WO2008058298A1 - Procédé et appareil d'introduction d'eau acide sous-saturée dans une formation géologique - Google Patents

Procédé et appareil d'introduction d'eau acide sous-saturée dans une formation géologique Download PDF

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Publication number
WO2008058298A1
WO2008058298A1 PCT/ZA2007/000039 ZA2007000039W WO2008058298A1 WO 2008058298 A1 WO2008058298 A1 WO 2008058298A1 ZA 2007000039 W ZA2007000039 W ZA 2007000039W WO 2008058298 A1 WO2008058298 A1 WO 2008058298A1
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WO
WIPO (PCT)
Prior art keywords
well
gas
aqueous phase
delivering
fluid
Prior art date
Application number
PCT/ZA2007/000039
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English (en)
Inventor
Geoffrey Jackson
Original Assignee
Geoffrey Jackson
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Geoffrey Jackson filed Critical Geoffrey Jackson
Publication of WO2008058298A1 publication Critical patent/WO2008058298A1/fr

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Classifications

    • 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
    • E21B43/164—Injecting CO2 or carbonated water
    • 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
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/005—Waste disposal systems
    • E21B41/0057—Disposal of a fluid by injection into a subterranean formation
    • 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
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/005—Waste disposal systems
    • E21B41/0057—Disposal of a fluid by injection into a subterranean formation
    • E21B41/0064—Carbon dioxide sequestration
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/04—Measuring depth or liquid level
    • E21B47/047—Liquid level
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C20/00—Capture or disposal of greenhouse gases
    • Y02C20/40—Capture or disposal of greenhouse gases of CO2
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
    • Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells

