recovered hydrocarbons into a lighter product adjacent the well head.
  • the solvent may be a highly hydrogenated naphthenic solvent obtained as a fraction from the product output of the thermochemical reforming plant.
  • the invention further provides a well for the recovery of heavy and ultra-heavy hydrocarbons from formations containing petroleum deposits, comprising a main central bore and a plurality of slant bores terminating at their lower ends in an array around the central bore, the main central bore containing at least a passage for delivering solvent downward for injection into the formation and a passage in which extracted hydrocarbons are raised by gas lift, and the slant bores each containing at least a passage delivering hot flue gases downward for injection into the format-on.
  • the main bore is formed at an intermediate level with a chamber having a platform across it, the slant bcres commence at and extend downward from the platform, and above the intermediate chamber the main bore includes also a passage delivering hot flue gases downward to the slant bores.
  • the well may be operated in conjunction with a thermochemical reforming plant adjacent the well head which reforms the reccvered hydrocarbons to produce a pipe-line quality product, said plant including a furnace supplying the hot flue gases for the well, and means for fractioning the plant output to obtain the solvent.
  • the feed stock for the plant is obtained from a 'daisy' well 10 with a central solvent injection and production bore 12 surrounded by six slanting gas injection bores 13.
  • a 'daisy' well can recover as much as 80% of the total accumulation of hydrocarbons over an area of approximately 1 to 1.2 acres (0.4 to 0.49 ha).
  • the feed stock from the annular casing 14 of the production bore 12 which will typically be an emulsion of crude, solvent, water and gas, enters a main separator 11 at elevated temperature and pressure, for example, 450°F (232°C) and 460 PSIG (3 151 x 10 3 N / m 2 ) .
  • Vaporized hydrocarbons are condensed in a condenser 15 which is an inlet stage of gas scrubber 16 from which carbon dioxide and nitrogen are vented.
  • the condenser has a coil which is cooled by raw water pumped from a well or reservoir by a pump 17.
  • the water, after passing through the condenser 15, is introduced into the cooling coil system 18 of the desander-desalter separator 19 from where it passes into a furnace water jacket 20 of a high pressure thermochemical reformer 21 and thence as steam into the coil of a steam superheater 22 at about 450°F (232°C).
  • thermochemical reforming coils 23 Between the water jacket 20 and the steam superheater 22, a by-pass stream is withdrawn at a process control valve 24 and injected continuously, or cyclically, into thermochemical reforming coils 23 through process control valves 25, 26.
  • Superheated steam from the steam superheater 22 is injected into a sand jet-washing system 27 in the main separator 11 where it condenses, and whence it carries entrained sand into the desanding-desalting separator 19.
  • the water is cooled somewhat in the separator 19, and the settling sand is discharged, at 28, by a screw feeder 32.
  • a quencher-hydrogenator 29 Separated, largely de-emulsified crude in solvent, under the internal pressure of the main separator 11, is introduced at a temperature of about 420°F (216°C) into a quencher-hydrogenator 29 in which it is reacted with superheated thermally cracked hydrocarbon,and hydrogen generated principally in the coil system 23 of the thermochemical reformer 21 from which it enters the quencher-hydrogenator usually at a temperature not less than 1300°F (704°C).
  • Quenched and hydrogenated crude under the internal pressure of the quencher-hydrogenator 29 leaves at about 850°F (454°C) and is introduced into a first stage fractionator 30 at an inlet temperature of, for example, 800°F (427°C).
  • the heavy liquid fraction separated in the fractionator 30 is recycled by a pump 33 to the process control valves 26, 25 and through the coils 23 of the thermochemical reformer into the quencher-hydrogenator 29.
  • the light vapour fraction from the fractionator 30 is condensed in an air-cooled condenser 34 and pumped by a pump 36 at about 550°F (288°C) into a second stage fractionator 35, from where the liquid fraction, which is a heavy distillate, is pulped off by a pump 37 and recycled, via a process control valve 44 and the valves 25, 26, through the coils 23 in the thermochemical reformer to the quencher-hydrogenator 29.
  • the lighter vapour fraction from the fractionator 35 is condensed in an air-cooled condenser 38 and pumped by a pump 39 at about 300°F (149°C) to a third stage fractionator 40.
