WO2014022393A2 - Configurations de puits pour reflux limité - Google Patents

Configurations de puits pour reflux limité Download PDF

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Publication number
WO2014022393A2
WO2014022393A2 PCT/US2013/052724 US2013052724W WO2014022393A2 WO 2014022393 A2 WO2014022393 A2 WO 2014022393A2 US 2013052724 W US2013052724 W US 2013052724W WO 2014022393 A2 WO2014022393 A2 WO 2014022393A2
Authority
WO
WIPO (PCT)
Prior art keywords
injection well
steam
ncg
production wells
mixture
Prior art date
Application number
PCT/US2013/052724
Other languages
English (en)
Other versions
WO2014022393A3 (fr
Inventor
Qing Chen
Lilian LO
Olajide AKINLADE
Original Assignee
Conocophillips Company
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 Conocophillips Company filed Critical Conocophillips Company
Priority to CA2880924A priority Critical patent/CA2880924C/fr
Publication of WO2014022393A2 publication Critical patent/WO2014022393A2/fr
Publication of WO2014022393A3 publication Critical patent/WO2014022393A3/fr

Links

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
    • E21B43/30—Specific pattern of wells, e.g. optimising the spacing of 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
    • E21B43/24—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
    • E21B43/16—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]
    • 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

Definitions

  • Embodiments of the invention relate to producing hydrocarbons by steam assisted gravity drainage with dual producers separated vertically and laterally from at least one injector.
  • SAGD Steam assisted gravity drainage
  • steam introduced into the reservoir through a horizontal injector well transfers heat upon condensation and develops a steam chamber in the reservoir.
  • the bitumen with reduced viscosity due to this heating drains together with steam condensate along a boundary of the steam chamber and is recovered via a producer well placed parallel and beneath the injector well.
  • gaseous carbon dioxide C02
  • solvent that may be injected with the steam in some applications can further present problems.
  • the gaseous C02/solvent acts as a thermal insulator impairing heat transfer from the steam to the bitumen, decreases temperature of the drainage interface due to partial pressure impact, and decreases effective permeability to oil as a result of increased gas saturation.
  • a method of recovering hydrocarbons includes introducing a gaseous mixture including steam and non-condensible gas (NCG) into an injection well.
  • the mixture passes into a formation through a horizontal length of the injection well.
  • the method further includes recovering a petroleum fluid from first and second production wells spaced laterally from one another by at least 10 meters and oriented horizontal and parallel to the horizontal length of the injection well that is disposed in vertical alignment 1 to 10 meters above a midpoint between the production wells.
  • a method of recovering hydrocarbons includes introducing a gaseous mixture including steam and NCG into an injection well having a horizontal length through which the mixture passes into a formation.
  • a steam chamber generates within the formation along with drainage pathways at a boundary of the chamber that end at first and second production wells and remain below a threshold temperature for retaining the NCG in solution due to location of the production wells below and on each side of the injection well.
  • the method also includes recovering a petroleum fluid from the production wells that are oriented horizontal and parallel to the horizontal length of the injection well.
  • a system for recovering hydrocarbons includes an injection well disposed in a formation and in fluid communication with a gaseous mixture of steam and NCG.
  • the injection well includes a horizontal length thereof through which the mixture is passable into the formation.
  • the system further includes first and second production wells spaced laterally from one another by at least 10 meters and oriented horizontal and parallel to the horizontal length of the injection well that is disposed in vertical alignment 1 to 10 meters above a midpoint between the production wells through which a petroleum fluid is recoverable.
  • Figure 1 is a schematic of an injector with dual producers in a steam assisted gravity drainage operation, according to one embodiment of the invention.
  • Figure 2 is a schematic of dual injectors with dual producers in a steam assisted gravity drainage operation, according to one embodiment of the invention.
  • Figure 3 is a graph of oil production rate versus time for comparison of simulated results based on well configurations such as shown in Figure 1 , according to one embodiment of the invention.
  • Figure 4 is a graph of cumulative steam to oil ratio versus time for comparison of simulated results based on well configurations such as shown in Figure 1 , according to one embodiment of the invention.
  • Figure 5 is a graph of oil production rate versus time for comparison of simulated results based on well configurations such as shown in Figure 2, according to one embodiment of the invention.
  • Figure 6 is a graph of cumulative steam to oil ratio versus time for comparison of simulated results based on well configurations such as shown in Figure 2, according to one embodiment of the invention.
  • methods and systems produce petroleum products by steam assisted gravity drainage (SAGD) with dual producers separated vertically and laterally from at least one injector. Placement of the producers limits temperature rise of draining fluids and hence reflux of non-condensable gases (NCG) injected with steam.