Definitions

  • the present invention relates to the fields of enhanced oil recovery by using carbonated water and the field of geological storage of greenhouse gas to mitigate climate change, in particular, the disposal of gaseous waste in geological formations.
  • the invention is related to the injection of gas-saturated water into the geological formation and the use of fluid levels inside the injection borehole.
  • water aqueous phase and brine are used interchangeably.
  • carbon dioxide is used to describe either pure carbon dioxide, a mixture of gases consisting mostly of carbon dioxide or any water soluble waste gas.
  • the mixture may contain hydrogen sulphide, sulphur dioxide, nitrogen, hydrocarbon gases, water vapour and other impurities typically found in the application of the invention.
  • a critical parameter in a carbonated waterflood is the degree of saturation with carbon dioxide of the aqueous phase, which is defined as the amount of carbon dioxide dissolved as a fraction of the maximum amount that can be dissolved without free gas evolving.
  • the degree of saturation of the water with the gas is a parameter of primary relevance in determining the behavior of the injectant on leaving the injection well and its subsequent interaction with the oil, water and gas in the reservoir.
  • the degree of saturation is controlled by the ratio of carbon dioxide to water injected.
  • the solubility of the carbon dioxide in water is strongly dependent on the pressure, temperature and the chemistry of the water under consideration.
  • the degree of saturation can only be determined from the injection ratio if these parameters are all known to good accuracy at the bottom of the injection well.
  • Downhole pressure and temperature gauges can be combined with either the results of solubility experiments on the injected water or published correlations to determine the degree of saturation.
  • uncertainties in these measurements mean that confidence in the degree of saturation is often poor.
  • the injected water may already contain some unknown or poorly known quantity of carbon dioxide, greatly complicating the calculation of how much extra carbon dioxide can be added before full saturation of the water occurs.
  • thermodynamic parameters In US Patent 6,325,147 the use of state detectors in the injection zone was proposed to measure the thermodynamic parameters and thus control the ratio of aqueous phase and gas injected. No enabling disclosure is provided as to which thermodynamic parameters are to be measured or how these parameters would be translated into control signals. Reference is only made to the preparation of completely saturated solutions or over-saturated solutions in which excess gas is present. It is not intended for aqueous solutions that are under-saturated to any degree.
  • Detection of fluid levels in a borehole is performed in the oil industry, typically for establishing the liquid level in a production well equipped with a downhole pump. Fluids are pumped up a production tubing to surface. This reduces the bottomhole pressure in the annulus between the casing and production tubing, which enhances flow into the well. The liquid level in the annulus is lowered below surface. Generally, this level needs to be maintained some optimum distance above the pump, high enough to cause flow into the pump, but low enough to significantly reduce bottomhole pressures. Such methods and apparatus cannot be applied in the context of an injection well and where the casing-tubing annulus has been sealed a short distance above the apertures in the well casing leading to the geological formation. The current art does not include the use of liquid levels and systems to monitor them in an injection well.
  • the storage of carbon dioxide in aquifers has been proposed as one of the few ways of significantly reducing global emissions of greenhouse gases.
  • the current art for the. storage of carbon dioxide in aquifers is to inject essentially pure, supercritical (dense phase) carbon dioxide directly into an aquifer.
  • An alternative storage technique for carbon dioxide in an aquifer is to inject carbonated water.
  • Carbonated water injection is not currently used for geological storage of carbon dioxide. In addition methods and apparatus to determine and monitor the particular degree of saturation of carbonated water injection are unknown.
  • Any waste gas can be disposed of by injection into buried geological formations.
  • acid gas which is a mixture of hydrogen sulphide and carbon dioxide
  • well known examples are found in the processing of sour natural gas in Alberta, Canada.
  • the gas is first dissolved in water.
  • a well completion for delivering an aqueous phase containing dissolved gas into a geological formation wherein the well comprises:
  • the well casing has a plurality of apertures along a portion of its length.
  • the well casing extends to below the geological formation targeted for injection and the apertures border at least a section of the target geological formation through which the well extends.
  • the well casing may however extend only until the uppermost section of the target geological formation.
  • the well may be deviated from vertical and comprise a casing with apertures on its underside.
  • the injection tubing comprises at least one aperture above the lowest downhole sensor.
