US20120312534A1 - Enhanced hydrocarbon recovery through gas production control for noncondensable solvents or gases in sagd or es-sagd operations - Google Patents

Enhanced hydrocarbon recovery through gas production control for noncondensable solvents or gases in sagd or es-sagd operations Download PDF

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Publication number
US20120312534A1
US20120312534A1 US13/471,928 US201213471928A US2012312534A1 US 20120312534 A1 US20120312534 A1 US 20120312534A1 US 201213471928 A US201213471928 A US 201213471928A US 2012312534 A1 US2012312534 A1 US 2012312534A1
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Prior art keywords
gas
production
injection
steam
flow
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English (en)
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Tawfik N. Nasr
Thomas J. Wheeler
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ConocoPhillips Co
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ConocoPhillips Co
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Priority to US13/471,928 priority Critical patent/US20120312534A1/en
Assigned to CONCOPHILLIPS reassignment CONCOPHILLIPS ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: NASR, TAWFIK N, WHEELER, THOMAS J.
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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
    • E21B43/16—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
    • 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
    • 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
    • E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
    • E21B43/168—Injecting a gaseous medium

Definitions

  • the present invention relates generally to methods and systems for enhancing hydrocarbon recovery through gas production control for noncondensable solvents or gases in SAGD or ES-SAGD operations.
  • Low mobility reservoirs are characterized by high viscosity hydrocarbons, low permeability formations, and/or low driving forces. Extraction of high viscosity hydrocarbons is typically difficult due to the relative immobility of the high viscosity hydrocarbons.
  • some heavy crude oils, such as bitumen are highly viscous and therefore immobile at the initial viscosity of the oil at reservoir temperature and pressure. Indeed, such heavy oils may be quite thick and have a consistency similar to that of peanut butter or heavy tars, making their extraction from reservoirs especially challenging.
  • SAGD Steam Assisted Gravity Drainage
  • Solvent injection processes present other challenges. While solvent injection processes typically require less energy as compared to steam injection processes, the solvent injection processes generally require large volumes of expensive solvent and result in significant, costly solvent loss in the reservoir. These costly solvent losses often render solvent injection process economically disadvantageous.
  • the present invention relates generally to methods and systems for enhancing hydrocarbon recovery through gas production control for noncondensable solvents or gases in SAGD or ES-SAGD operations.
  • One example of a method for enhancing recovery of bitumen or heavy oil from a low mobility reservoir comprises the steps of: providing one or more injection wells wherein the one or more injection wells intersect the heavy oil reservoir; providing one or more production wells wherein the one or more production wells intersect the heavy oil reservoir; wherein the one or more injection wells and the one or more production wells are paired to form a SAGD or ES-SAGD process; producing steam via a steam generator wherein flue gas is produced as a byproduct of the steam generator; introducing the steam into one of the one or more injection wells; introducing the flue gas into one of the one or more injection wells; allowing a production flow to be produced from the one or more production wells wherein the production flow comprises a production gas flow and a production water flow; determining a production gas-to-water ratio as a ratio of the production gas flow to the production water flow; and limiting the production flow to obtain a production gas-to-water ratio in the production flow from about 1 to about 30.
  • One example of a method for enhancing recovery of bitumen or heavy oil from a low mobility reservoir comprises the steps of: providing an injection well wherein the injection well extends into the heavy oil reservoir via an upper horizontal well; providing a production well wherein the production well extends into the heavy oil reservoir via a lower horizontal well; continuously introducing steam and a non-condensable gas into the injection well; allowing a production flow to be produced from the production well wherein the production flow comprises a gas flow and a water flow; determining a production gas-to-water ratio as a ratio of the production gas flow to the production water flow; and limiting the production flow to obtain a production gas-to-water ratio from about 1 to about 10.