  • NCG non-condensable gases
  • the fluids drain along a steam chamber boundary for recovery at positions that are not in a direct downward path from where the injector is introducing heat into the formation.
  • the NCG refers to a chemical that remains in the gaseous phase under process conditions within the formation.
  • examples of the NCG include, but are not limited to, air, carbon dioxide (C0 2 ), nitrogen (N 2 ), carbon monoxide (CO), hydrogen sulfide (H 2 S), hydrogen (H 2 ), anhydrous ammonia (NH 3 ) and flue gas.
  • Flue gas or combustion gas refers to an exhaust gas from a combustion process that may otherwise exit to the atmosphere via a pipe or channel. Flue gas often comprises nitrogen, C0 2 , water vapor, oxygen, CO, nitrogen oxides (NO x ) and sulfur oxides (SO x ).
  • the NCG can make up from 1 to 40 volume percent of a mixture that is injected into the formation.
  • hydrocarbon solvent refers to a chemical consisting of carbon and hydrogen atoms which dissolves into products being recovered to increase fluidity and/or decrease viscosity of the products.
  • the hydrocarbon solvent can have, for example, 1 to 12 carbon atoms (Ci-Ci 2 ) or 1 to 4 carbon atoms (C 1 -C4) per molecule.
  • the Ci to C 4 hydrocarbon solvent may include methane, ethane, propane and/or butane.
  • the hydrocarbon solvent can be introduced into the formation as a gas or as a liquid. Under the pressures of the formation, the hydrocarbon solvent may be another example of the NCG or may condense from a gas to a liquid, especially if the hydrocarbon solvent has 2 or more carbon atoms.
  • the NCG at a side boundary of the steam chamber may act as a thermal insulating blanket that impairs transport of heat from the steam to the bitumen. Due to the partial pressure effect, the temperature of the drainage interface decreases and the bitumen that drains along the boundary also becomes less mobile. Gas saturation increases as a direct result of NCG accumulation at the drainage interface such that the effective permeability to oil decreases.
  • NCG Some of the NCG that accumulates in the steam chamber comes from refluxing of the NCG dissolved in the draining fluids prior to recovery.
  • the NCG liberates from the fluid in liquid phase back into gaseous phase that then moves upward into the steam chamber. Solubility of the NCG in the draining fluids depends on temperature. For example, minimal carbon dioxide dissolves in bitumen at steam chamber temperatures above 200° C but will dissolve in the bitumen at lower temperatures along a boundary of the steam chamber.
  • Increase in temperature of the draining fluid due to heat transfer near the injector depends on proximity of the draining fluid passing by the injector. As described herein for some embodiments, drainage pathways at a boundary of the steam chamber that end at the production wells remain below a threshold temperature for retaining the NCG in solution. Prior well configurations and operations by contrast provided undesired temperature profiles in the formation causing effervescence of the NCG from the bitumen, resulting in the reflux of the NCG into the steam chamber.
  • direct steam generator products have the NCG (e.g., 10 to 12 weight percent carbon dioxide) intermixed with steam
  • direct steam generation when used to supply a SAGD process may reduce the steam-oil ratio and improve economic recovery.
  • the direct steam generation also consumes less water compared to conventional steam generation.
  • the NCG from the direct steam generator products may accumulate in the steam chamber to a level more than desired without utilizing approaches described herein.
  • the direct steam generation refers to making steam by direct contact of water with combustion and hot combustion products.
  • direct steam generators include a combustion zone, a plurality of mixing zones downstream from the combustion zone, and an exhaust barrel downstream from the mixing zones.
  • a direct steam generator such as that described in U.S. Pat. No. 6,206,684 (assigned to Clean Energy Systems and incorporated herein by reference in its entirety) can be used or modified for some embodiments.
  • Figure 1 shows an injection well 100 disposed above a first production well 102 and a second production well 103 within a formation. While viewed transverse to a horizontal length, the wells 100, 102, 103 include horizontal sections that traverse through the formation containing petroleum products, such as heavy oil or bitumen.
  • a steam chamber 104 develops as a mixture of steam and NCG is introduced into the formation through the injection well 100 and a resulting petroleum fluid is recovered from the production wells 102, 103. Use of the productions wells 102, 103 for this recovery may begin upon initial development of the steam chamber 104.
  • the steam and the NCG contacts the bitumen, condenses and/or dissolves in the bitumen if soluble. Heat transfer upon condensation and solvent based viscosity reduction makes the bitumen mobile and enables gravity drainage thereof.
  • the petroleum fluid of steam condensate, the bitumen and any dissolved NCG migrates through the formation due to gravity and is gathered at each of the production wells 102, 103 for recovery to surface.
  • a distance of at least 10 meters separates the first production well 102 from the second production well 103, which are spaced laterally from one another and oriented horizontal and parallel to a horizontal length of the injection well 100. Lateral spacing of the production wells 102, 103 promotes lateral development of the steam chamber 104. In some embodiments, the steam chamber 104 generation occurs without recovery of the petroleum fluid in an area of the formation having vertical alignment with the injection well 100.
