US20080066907A1 - Oilfield Enhanced in Situ Combustion Process - Google Patents

Oilfield Enhanced in Situ Combustion Process Download PDF

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Publication number
US20080066907A1
US20080066907A1 US11/570,225 US57022505A US2008066907A1 US 20080066907 A1 US20080066907 A1 US 20080066907A1 US 57022505 A US57022505 A US 57022505A US 2008066907 A1 US2008066907 A1 US 2008066907A1
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Prior art keywords
horizontal leg
well
steam
oxidizing gas
injecting
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Abandoned
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US11/570,225
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English (en)
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Conrad Ayasse
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Archon Technologies Ltd
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Archon Technologies Ltd
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Priority to US11/570,225 priority Critical patent/US20080066907A1/en
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Abandoned legal-status Critical Current

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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
    • E21B43/30—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
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/243—Combustion in situ

Definitions

  • This invention relates to a process for improved safety and productivity when undertaking oil recovery from an underground reservoir by the toe-to-heel in situ combustion process employing horizontal production wells, such as disclosed in U.S. Pat. Nos. 5,626,191 and 6,412,557.
  • U.S. Pat. Nos. 5,626,191 and 6,412,557 disclose in situ combustion processes for producing oil from an underground reservoir ( 100 ) utilizing an injection well ( 102 ) placed relatively high in an oil reservoir ( 100 ) and a production well ( 103 - 106 ) completed relatively low in the reservoir ( 100 ).
  • the production well has a horizontal leg ( 107 ) oriented generally perpendicularly to a generally linear and laterally extending upright combustion front propagated from the injection well ( 102 ).
  • the leg ( 107 ) is positioned in the path of the advancing combustion front.
  • a high oxygen flux is known to keep the combustion in the high-temperature oxidation (HTO) mode, achieving temperatures of greater than 350° C. and combusting the fuel substantially to carbon dioxide.
  • HTO high-temperature oxidation
  • LTO low-temperature oxidation
  • the present invention provides such a method.
  • the THAITM and CapriTM processes depend upon two forces to move oil, water and combustion gases into the horizontal wellbore for conveyance to the surface. These are gravity drainage and pressure.
  • the liquids, mainly oil, drain into the wellbore under the force of gravity since the wellbore is placed in the lower region of the reservoir. Both the liquids and gases flow downward into the horizontal wellbore under the pressure gradient that is established between the reservoir and the wellbore.
  • the present invention in a first broad embodiment comprises a process for extracting liquid hydrocarbons from an underground reservoir comprising the steps of:
  • the present invention comprises A process for extracting liquid hydrocarbons from an underground reservoir, comprising the steps of:
  • the present comprises the combination of the above steps of injecting a medium to the formation via the injection well, and as well injecting a medium via tubing in the horizontal leg. Accordingly, in this further embodiment the present invention comprises a method for extracting liquid hydrocarbons from an underground reservoir, comprising the steps of:
  • the medium is steam, it is injected into the reservoir/formation, via either or both the injection well or the production well via tubing therein, in this state, typically under a pressure of 7000 KpA.
  • the injected medium is water
  • the water become heated at the time of supply to the reservoir to become steam.
  • the water when it reaches the formation, via either or both the injection well and/or the tubing in the production well, may be heated to steam during such travel, or immediately upon its exiting of the injection well and/or tubing in the production well and its entry into the formation.
  • FIG. 1 is a schematic of the THAITM in situ combustion process with labeling as follows:
  • Item A represents the top level of a heavy oil or bitumen reservoir, and B represents the bottom level of such reservoir/formation.
  • C represents a vertical well with D showing the general injection point of a oxidizing gas such as air.
  • E represents a general location for the injection of steam or a non-oxidizing gas into the reservoir. This is part of the present invention.
  • F represents a partially perforated horizontal well casing. Fluids enter the casing and are typically conveyed directly to the surface by natural gas lift through another tubing located at the heel of the horizontal well (not shown).
  • G represents a tubing placed inside the horizontal leg.
  • the open end of the tubing may be located near the end of the casing, as represented, or elsewhere.
  • the tubing can be ‘coiled tubing’ that may be easily relocated inside the casing. This is part of the present invention.
  • E and G are part of the present invention and steam or non-oxidizing gas may be injected at E and/or at G.
  • E may be part of a separate well or may be part of the same well used to inject the oxidizing gas.
  • These injection wells may be vertical, slanted or horizontal wells or otherwise and each may serve several horizontal wells.
  • the steam, water or non-oxidizing gas may be injected at any position between the horizontal legs in the vicinity of the toe of the horizontal legs.
  • FIG. 2 is a schematic diagram of the Model reservoir.
  • the schematic is not to scale. Only an ‘element of symmetry’ is shown. The full spacing between horizontal legs is 50 meters but only the half-reservoir needs to be defined in the STARSTM computer software. This saves computing time.
  • the overall dimensions of the Element of Symmetry are:
  • length A-E is 250 m; width A-F is 25 m; height F-G is 20 m.
  • Oxidizing gas injection well J is placed at B in the first grid block 50 meters (A-B) from a corner A.