  • FIG. 1 illustrates an example of an enhanced heavy oil recovery system in accordance with one embodiment of the present invention.
  • FIG. 2 illustrates another example of an enhanced heavy oil recovery system incorporating a direct steam generator.
  • FIG. 3 shows a graph of monthly average water injection rate as a function of time comparing the cases of uncontrolled gas production and controlled gas production.
  • FIG. 4 shows a graph of injection pressure versus time comparing the cases of uncontrolled gas production and controlled gas production.
  • FIG. 5 shows a graph of monthly averages of gas-to-water ratios (GWR) versus time comparing the cases of uncontrolled gas production and controlled gas production.
  • GWR gas-to-water ratios
  • FIG. 6 shows a graph of cumulative oil production versus time comparing the cases of uncontrolled gas production and controlled gas production.
  • FIG. 7 shows a graph of cumulative steam-to-oil ratio (SOR) versus time comparing the cases of uncontrolled gas production and controlled gas production
  • FIGS. 8A , 8 B, and 8 C show a series of performance comparisons.
  • FIG. 8A shows a comparison of cumulative SOR.
  • FIG. 8B shows a comparison of reduction in percent SAGD SOR.
  • FIG. 8C shows a comparison of percent increase in SAGD cumulative oil.
  • the present invention relates generally to methods and systems for enhancing hydrocarbon recovery through gas production control for noncondensable solvents or gases in SAGD or ES-SAGD operations.
  • a plurality of wells intersects a low mobility reservoir.
  • Steam may be injected into one or more injection wells to heat the reservoir hydrocarbons and reduce their viscosity so that hydrocarbons may be produced by way of one or more production wells.
  • the injection wells may be arranged and paired with the production wells to form a SAGD process or where solvents are used, an ES-SAGD process.
  • a noncondensable gas may be injected into one or more of the injection wells to beneficially reduce the steam-to-oil ratio thus improving economic recovery.
  • gas production rates at the production wells may be controlled to optimize hydrocarbon output by limiting the produced gas-to-water ratio (GWR) to limited ranges, including ranges of about 1 to about 30.
  • GWR gas-to-water ratio
  • the noncondensable gas may comprise a gas from the combustion exhaust of a control device or from a steam generator (e.g. flue gas).
  • a gas from the combustion exhaust of a control device or from a steam generator (e.g. flue gas).
  • flue gas e.g. flue gas
  • Advantages of such enhanced hydrocarbon recovery processes include, but are not limited to, higher production efficiencies, lower steam-to-oil ratios, lower costs, a reduction of total extraction time of in-situ hydrocarbons, and in some embodiments, a reduction of greenhouse gas emissions.
  • FIG. 1 illustrates an example of an enhanced hydrocarbon recovery system in accordance with one embodiment of the present invention.
  • Low mobility reservoir 115 is shown residing in subterranean formation 110 .
  • Reservoir 115 suffers from low mobility of the hydrocarbons therein due in part to high viscosity of the hydrocarbons, low permeability, and/or low driving forces.
  • Injection well 120 and production well 125 both intersect low mobility reservoir 115 .
  • Injection well 120 is provided for introducing injected flow 121 into low mobility reservoir 115 by way of injection well 120
  • production well 125 is provided for extracting production flow 126 by way of production well 125 .
  • injection well 120 is superposed above production well 125 .
  • Steam 137 is introduced into injection well 120 .
  • steam 137 enters low mobility reservoir 115 , heats the hydrocarbons therein to reduce their viscosity and so, increases their mobility.
  • the heated hydrocarbons flow under the influence of gravity towards production well 125 along with any condensed steam.
  • the hydrocarbons and condensed steam are produced by way of production flow 126 from production well 125 .
  • a circulation pattern develops between injection well 120 and production well 125 , and a SAGD steam chamber develops around injection well 120 .
  • SAGD steam-to-oil ratio
  • SOR steam-to-oil ratio
  • GWR gas-to-water ratio
  • excessive noncondensable gas production can adversely affect hydrocarbon recovery.
  • excessive noncondensable gas production can decrease the relative permeability of hydrocarbons near the production well and decrease production.
  • noncondensable gas when injected at steam chamber conditions, exhibits limited solubility in the fluids within the steam chamber at these conditions. Slight changes in temperature can have a substantial effect on the solubility of these noncondensable gases and promote evolution of the noncondensable gas back into the steam chamber. This results in lower temperatures at the hydrocarbon drainage interface due to the partial pressure effects of the noncondensable gas and impacts the rate at which oil is produced. These noncondensable gases also tend to move towards the production well thus increasing the gas saturation and decreasing the permeability of hydrocarbons in the near production well region. These factors can negatively impact performance and adversely affect the economics of oil recovery.