  • the injection well 100 for some embodiments aligns in a vertical direction 1 to 10 meters above a midpoint between the production wells 102, 103.
  • spacing between the first and second production wells 102, 103 ranges from 10 to 20 meters. With such spacing, the first and second production wells 102, 103 rely only on fluid communication being established during startup with the injection well 100. Any additional adjacent injection wells associated with corresponding production wells may be too far off for effective fluid communication at startup without creating such a tight spacing of all wells to be uneconomical. Multilaterals may form the first and second production wells 102, 103, which thus connect to a vertical common wellbore instead of separate independent wellbores for each of the production wells 102, 103.
  • the productions wells 102, 103 may extend along a bottom of a hydrocarbon reservoir in the formation and may be disposed in a common horizontal plane.
  • This operation and configuration of the wells 100, 102, 103 provides a desired temperature profile in the formation and limits reflux and accumulation of the NCG, such as the carbon dioxide. Drainage pathways at a boundary of the steam chamber 104 terminate at the production wells 102, 103 and remain below a threshold temperature for retaining the NCG in solution. Limiting the accumulation of the NCG promotes growth of the steam chamber 104, which also develops with a desired shape by employing approaches described herein.
  • the NCG such as the carbon dioxide
  • Figure 2 illustrates an injection well 200 disposed below an auxiliary well 201 and above a first production well 202 and a second production well 203 within a formation.
  • the auxiliary well 201 supplements the injection well 200 in introducing a mixture of steam and NCG into the formation and may further facilitate creation of a desired temperature profile within the formation.
  • the injection well 200 and production wells 202, 203 otherwise correspond in function and design as like elements described herein with respect to Figure 1.
  • the auxiliary well 201 aligns in a vertical direction at least 5 meters, or between 10 and 20 meters, above a horizontal length of the injection well 200.
  • the auxiliary well extends parallel with the horizontal length of the injection well 200.
  • the injection well 200 may pass through the formation 5 meters above a horizontal plane of the production wells 202, 203 with the auxiliary well 201 disposed 5 meters above the injection well 200.
  • the mixture of the steam and NCG may pass through both the injection well 200 and the auxiliary well 201 simultaneously.
  • An alternative staged strategy shuts in the injection well 200 stopping introduction of the mixture via the injection well 200 before injecting the mixture into the auxiliary well 201. Shutting in the injection well 200 may occur once thermal communication is established between the auxiliary well 201 and the production wells 202, 203 (e.g., after about 2 years).
  • Figure 3 shows simulated results for oil production rate versus time with a first curve 301 corresponding to a conventional steam only vertical aligned SAGD well pair, a second curve 302 corresponding to a well configuration as depicted in Figure 1 and operating with a direct steam generator, and a third curve 303 corresponding to the SAGD well pair operating with the direct steam generator.
  • the oil production rate thus improves with the well configuration as depicted in Figure 1.
  • the second curve 302 remains about the third curve 303 throughout most of the time and is above the first curve 301 as the time progresses.
  • Figure 4 illustrates simulated results for cumulative steam to oil ratio versus time with a first curve 401 corresponding to a conventional steam only vertical aligned SAGD well pair, a second curve 402 corresponding to a well configuration as depicted in Figure 1 and operating with a direct steam generator, and a third curve 403 corresponding to the SAGD well pair operating with the direct steam generator.
  • the second curve 402 remains below the first and third curves 401, 403 most of the time. Accordingly, embodiments described herein retain superior energy efficiency obtained by use of the direct steam generator as evidenced by a more than 20% reduction in the cumulative steam to oil ratio compared to steam only SAGD.
  • Figure 5 shows simulated results for oil production rate versus time with a first curve 501 corresponding to a conventional steam only vertical aligned SAGD well pair, a second curve 502 corresponding to a well configuration as depicted in Figure 2 and operating with a direct steam generator, and a third curve 503 corresponding to the SAGD well pair operating with the direct steam generator.
  • the oil production rate thus improves with the well configuration as depicted in Figure 2.
  • the second curve 502 remains about the third curve 503 throughout most of the time and is above the first curve 501 as the time progresses.
  • Figure 6 illustrates simulated results for cumulative steam to oil ratio versus time with a first curve 601 corresponding to a conventional steam only vertical aligned SAGD well pair, a second curve 602 corresponding to a well configuration as depicted in Figure 2 and operating with a direct steam generator, and a third curve 603 corresponding to the SAGD well pair operating with the direct steam generator. Similar to Figure 4, the second curve 602 remains below the first and third curves 601, 603 most of the time. Accordingly, embodiments described herein retain superior energy efficiency obtained by use of the direct steam generator as evidenced by a more than 20% reduction in the cumulative steam to oil ratio compared to steam only SAGD.