  • water is injected through the apertures, which are located above the gas-liquid contact level. Accumulated carbon dioxide above the gas-liquid contact is thereby washed and at least partially dissolved into the aqueous solution.
  • control system and valves controlling the rate of fluid injected into the well are situated on the surface, at the wellhead or even remote from the well. Alternatively some or all of the control system elements may be placed downhole.
  • At least one downhole sensor is used to measure a response of bottomhole pressure to changes in the surface liquid or gas well injection rates.
  • the sensors are thereby enabled to detect the system response time of fluid injection into the well.
  • a plurality of sensor types including a combination thereof, enabled to measure at least one of the following: a) the electrical properties of the surrounding fluid; b) the acoustic properties of the surrounding fluid; c) the density of the surrounding fluid; or d) the pressure gradient in the surrounding fluid.
  • At least two sensors are utilized to detect the gas-liquid contact level of which at least one sensor is a pressure sensor.
  • This sensor configuration optimizes the calibration of the gas-liquid contact level.
  • At least two downhole pressure sensors are located inside the well at different levels and above the highest target entry point through which fluid is injected into the geological formation.
  • At least one sensor may be placed inside a length of ventilated tubing situated in the downhole completion of the well so as to avoid zones of higher flow and turbulence, in use. Multiple sensors may be used to flexibly set the depth of the liquid-gas contact.
  • the well may contain packing material to enhance the mixing of gas and water.
  • the packing material may be comprised of glass spheres or other destruction resistant and inert material that is denser than water and allows an easy flow of fluid through the packing material.
  • a method of delivering an aqueous phase containing dissolved gas into a geological formation comprising the steps of using a delivery apparatus as described above to deliver the aqueous phase.
  • the method comprises the step of establishing the gas-liquid contact above the top aperture of the casing, by adjusting the fluid injection rates.
  • the fluid which comprises an aqueous phase, containing injected carbon dioxide, is close to fully saturated therewith.
  • the under-saturation of and absence of free gas in the injected aqueous phase is ensured by the gravitational segregation of liquid and gaseous phases in the well.
  • the method of delivery of the aqueous phase comprises the steps of first adjusting the gas rate, followed by an adjustment of the liquid rate by means of an automated control system, thereby optimizing delivery.
  • a method of storing carbon dioxide in a geological formation wherein the method and delivery apparatus as described above is employed to deliver an under saturated carbonated aqueous phase into the geological formation.
  • reference to the word tubing implies at least one section of tubing and reference to the word fluid implies at least one type of fluid.
  • the summary of invention forms an integral part of the disclosure.
  • Figure 1 shows a schematic diagram of an apparatus of the invention for injecting carbonated water into a geological formation
  • Figure 2 shows a longitudinal section through a vertical well completion of the invention as shown in Figure 1 ;
  • Figure 3 shows a longitudinal section through another embodiment of a vertical well completion of the invention as shown in Figure 1 ;
  • Figure 4 shows a longitudinal section through another embodiment of a vertical well completion of the invention as shown in Figure 1;
  • Figure 5 shows a longitudinal section through another embodiment of a vertical well completion of the invention as shown in Figure 1;
  • Figure 6 shows a longitudinal section through another embodiment of a vertical well completion of the invention as shown in Figure 1;
  • Figure 7 shows a longitudinal section through a deviated well completion of the invention as shown in Figure 1.
  • figure 1 shows a schematic diagram of a method and apparatus for the delivery of near-saturated carbonated water to a geological formation utilizing carbonated water injection.
  • the apparatus comprises an injection system 10 configured to deliver carbon dioxide and water separately.
  • the method comprises the steps of connecting a source of water 12 to a pump 14, which is connected to a larger diameter injection tubing which extends from the pump through a flow meter 16, a control valve 18 and a wellhead 20 into the well 22.
  • a high pressure source of soluble gas 24 is connected to a smaller diameter injection tubing 26 which extends from the source through a flow meter 28, a control valve 30 and the wellhead into the well.
  • the water and gas tubing are integrated at the wellhead.
  • the gas injection tubing is run inside the water injection tubing and both run to a downhole completion 32.
  • Data from sensors 34 and surface flow meters 16, 28 are transmitted to a control computer 36 which adjusts the injection rates of gas and water by the control valves so as to maintain a gas-liquid contact 38 inside the well at a level above the apertures 40 in the casing abutting the target geological formation.