  • Gas production rates may be controlled to optimize efficiency of the process.
  • production flow 126 may be modulated to enhance hydrocarbon recovery by reducing the produced gas-to-water ratio (GWR), leading to reduced steam-to-oil ratios and consequently, higher efficiencies.
  • the gas-to-water ratio may be determined with reference to the ratio of the volume fractions of gas and liquid from liquid/gas separator 140 .
  • production flow 126 may be modulated by production control valve 126 to achieve a gas-to-water ratio in the production flow of about 1 to about 30, of about 1 to about 10, of about 1 to about 5, of about 1 to about 2, of about 5 to about 10, or any combination thereof.
  • limiting the gas-to-water ratio to these ranges can significantly improve production efficiencies.
  • Noncondensable gas 135 being injected into injection well 120 may comprise any gas that does not condense at any of the reservoir temperature and pressure conditions.
  • suitable noncondensable gases include, but are not limited to, methane, ethane, propane, butane, air, oxygen, nitrogen, hydrogen, carbon dioxide, carbon monoxide, combustion gases from a control device or other direct combustion device, combustion gases from a direct steam generator, flue gas, or any combination thereof.
  • the amount of noncondensable gas that is introduced varies and may include gas-to-water ratios from about 1 to about 1,000. In certain other embodiments, the gas-to-water ratio in the injected flow varies from about 20 to about 100.
  • the noncondensable gas may comprise two or more noncondensable gases in some embodiments.
  • solvent 139 may be introduced to further enhance the efficiency of the hydrocarbon recovery process by, for example, further reducing the viscosity of the low mobility hydrocarbons.
  • suitable solvents include, but are not limited to, carbon dioxide, an aliphatic hydrocarbon having 4 carbons to 30 carbons, a light non-condensable hydrocarbon solvent having 1 to 4 carbons, naptha, Syncrude, diesel, an aromatic solvent, toluene, benzene, xylene, hexane, or any combination thereof.
  • steam, solvents, or noncondensable gases described herein may be introduced to the low mobility reservoir continuously or intermittently, sequentially or combined, or any combination thereof as desired.
  • FIG. 2 illustrates another example of an enhanced hydrocarbon recovery system.
  • steam generator 230 is shown generating steam 237 from water feed 231 .
  • a fuel source 233 such as natural gas and an oxidant 232 (e.g. air or oxygen) are fed to direct steam generator 230 to provide the combustion heat necessary to generate heat required to convert water feed 231 to steam 237 .
  • fuel source 233 As fuel source 233 is combusted, it converts to combustion products, namely flue gas 235 .
  • Flue gas 235 may be introduced to injection well 220 as a noncondensable gas similar to noncondensable gas 135 depicted in FIG. 1 .
  • using flue gas 235 advantageously reduces green house gas emissions by diverting flue gas 235 to a useful application.
  • any other effluent from a control device or other effluent from direct combustion device may be substituted for flue gas 235 as desired.
  • a fraction of fuel source 233 may be combined with flue gas 235 to achieve optimal compositions of injection flow 221 .
  • flue gas 235 combines with steam 237 to form combined injection flow 221 which is introduced into injection well 220 .
  • Hydrocarbons along with condensed steam and any noncondensible gases are produced via production well 225 to form combined production flow 226 .
  • the process may be controlled to limit total production flow 226 to an amount that optimizes the gas-to-water ratio.
  • One way of achieving this control is illustrated by the control loop depicted in FIG. 2 .
  • Gas meter 241 measures the flow rate of gas flow 241
  • liquid meter 242 measures the flow rate of liquid flow 242 .
  • These flow rates may be converted to a ratio of volume fractions and transmitted to controller 245 which modulates control valve 228 to achieve a desired gas-to-water ratio.
  • DSG direct steam generator
  • steam generator 230 could be substituted in place of steam generator 230 .
  • direct steam generators output the steam and flue gas as a single combined stream, in such a case, steam 237 and noncondensable gas 235 would be combined into a single output stream which would then be available for introducing into wellbore 220 .
  • a solvent 239 could be optionally introduced into wellbore 220 .
  • An athbasca oil sands reservoir of 100 m in width by 30 m in height by 850 m in length was used for the study.