  • the liquid fraction from the third stage fractionator is a final pipeline quality commercial product, up to 40° API gravity, and is pumped away by a pump 41 via process control valves 42, 43 to a final reformed product pipeline 45.
  • vapour fraction from the fractionator 40 is condensed in an air-cooled condenser 46 and injected by a pump 47 via a process control valve 48, at a temperature of about 200°F (93°C), down the central pipe 49 of the production bore 12 to act as hydrogen donor solvent to dissolve and partially reform the in situ crude by non- catalytic hydrogenation in the presence of flue gas components and in reaction with them.
  • the hydrogen donor solvent is a highly hydrogenated naphthene fraction having a boiling range usually between 150° and 250°F (66° - 121°C).
  • the amount of solvent needed for crude sraction is usually approximately 25% by weight of the recovered crude. Further portions of it can be blended with the final product or employed to dilute the hydrocarbon liquids returning to the thermochemical reformer from the first and second stage fractionators.
  • the high pressure, high temperature thermochemical reforming reactor 21 produces high temperature combustion gases and performs the following functions:
  • thermochemical reformer at 800 - 1000°F (427 - 538°C) and 800- 1000 PSI (5480 x 10 3 - 6850 x 10 3N /m 2 ) are fed to the outer casing 50 of the production well and thence into the gas injection bores 13 to react with the hydrogen donor solvent and the in situ crude.
  • Hot water at about 200°F (93°C) is also supplied into the outer casing 50 from the desander-desalter 19 by a pump 51.
  • the thermochemical reforming reactor 21 has a water- jacketed high pressure refractory furnace 52 with a burner system fed by high pressure fuel pumps 53 and a compressor 54 into which the gaseous fraction from the condenser 46 is introduced for use as fuel.
  • the main fuel for the furnace may be gas or liquid hydrocarbon or pulverised coal, but is preferably obtained from the crude being treated in the process. It is injected at high pressure, together with compressed air which can, if desired, be oxygen enriched.
  • the furnace 52 opens into the section of the reactor containing the reforming coils 23, which is followed by the section containing the steam super-heater 22.
  • the system is designed to restrict the decompression and flow of the combustion gases from the furnace so that a high intensity condensed flame is obtained and a very high combustion gas temperature is reached, not less than 3000°F (1649°C).
  • the coil system 23 of the thermochemical reformer has dual interconnected passageways 55, 56 controlled by the process control valves 24, 25, 26. While one pass is charged with heavy hydrocarbons from the fractionators 30, 35 for thermal cracking and coke deposition, the other pass is fed with steam from the by-pass valve 24 to provide a water gas reaction with the deposited coke and generate hydrogen.
  • the hydrogen mixes with the crude and partially refined hydrocarbons and provides the hydrogenation reaction in the quencher- hydro g enator 29.
  • the process control valves 24, 25, 26 are operated to switch the flows of hydrocarbons and steam cyclically between the coil passages 55 and 56 so as to maintain the water gas reaction, but the hydrogen flow into the quencher hydro g enator, and hence the hydrogenation reaction, is substantially continuous. Additional hydrogen is generated in the quencher hydrogenator by reaction of the flue gases with residual steam from the coils 23.
  • the function of the water jacket 20 around the furnace 52 is to raise the water temperature to generate steam for the water gas reaction with the deposited coke.
  • Provision for a large amount of coke deposition is made by enlargement of the diameter of the tubing of each coil to form a coke deposition chamber in which the hydrocarbon flow velocity is decreased, these chambers being situated toward the furnace end of the reforming section where combustion is still continuing around the coils 23 so that the coke deposition chambers are exposed to a very high heat intensity.
  • the coke deposition chambers are constructed from high quality metal alloy resistant to high temperature and high external pressure.
  • the process valves 24, 25, 26 have controllers designed to provide manual or automatic control of the entire water gas reaction in the thermochemical reformer.
  • the slant bores 13 are fitted with internal tubes 60, of smaller diameter than the bore casings 62, to convey the hot flue gases from the thermochemical reformer to discharge filters 61 at the bottom ends cf the slant wells. Seals 59 at the lower ends of the tubes 60 prevent passage of the gases up the bores outside the tubes.
  • the slant wells 13 can, if desired, be drilled from the surface at points close around the main shaft 12, but in the example shown they are drilled from inside the main shaft.