  • the delivery rate of carbon dioxide and water injected is optimized by first adjusting the gas rate, followed by an adjustment of the water rate.
  • a control system is used to maintain the level of the contact just above the lowermost sensor. If less carbon dioxide is injected than can be dissolved in the water, the accumulation of free gas at the top of the space inside the well will diminish and the gas-liquid contact will move upwards. If more carbon dioxide is injected than can be dissolved in the water, the contact would move down until it reaches the top well casing aperture and free gas enters the formation. Before the contact reaches the top aperture, however, it is detected by sensors and the ratio of carbon dioxide to water is reduced.
  • a stable water injection rate is established.
  • the flowing bottomhole pressure is then monitored continuously as small step changes are made to the surface water rate.
  • These adjustments would be made manually but at the same point on the water injection system as will be used by an automated control system to adjust water rates during continuous injection.
  • This experiment defines the impulse response of the water injection system and in particular, the delay between an adjustment on surface and its downhole expression.
  • the maximum gas rate that could be dissolved in the injected water is then estimated, using the flowing bottomhole pressure, as measured by the pressure sensor in the completion, the temperature of the injected water, which can be measured at surface, and the salinity of the injected water. Gas injection is then initiated at this calculated maximum rate reduced by some margin to take account of uncertainties in the calculation.
  • the downhole sensor an inductive resistivity sensor in the preferred embodiment, should confirm that the fluid immediately above the top perforation is still a liquid. Small decreases in resistivity may be observed as the water is now carbonated. If, however, gas is detected, the gas rate should be reduced and the system allowed to stabilize again. Gas rates should be reduced until the fluid detected by the lowermost sensor is indeed a liquid. Rate adjustments until this stage have been manual.
  • the water has a lower compressibility than gas. Therefore the water injection rate downhole will respond more quickly to a distant surface adjustment than would the gas system. The quicker response makes the control problem easier and enables surface adjustment rather than requiring more expensive downhole rate adjustment equipment.
  • the control system will need to reduce the water rate if, after a certain period of time, a "gas at sensor” signal has not been generated. This is to avoid the gas-liquid contact level rising progressively further above the sensor.
  • a second, higher sensor is employed and the water rate adjusted to maintain the gas-water contact at a level between the two sensors by having the control system seek simultaneous "liquid at sensor” and “gas at sensor” signals from the lower and upper sensors respectively.
  • Multiple sensors may also be advantageous if there is a strong requirement to avoid any free gas entering the geological formation, even for short periods of time.
  • the ratio of carbon dioxide to water can be monitored. If perfect mixing is occurring, this ratio will be the solubility. If mixing is imperfect, the ratio of carbon dioxide to water will be lower since the system avoids free gas injection. Anomalously low ratios may suggest changing the completion to one of the alternative embodiments for better mixing or changing the operating conditions to achieve better mixing.
  • An injection rate to maximize the carbon dioxide to water ratio while not exceeding maximum permissible injection pressures can be found by experiment in the field. For each gas rate, the system finds the corresponding maximum water rate that still avoids free gas injection into the geological formation.
  • the sensors measure the electrical resistivity of the fluid adjacent to the sensor to give a "liquid at sensor” or “gas at sensor” signal.
  • the resistivity of free carbon dioxide is greater than the resistivity of a brine or even fresh waters encountered in the subsurface.
  • Sensors measuring acoustic propagation velocity or the density of the adjacent fluid would also distinguish gas from liquid.
  • the choice of an electrical, sonic or density sensor would be made on the basis of the cost and reliability of such continuous readout, downhole gauges that were available at the time of project execution.
  • Figure 2 shows a vertical well completion 32 in which the water is introduced to the annulus 102 inside the casing 122 by means of tubing 104 immediately beneath a top packer 106 and above a second packer 108 through apertures in the tubing 110.
  • the soluble gas is introduced by a different tubing 112 run inside the water tubing and through a nozzle 114 immediately above the top well casing aperture 116 establishing a gas-water contact 118, in use.
  • a sensor 120 is located above the top well casing aperture to measure fluid properties inside the casing 122.
  • a pressure sensor 124 is included in the string. Ventilation holes 126 in the water tubing beneath the second packer ensure fluid levels in the two annuli are the similar.