  • Two (850 m long) horizontal wells were placed near the bottom, and in the middle, of the reservoir and separated by 5 m in the vertical direction.
  • the lower horizontal well was placed I m above the bottom of the oil bearing sands.
  • a pre-heating period of 90 days was used to heat the region between the wells by circulating steam in both the injection and production wells (similar to field pre-heating for SAGD).
  • a baseline case where steam-only was injected was used for comparison with a steam-butane case where the butane gas production rate was controlled and a steam-butane case where butane gas production rate was uncontrolled. In all cases, a maximum bottom hole injection pressure of 3.5 MPa was used.
  • steam was injected into the top well and oil and water was produced from the bottom well.
  • steam-butane cases following pre-heating, a mixture of steam-butane at a volume fraction of 0.016 steam and 0.984 butane gas was injected into the top well and oil, water and butane was produced from the bottom well. The volume fraction was selected to demonstrate the concept.
  • butane volume fractions ranging from about 0.001 to about 0.999 may be used.
  • the objective of adding the butane to steam was to evaluate the potential for oil production with less energy as compared to steam alone.
  • the injected gas would help in maintaining the reservoir pressure and reduce oil viscosity and hence reduce steam energy requirements.
  • the numerical simulator adjusted the total fluid injection rate (steam in the case of SAGD and steam-gas in the case of butane co-injection) to maintain the maximum injection bottom-hole pressure at 3.5 MPa.
  • FIG. 3 shows that the steam injection rate for the SAGD process was the highest and for the steam-butane with controlled gas production rate was the lowest. This data illustrates a significant saving in steam requirements for the controlled gas production case as compared to the SAGD process.
  • FIG. 4 illustrates that a maximum injection bottom-hole pressure of 3.5 MPa was practically maintained throughout the entire period of injection, 5,000 days, for all three cases. After 5,000 days, injection was stopped and production continued for all cases.
  • gas production rate at the producer was controlled to optimize efficiency of the process.
  • This control limited the produced gas-to-water ratio (GWR) to a range of about 1 to about 10.
  • GWR gas-to-water ratio
  • This control may be implemented in the field via a control loop in conjunction with a gas/liquid meter and a control valve installed on the production well at the surface.
  • FIG. 5 illustrates a comparison between the controlled and uncontrolled produced GWR. In the uncontrolled case, a produced GWR as high as 55 was obtained and this negatively impacted the performance of the process.
  • the process performed at a significantly improved level as compared to SAGD and the uncontrolled gas production rate cases.
  • FIG. 6 illustrates that at the end of the injection period, 5,000 days, the controlled gas production case produced more oil as compared to SAGD and the uncontrolled gas production cases (613,649 m 3 versus 542,410 m 3 and 596,341 m 3 ; respectively).
  • FIG. 7 illustrates that a cumulative steam-to-oil ratio (SOR) of 1.6 was obtained from the new concept as compared to 3.2 for SAGD and 2.1 for the uncontrolled gas production case. This results in significant improvement in energy efficiency and reduced water requirement and greenhouse gas emissions by using the new concept.
  • FIG. 7 demonstrates that the improved thermal efficiency is maintained throughout the life of the process, thus improving the overall economics of recovery.
  • FIG. 1 illustrates that at the end of the injection period, 5,000 days, the controlled gas production case produced more oil as compared to SAGD and the uncontrolled gas production cases (613,649 m 3 versus 542,410 m 3 and 596,341 m 3 ; respectively).
  • FIG. 7 illustrates that a cumulative steam-
  • Table 1 below and FIG. 8 summarize the benefits of the produced gas control concept as compared to SAGD and the uncontrolled gas production cases.
  • non-condensable solvent examples include, but not limited to, methane, ethane, propane, butane, air, oxygen, nitrogen, hydrogen, carbon dioxide, carbon monoxide, combustion gases from a control device or other direct combustion device, combustion gases from a direct steam generator, flue gas, or any combination thereof.
  • the flue gas may be obtained from any industrial fuel burning installation for example, a steam generator, a direct steam generator (DSG), or a combustion device.
  • non-condensable additive was injected with the steam in a continuous manner; however, an alternative injection strategy may include injecting the additives intermittently or sequentially with steam at different time intervals.
  • an alternative injection strategy may include injecting the additives intermittently or sequentially with steam at different time intervals.
  • the concept maybe used in any steam injection processes including SAGD and steam flooding.