  • the main shaft 12 has a larger diameter upper section 12A and a smaller diameter lower section 12B, the bottom end portion of the larger diameter upper section being constituted as a drilling gas-distributing and product- collecting chamber 63, and the slant wells commence from a platform 64 across the chamber 63.
  • the upper section 12A of the main shaft includes, concentrically arranged and in increasing order of diameter, the central injection pipe 49 for hydrogen donor solvent, the intermediate casing 14 for product upflow, the outer casing 50 for the hot flue gases, and finally the outer bore 65 of the shaft.
  • the lower end of the casing 50 terminates at the roof of the chamber 63 so that the hot flue gases are discharged into the portion of the chamber above the platform 64 thereby to enter the tubes 60.
  • the casings 62 are sealed to the platform 64 and also the gaps between the casings 62 and the tubes 60 are sealed by means of sealing cones 66, but the upper ends of the tubes 60 are open for entry of the hot flue gases.
  • the annular space within the main shaft bore 65 and the casing 50 is filled with thermally-insulating concrete 67.
  • This concrete can be placed by means of a tube lowered initially to the deepest part of the void annular space to be filled and gradually retracted upwards as concrete is injected, keeping the lower end of the tube always beneath the level of the liquid concrete.
  • One or more sliding thermal expansion joins may be provided in the metal casings of the main shaft.
  • the lower section 12B of the main shaft includes, concentrically arranged and in increasing order of diameter, the central solvent injection pipe 49, the intermediate casing 14 for product upflow, and a outer casing 68 with a multiplicity of openings 69 fitted with filters for admitting liquid hydrocarbon product into the annular space between the casings 68 and 14.
  • the casing 68 At the upper end of the casing 68 there are openings 69 lying within and communicating with the portion of the chamber 63 below the platform 64.
  • the casings 62 of the slant wells 13 are likewise provided with openings 70 equipped with filters for the entry of hydrocarbon product into the annular spaces between the casings 62 and the tubes 60, and at the upper ends of the slant wells there are also openings 70 lying within and communicating with the portion of the chamber 63 below the platform 64. Therefore, the hydrocarbon product is able to pass from the casings 22 into the casing 68 by way of the lower portion of the chamber 63.
  • the casings 50 and 68 of the upper and lower sections of the main shaft are sturdily united by the chamber 63 to create an integral robust main shaft casing very resistant to destruction by subsidence of the oil-bearing formation or the overburden.
  • the central injection pipe 49 opens into the lower end of the casing 68 which is formed as a filter outlet 71 into the oil-bearing formation. Seals 72 and 73 prevent the injected solvent from rising around the pipe 49 inside the casings 14 and 68.
  • the lower section of the main shaft can also be provided with small lateral tubes for discharging solvent at different levels in the formation.
  • the upper end of the main shaft is equipped at the surface with a head-tree incorporating control valves far all the downgoing and upcoming fluids and control mechanism for a gas lift pump.
  • a head-tree incorporating control valves far all the downgoing and upcoming fluids and control mechanism for a gas lift pump.
  • the downflow of flue gases, or a portion of it can be switched from the casing 50 into the casing 14 which latter constitutes the gas lift pump tube.
  • Hydrocarbon product and gases from the formation enter the pump tube 14 from the casing 68 through apertures 74, and the regulated entry of further gases into the pump tube lowers the gravity of the product liquid and creates a lifting effect according to the well known air/gas lift principle.
  • the valve of the gas lift pump may be simply a vertically sliding tube for selectively opening and closing gas ports that admit into the pump tube 14 flue gas at comparatively low pressure from the gas distribution chamber 63, or gas at higher pressure from the casing 50. If desired, the flue gases entering the pump tube 14 may be passed in heat exchange with the collected hydrocarbon product that is about to be extracted from the well by means of the gas lift.
  • hot flue gases are injected under . pressure into the formation at the lower ends of the slant wells thereby creating a dynamic heated zone at elevated pressure surrounding the central main shaft in very roughly hemispherical form as indicated by the arrows 75.
  • Hydrogen donor solvent is simultaneously injected at a controlled pressure lower than the flue gas pressure at the bottom of the main shaft.
  • the injected flue gas pressure being higher than the pressure of the injected solvent, a dynamic barrier is created against the outward flow and loss of solvent into the surroundings.
  • the heavy and ultra-heavy hydrocarbons in the formation are partially upgraded and converted into lighter crude in situ by the action of the hydrogen donor solvent at high temperature in the presence of components of the flue gases.