  • the packer 106 is set between the casing and the water injection tubing at a distance of 50m above the top perforation. The distance may be reduced to 10m.
  • the packer spacing creates space for the optimum mixing of water and gas.
  • the second packer 108 is set inside the water tubing a short distance below the top packer. Apertures 110 in the water tubing between the levels of the two packers allow injected water to enter the annulus 102 between the casing and tubing. The apertures are sufficiently small to cause the water to spray into the annulus, and large enough to avoid causing excessive pressure drops.
  • the water tubing string 104 is extended some distance beneath the second packer to a level beneath the desired gas-liquid contact and shortly above the top well casing aperture 116.
  • This extension of the water tubing carries the downhole sensors, which are inserted into the string to measure the fluids in the annulus between the carbon dioxide tubing and the water tubing.
  • Apertures in the tubing beneath the second packer put the annulus between the carbon dioxide tubing and water tubing into contact with the annulus between the water tubing and the casing.
  • the apertures should be sufficiently large and well distributed along this interval so as to ventilate the inner annulus and allow for the establishment of a gas-water contact corresponding to that in the outer annulus.
  • the less turbulent conditions inside the inner annulus provide a more suitable measuring environment for the downhole sensors.
  • the carbon dioxide injection tubing 112 extends a short distance beneath this lowermost packer, but ends above the top well casing aperture.
  • the distance between the top aperture and end of the carbon dioxide injection tubing is sufficient for the carbon dioxide jet emerging from the tubing to lose its momentum and to prevent it from entering the casing apertures and the geological formation directly.
  • a nozzle to direct the jet outwards toward the casing or upwards, rather than downwards, is used to minimize the distance needed for this purpose.
  • the water immediately beneath the gas-water contact should be a close as possible to fully saturated with carbon dioxide.
  • the well configuration enables mixing for water arriving at the level of the contact. Downhole mixing of carbon dioxide is enhanced by partially injecting water above the gas-liquid contact level. Such water washes and dissolves accumulated carbon dioxide into the aqueous solution.
  • FIG. 3 shows a vertical well completion 32 in which water is introduced both through small apertures 110 immediately beneath the top packer 106 and also through the water injection tubing 104 extending below the perforations 116 in the casing. The carbon dioxide is injected through a different tubing 112, also extending to below the perforations.
  • Two pressure sensors 140 are fixed to measure fluids in the casing annulus above the top perforation.
  • Figure 4 shows a vertical well completion, similar to that in Figure 2 except that the carbon dioxide injection tubing 112 has been extended to inject the carbon dioxide beneath packing material 142.
  • the packing material is located inside the casing below the lowermost well casing aperture 144 so that gravity effects dominate viscous forces as the free gas moves past the apertures, thereby minimizing the amount of free gas pulled through the perforations by the flow of water. Packing material obstructs the flow of fluids and creates turbulence.
  • the packing material is comprised of glass spheres or other destruction resistant and inert materials that are denser than water and allow an easy flow of fluid through the packing.
  • Figure 5 shows a vertical well completion for co-injected water and gas delivered downhole by a single tubing 150. Fluids enter through apertures in the tubing 110 immediately beneath the top packer 106 and above a plug or end 152 in the tubing. Downhole sensors 154 are situated in the lowermost part of the tubing string to monitor the level of the gas-water contact 118 inside the tubing. Ventilation holes 126 situated along the length of the tubing connect the inside of the tubing with the casing annulus to allow the gas-liquid contact levels in the tubing and annulus to equalize.
  • Figure 6 shows a vertical well completion for co-injected water and gas where the mixture is injected both at the top of the completion 160 and in the rathole 162 below the lowest well casing aperture.
  • Figure 7 shows a modification to the completion for a deviated well 170.
  • Gas is injected from the tubing 112, whose outlet is located below the well casing apertures 116. Only the underside of the well casing extending across the reservoir interval 172 has apertures. The upper side 174 of the well situated across the reservoir is not perforated.
  • the gas bubbles will tend to move along the top side of the casing, rather than being more evenly distributed throughout the water column in the well.
  • the non perforated top casing contains the rising gas within the well, which bypasses the lower well casing apertures and continues into the top of the completion. It will be appreciated that the invention is not limited to the above described embodiments.
  • the phrase "well casing" and "cased borehole” are used interchangeably and make reference to the same aspect of the well completion.