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Cited By (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20140251608A1 (en) * 2013-03-05 2014-09-11 Cenovus Energy Inc. Single vertical or inclined well thermal recovery process
WO2014182933A1 (fr) * 2013-05-08 2014-11-13 Conocophillips Company Polyol pour ameliorer l'efficacite de balayge dans des gisements de petrole
US20150083413A1 (en) * 2013-09-20 2015-03-26 Conocophillips Company Reducing solvent retention in es-sagd
WO2014195443A3 (fr) * 2013-06-07 2015-06-18 Maersk Olie Og Gas A/S Procédé amélioré de récupération de pétrole
CN104847321A (zh) * 2014-02-18 2015-08-19 中国石油化工股份有限公司 一种用于超深层稠油的水平井热化学采油方法
US20170314378A1 (en) * 2016-04-27 2017-11-02 Highlands Natural Resources, Plc Method for forming a gas phase in water saturated hydrocarbon reservoirs
US11125063B2 (en) 2017-07-19 2021-09-21 Conocophillips Company Accelerated interval communication using openholes
US20210396106A1 (en) * 2020-06-18 2021-12-23 Cenovus Energy Inc. Non-condensable gas management during production of in-situ hydrocarbons

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CN104975833A (zh) * 2014-04-03 2015-10-14 中国石油化工股份有限公司 蒸汽-降粘剂辅助重力泄油采油方法
CN106761626A (zh) * 2016-12-02 2017-05-31 中国石油天然气股份有限公司 双水平井过热蒸汽辅助重力泄油井网和开采方法
CN116084916A (zh) * 2023-02-21 2023-05-09 中海石油（中国）有限公司天津分公司 油藏蒸汽驱经济极限采收率的确定方法

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Cited By (11)

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Publication number Priority date Publication date Assignee Title
US20140251608A1 (en) * 2013-03-05 2014-09-11 Cenovus Energy Inc. Single vertical or inclined well thermal recovery process
WO2014182933A1 (fr) * 2013-05-08 2014-11-13 Conocophillips Company Polyol pour ameliorer l'efficacite de balayge dans des gisements de petrole
US11174714B2 (en) 2013-05-08 2021-11-16 Conocophillips Company Polyol for improving sweep efficiency in oil reservoirs
WO2014195443A3 (fr) * 2013-06-07 2015-06-18 Maersk Olie Og Gas A/S Procédé amélioré de récupération de pétrole
US20150083413A1 (en) * 2013-09-20 2015-03-26 Conocophillips Company Reducing solvent retention in es-sagd
US10633957B2 (en) * 2013-09-20 2020-04-28 Conocophillips Company Reducing solvent retention in ES-SAGD
CN104847321A (zh) * 2014-02-18 2015-08-19 中国石油化工股份有限公司 一种用于超深层稠油的水平井热化学采油方法
US20170314378A1 (en) * 2016-04-27 2017-11-02 Highlands Natural Resources, Plc Method for forming a gas phase in water saturated hydrocarbon reservoirs
US11125063B2 (en) 2017-07-19 2021-09-21 Conocophillips Company Accelerated interval communication using openholes
US20210396106A1 (en) * 2020-06-18 2021-12-23 Cenovus Energy Inc. Non-condensable gas management during production of in-situ hydrocarbons
US11713656B2 (en) * 2020-06-18 2023-08-01 Cenovus Energy Inc. Non-condensable gas management during production of in-situ hydrocarbons

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