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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)

Abstract

L'invention porte sur des procédés et sur des systèmes, lesquels produisent des produits pétroliers par drainage par gravité assisté à la vapeur utilisant des dispositifs de production doubles séparés verticalement et latéralement vis-à-vis d'au moins un injecteur. La disposition des dispositifs de production limite une élévation de température de fluides de drainage, et, par conséquent, un reflux de gaz non-condensables injectés avec de la vapeur. En particulier, les fluides sont évacués le long d'une limite de chambre de vapeur pour une récupération en des positions qui ne sont pas dans une trajectoire vers le bas directe à partir de l'endroit où l'injecteur introduit de la chaleur.
PCT/US2013/052724 2012-08-03 2013-07-30 Configurations de puits pour reflux limité WO2014022393A2 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
CA2880924A CA2880924C (fr) 2012-08-03 2013-07-30 Configurations de puits pour reflux limite

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US201261679248P 2012-08-03 2012-08-03
US61/679,248 2012-08-03
US13/954,389 US20140034296A1 (en) 2012-08-03 2013-07-30 Well configurations for limited reflux
US13/954,389 2013-07-30

Publications (2)

Publication Number Publication Date
WO2014022393A2 true WO2014022393A2 (fr) 2014-02-06
WO2014022393A3 WO2014022393A3 (fr) 2015-07-16

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Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN103939069A (zh) * 2014-03-13 2014-07-23 中国石油大学(北京) 一种蒸汽-气体驱替与重力泄油复合开采方法
CN104389568A (zh) * 2014-09-29 2015-03-04 中国石油大学(北京) 蒸汽辅助重力泄油过程中气体辅助用量的获取方法及装置
CN104389569A (zh) * 2014-11-11 2015-03-04 中国石油天然气股份有限公司 一种蒸汽吞吐开采方法

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US10287864B2 (en) 2014-12-01 2019-05-14 Conocophillips Company Non-condensable gas coinjection with fishbone lateral wells
US10526881B2 (en) 2014-12-01 2020-01-07 Conocophillips Company Solvents and non-condensable gas coinjection
CN115898361A (zh) * 2021-08-12 2023-04-04 中国石油天然气股份有限公司 油藏井网结构

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CA2046107C (fr) * 1991-07-03 1994-12-06 Geryl Owen Brannan Methode de recuperation d'hydrocarbures dans un puits horizontal decale lateralement et verticalement
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Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN103939069A (zh) * 2014-03-13 2014-07-23 中国石油大学(北京) 一种蒸汽-气体驱替与重力泄油复合开采方法
CN104389568A (zh) * 2014-09-29 2015-03-04 中国石油大学(北京) 蒸汽辅助重力泄油过程中气体辅助用量的获取方法及装置
CN104389569A (zh) * 2014-11-11 2015-03-04 中国石油天然气股份有限公司 一种蒸汽吞吐开采方法

Also Published As

Publication number Publication date
CA2880924A1 (fr) 2014-02-06
US20140034296A1 (en) 2014-02-06
WO2014022393A3 (fr) 2015-07-16
CA2880924C (fr) 2020-07-21

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