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  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Chemical & Material Sciences (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Geophysics (AREA)
  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)

Abstract

L'invention concerne la réalisation d'un puits et un procédé d'introduction d'une phase aqueuse contenant un gaz dissous dans une formation géologique. Le puits comprend: un trou de sonde tubé ayant une tubulure d'injection permettant l'injection d'un fluide vers le bas du puits; au moins un capteur de fond de trou situé à l'intérieur du puits et au-dessus d'une ouverture ménagée dans le tubage et par laquelle le fluide est injecté dans la formation géologique; un système de contrôle activé pour recevoir et interpréter des signaux émis par le capteur pour détecter un contact gaz-liquide dans le puits et y régler le débit d'injection de fluide afin de maintenir le contact gaz-liquide à un niveau situé au-dessus du capteur de fond de trou.
PCT/ZA2007/000039 2006-11-07 2007-07-02 Procédé et appareil d'introduction d'eau acide sous-saturée dans une formation géologique WO2008058298A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
ZA2006/09288 2006-11-07
ZA200609288 2006-11-07

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WO2008058298A1 true WO2008058298A1 (fr) 2008-05-15

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Cited By (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2013000520A1 (fr) 2011-06-30 2013-01-03 Statoil Petroleum As Procédé pour le stockage de compositions de dioxyde de carbone dans des formations géologiques souterraines et agencement destiné à être utilisé dans de tels procédés
EP2584139A1 (fr) 2011-10-17 2013-04-24 Fundacion Ciudad de la Energia-Ciuden Procédé et système de stockage de gaz solubles dans des formations géologiques perméables
CN105089591A (zh) * 2015-06-19 2015-11-25 中国石油天然气股份有限公司 一种确定注蒸汽井环空气液界面的方法
WO2016010960A1 (fr) * 2014-07-18 2016-01-21 Schlumberger Canada Limited Régulation d'injection d'eau intelligente
WO2015197422A3 (fr) * 2014-06-24 2016-02-18 Maersk Olie Og Gas A/S Procédé et appareil de récupération perfectionnés
JP2018043195A (ja) * 2016-09-14 2018-03-22 株式会社大林組 気体回収システムおよび気体回収方法
JP2018043176A (ja) * 2016-09-12 2018-03-22 株式会社大林組 気体注入システムおよび二酸化炭素地中貯留方法
NO20191345A1 (en) * 2019-11-13 2021-05-14 Arild Ove Aarskog System and method for capturing carbon dioxide (co2) from a flue gas
WO2023225486A1 (fr) * 2022-05-15 2023-11-23 Advantek Waste Management Services, Llc Injection de dioxyde de carbone dissous dans une formation souterraine

Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2869642A (en) * 1954-09-14 1959-01-20 Texas Co Method of treating subsurface formations
US4042029A (en) * 1975-04-25 1977-08-16 Shell Oil Company Carbon-dioxide-assisted production from extensively fractured reservoirs
US6325147B1 (en) * 1999-04-23 2001-12-04 Institut Francais Du Petrole Enhanced oil recovery process with combined injection of an aqueous phase and of at least partially water-miscible gas
US20050217350A1 (en) * 2004-03-30 2005-10-06 Core Laboratories Canada Ltd. Systems and methods for controlling flow control devices

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2869642A (en) * 1954-09-14 1959-01-20 Texas Co Method of treating subsurface formations
US4042029A (en) * 1975-04-25 1977-08-16 Shell Oil Company Carbon-dioxide-assisted production from extensively fractured reservoirs
US6325147B1 (en) * 1999-04-23 2001-12-04 Institut Francais Du Petrole Enhanced oil recovery process with combined injection of an aqueous phase and of at least partially water-miscible gas
US20050217350A1 (en) * 2004-03-30 2005-10-06 Core Laboratories Canada Ltd. Systems and methods for controlling flow control devices

Cited By (10)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2013000520A1 (fr) 2011-06-30 2013-01-03 Statoil Petroleum As Procédé pour le stockage de compositions de dioxyde de carbone dans des formations géologiques souterraines et agencement destiné à être utilisé dans de tels procédés
US9586759B2 (en) 2011-06-30 2017-03-07 Statoil Petroleum As Method for storing carbon dioxide compositions in subterranean geological formations and an arrangement for use in such methods
EP2584139A1 (fr) 2011-10-17 2013-04-24 Fundacion Ciudad de la Energia-Ciuden Procédé et système de stockage de gaz solubles dans des formations géologiques perméables
WO2015197422A3 (fr) * 2014-06-24 2016-02-18 Maersk Olie Og Gas A/S Procédé et appareil de récupération perfectionnés
WO2016010960A1 (fr) * 2014-07-18 2016-01-21 Schlumberger Canada Limited Régulation d'injection d'eau intelligente
CN105089591A (zh) * 2015-06-19 2015-11-25 中国石油天然气股份有限公司 一种确定注蒸汽井环空气液界面的方法
JP2018043176A (ja) * 2016-09-12 2018-03-22 株式会社大林組 気体注入システムおよび二酸化炭素地中貯留方法
JP2018043195A (ja) * 2016-09-14 2018-03-22 株式会社大林組 気体回収システムおよび気体回収方法
NO20191345A1 (en) * 2019-11-13 2021-05-14 Arild Ove Aarskog System and method for capturing carbon dioxide (co2) from a flue gas
WO2023225486A1 (fr) * 2022-05-15 2023-11-23 Advantek Waste Management Services, Llc Injection de dioxyde de carbone dissous dans une formation souterraine

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