  • the hydrogen donor solvent will be a naphthenic material.
  • the hydrocarbons are thus rendered mobile by the combined actions of dissolution, heat and partial reforming and are impelled toward the central main shaft.
  • a continuous inward flow of hydrocarbon liquids is produced by the displacement actions of the solvent and flue gases and by the fact that the pressure in the vicinity of the main shaft casing is reduced by the gas lift pumping effect in the main shaft, all fluids therefore tending to migrate from the higher pressure injection zones to the region around the main shaft casing.
  • the gas lift pumping is generated by flue gases flowing from the formation together with the liquids into the casings 68 and 14 of the main shaft, augmented if desired by direct introduction of flue gases into the main shaft gas lift from the chamber 63 and/or the casing 50.
  • the locally produced fuel burned in the thermochemical reformer will usually be highly contaminated with sulphur, possibly as much as 5-7% by weight.
  • the flue gases injected into the formation will therefore contain, as major contaminants, S0 2 , NOx and CO, and the formation rock or sand will act as a decontaminating system to strip these from the flue gases.
  • the remaining components, primarily C0 2 and N 2 act as agents in promoting the mobility of the hydrocarbons in the formation already liquefied by the injected solvent.
  • Any water in the formation will be converted in situ into steam by the high temperature flue gases and will augment their action. If desired, further steam can be produced by pumping or injecting waste water from the thermochemical reforming plant into the main shaft casing where it will be gasified by the high temperature flue gases on their way down the shaft.
  • a cyclical, instead of continuous, mode of operation can be employed.
  • the solvent in one phase the solvent can be injected not only at the bottom of the main shaft but also at the bottoms of the slant wells and into the casings 14, 68 of the main shaft, so that it emerges into the formation through the intake filters as well, after which in a second phase flue gases, and steam generated in the main casing, can be injected to sweep the liquefied hydrocarbons toward and into the lift pump casing and generate the gas lift.
  • the hydrogen donor solvent is largely recovered with the hydrocarbon product from the well and is generated in the thermochemical reforming plant for reuse.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
EP19840308156 1983-11-25 1984-11-23 Gewinnung und Reformierung von ultraschweren Teeren und Öllagerstätten Expired EP0144203B1 (de)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB838331534A GB8331534D0 (en) 1983-11-25 1983-11-25 Recovery and reforming ultra heavy tars and oil deposits
GB8331534 1983-11-25

Publications (3)

Publication Number Publication Date
EP0144203A2 true EP0144203A2 (de) 1985-06-12
EP0144203A3 EP0144203A3 (en) 1987-05-20
EP0144203B1 EP0144203B1 (de) 1991-02-27

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DE (1) DE3484177D1 (de)
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Cited By (14)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
RU2161249C1 (ru) * 1999-12-20 2000-12-27 Грайфер Валерий Исаакович Способ освоения месторождений тяжелых нефтей и битумов
RU2226604C2 (ru) * 2000-11-20 2004-04-10 Общество с ограниченной ответственностью "Амбасадор" Способ инжекции стимулятора в скважину и скважинный плунжерный инжектор для его осуществления
GB2425550A (en) * 2005-04-27 2006-11-01 Diamond Qc Technologies Inc Flue gas injection for heavy oil recovery
US7640987B2 (en) 2005-08-17 2010-01-05 Halliburton Energy Services, Inc. Communicating fluids with a heated-fluid generation system
US7770643B2 (en) 2006-10-10 2010-08-10 Halliburton Energy Services, Inc. Hydrocarbon recovery using fluids
EP2233689A1 (de) * 2009-03-27 2010-09-29 Shell Internationale Research Maatschappij B.V. Integriertes Verfahren und System für Säuretraggas und erweiterte Ölwiedergewinnung mithilfe von Säuregas
US7809538B2 (en) 2006-01-13 2010-10-05 Halliburton Energy Services, Inc. Real time monitoring and control of thermal recovery operations for heavy oil reservoirs
US7832482B2 (en) 2006-10-10 2010-11-16 Halliburton Energy Services, Inc. Producing resources using steam injection
US8091636B2 (en) 2008-04-30 2012-01-10 World Energy Systems Incorporated Method for increasing the recovery of hydrocarbons
US10487636B2 (en) 2017-07-27 2019-11-26 Exxonmobil Upstream Research Company Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes
US11002123B2 (en) 2017-08-31 2021-05-11 Exxonmobil Upstream Research Company Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation
US11142681B2 (en) 2017-06-29 2021-10-12 Exxonmobil Upstream Research Company Chasing solvent for enhanced recovery processes
US11261725B2 (en) 2017-10-24 2022-03-01 Exxonmobil Upstream Research Company Systems and methods for estimating and controlling liquid level using periodic shut-ins
CN116812846A (zh) * 2023-06-21 2023-09-29 重庆川维物流有限公司 一种用于港区沥青装卸系统及其方法

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EP1816314B1 (de) 2006-02-07 2010-12-15 Diamond QC Technologies Inc. Mit Kohlendioxid angereicherte Rauchgaseinspritzung zur Kohlenwasserstoffgewinnung

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SU322084A1 (ru) * 1970-03-23 1973-10-26 Устройство для извлечения геотермальнойэнергии
US4008764A (en) * 1974-03-07 1977-02-22 Texaco Inc. Carrier gas vaporized solvent oil recovery method
US4397612A (en) * 1979-02-22 1983-08-09 Kalina Alexander Ifaevich Gas lift utilizing a liquefiable gas introduced into a well
US4222611A (en) * 1979-08-16 1980-09-16 United States Of America As Represented By The Secretary Of The Interior In-situ leach mining method using branched single well for input and output

Cited By (17)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
RU2161249C1 (ru) * 1999-12-20 2000-12-27 Грайфер Валерий Исаакович Способ освоения месторождений тяжелых нефтей и битумов
RU2226604C2 (ru) * 2000-11-20 2004-04-10 Общество с ограниченной ответственностью "Амбасадор" Способ инжекции стимулятора в скважину и скважинный плунжерный инжектор для его осуществления
GB2425550A (en) * 2005-04-27 2006-11-01 Diamond Qc Technologies Inc Flue gas injection for heavy oil recovery
AU2006200466B2 (en) * 2005-04-27 2010-02-18 Diamond Qc Technologies Inc. Flue gas injection for heavy oil recovery
GB2425550B (en) * 2005-04-27 2010-06-02 Diamond Qc Technologies Inc Flue gas injection for heavy oil recovery
US7640987B2 (en) 2005-08-17 2010-01-05 Halliburton Energy Services, Inc. Communicating fluids with a heated-fluid generation system
US7809538B2 (en) 2006-01-13 2010-10-05 Halliburton Energy Services, Inc. Real time monitoring and control of thermal recovery operations for heavy oil reservoirs
US7770643B2 (en) 2006-10-10 2010-08-10 Halliburton Energy Services, Inc. Hydrocarbon recovery using fluids
US7832482B2 (en) 2006-10-10 2010-11-16 Halliburton Energy Services, Inc. Producing resources using steam injection
US8091636B2 (en) 2008-04-30 2012-01-10 World Energy Systems Incorporated Method for increasing the recovery of hydrocarbons
US8820420B2 (en) 2008-04-30 2014-09-02 World Energy Systems Incorporated Method for increasing the recovery of hydrocarbons
EP2233689A1 (de) * 2009-03-27 2010-09-29 Shell Internationale Research Maatschappij B.V. Integriertes Verfahren und System für Säuretraggas und erweiterte Ölwiedergewinnung mithilfe von Säuregas
US11142681B2 (en) 2017-06-29 2021-10-12 Exxonmobil Upstream Research Company Chasing solvent for enhanced recovery processes
US10487636B2 (en) 2017-07-27 2019-11-26 Exxonmobil Upstream Research Company Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes
US11002123B2 (en) 2017-08-31 2021-05-11 Exxonmobil Upstream Research Company Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation
US11261725B2 (en) 2017-10-24 2022-03-01 Exxonmobil Upstream Research Company Systems and methods for estimating and controlling liquid level using periodic shut-ins
CN116812846A (zh) * 2023-06-21 2023-09-29 重庆川维物流有限公司 一种用于港区沥青装卸系统及其方法

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Publication number Publication date
GB8331534D0 (en) 1984-01-04
EP0144203B1 (de) 1991-02-27
EP0144203A3 (en) 1987-05-20
DE3484177D1 (de) 1991-04-04

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