  • the toe of the horizontal well K is in the first grid block between A and F and is 15 m (B-C) offset along the reservoir length from the injector well J.
  • the heel of the horizontal well K lies at D and is 50 m from the corner of the reservoir, E.
  • the horizontal section of the horizontal well K is 135 m (C-D) in length and is placed 2.5 m above the base of the reservoir (A-E) in the third grid block.
  • the Injector well J is perforated in two (2) locations.
  • the perforations at H are injection points for oxidizing gas, while the perforations at I are injection points for steam or non-oxidizing gas.
  • the horizontal leg (C-D) is perforated 50% and contains tubing open near the toe (not shown, see FIG. 1 ).
  • the operation of the THAITM process has been described in U.S. Pat. Nos. 5,626,191 and 6,412,557 and will be briefly reviewed.
  • the oxidizing gas typically air, oxygen or oxygen-enriched air
  • Coke that was previously laid down consumes the oxygen so that only oxygen-free gases contact the oil ahead of the coke zone.
  • Combustion gas temperatures typically 600° C. and as high as 1000° C. are achieved from the high-temperature oxidation of the coke fuel.
  • MOZ Mobile Oil Zone
  • the Burned Zone of the reservoir is depleted of liquids (oil and water) and is filled with oxidizing gas.
  • the section of the horizontal well opposite this Burned Zone is in jeopardy of receiving oxygen which will combust the oil present inside the well and create extremely high wellbore temperatures that would damage the steel casing and especially the sand screens that are used to permit the entry of fluids but exclude sand. If the sand screens fail, unconsolidated reservoir sand will enter the wellbore and necessitate shutting in the well for cleaning-out and remediation with cement plugs. This operation is very difficult and dangerous since the wellbore can contain explosive levels of oil and oxygen.
  • Simulator STARS TM 2003.13, Computer Modelling Group Limited Model dimensions: Length 250 m, 100 grid blocks, eac Width 25 m, 20 grid blocks Height 20 m, 20 grid blocks Grid Block dimensions: 2.5 m ⁇ 2.5 m ⁇ 1.0 m (LWH).
  • Horizontal Production Well A discrete well with a 135 m horizontal section extending from grid block 26, 1, 3 to 80, 1, 3 The toe is offset by 15 m from the vertical air injector..
  • Bitumen average molecular weight 550 AMU Upgrade viscosity: 664 cP at 10° C. Upgrade average molecular weight: 330 AMU Physical Conditions: Reservoir temperature: 20° C. Native reservoir pressure: 2600 kPa. Bottomhole pressure: 4000 kPa. Reactions: 1. 1.0 Bitumen ----> 0.42 Upgrade + 1.3375 CH4 + 20 Coke 2. 1.0 Bitumen + 16 O2 ⁇ circumflex over ( ) ⁇ 0.05 ----> 12.5 water + 5.0 CH4 + 9.5 CO2 + 0.5 CO/N2 + 15 Coke 3. 1.0 Coke + 1.225 O2 ----> 0.5 water + 0.95 CO2 + 0.05 CO/N2
  • Table 1a shows the simulation results for an air injection rate of 65,000 m3/day (standard temperature and pressure) into a vertical injector (E in FIG. 1 ).
  • the case of zero steam injected at the base of the reservoir at point I in well J is not part of the present invention.
  • At 65,000 m3/day air rate there is no oxygen entry into the horizontal wellbore even with no steam injection and the maximum wellbore temperature never exceeds the target of 425° C.
  • Table 1b shows the results of injecting steam into the horizontal well via the internal tubing, G, in the vicinity of the toe while simultaneously injecting air at 65,000 m3/day (standard temperature and pressure) into the upper part of the reservoir.
  • the maximum wellbore temperature is reduced in relative proportion to the amount of steam injected and the oil recovery factor is increased relative to the base case of zero steam. Additionally, the maximum volume percent of coke deposited in the wellbore decreases with increasing amounts of injected steam. This is beneficial since pressure drop in the wellbore will be lower and fluids will flow more easily for the same pressure drop in comparison to wells without steam injection at the toe of the horizontal well.
  • the air injection rate was increased to 85,000 m3/day (standard temperature and pressure) and resulted in oxygen breakthrough as shown in Table 2a.
  • An 8.8% oxygen concentration was indicated in the wellbore for the base case of zero steam injection.
  • Maximum wellbore temperature reached 1074° C. and coke was deposited decreasing wellbore permeability by 97%.
  • 12 m3/day (water equivalent) of steam at the base of the reservoir via vertical injection well C (see FIG. 1 )provided an excellent result of zero oxygen breakthrough, acceptable coke and good oil recovery.
  • Table 2b shows the combustion performance with 85,000 m3/day air (standard temperature and pressure) and simultaneous injection of steam into the wellbore via an internal tubing G (see FIG. 1 ) . Again 10 m3/day (water equivalent) of steam was needed to prevent oxygen breakthrough and an acceptable maximum wellbore temperature.
  • Table 3b shows the consequence of injecting steam into the well tubing G(ref. FIG. 1 ) while injecting 100,000 m3/day air into the reservoir. Identically with steam injection at the reservoir base, a steam rate of 20 m3/day (water equivalent) was required in order to prevent oxygen entry into the horizontal leg.
  • the average daily oil recovery rate increased with air injection rate. This is not unexpected since the volume of the sweeping fluid is increased. However, it is surprising that the total oil recovered decreases as air rate is increased. This is during the life of the air injection period (time for the combustion front to reach the heel of the horizontal well).

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  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Physics & Mathematics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Spray-Type Burners (AREA)
  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)
  • Physical Or Chemical Processes And Apparatus (AREA)
US11/570,225 2004-06-07 2005-06-07 Oilfield Enhanced in Situ Combustion Process Abandoned US20080066907A1 (en)

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US57777904P 2004-06-07 2004-06-07
US11/570,225 US20080066907A1 (en) 2004-06-07 2005-06-07 Oilfield Enhanced in Situ Combustion Process
PCT/CA2005/000883 WO2005121504A1 (en) 2004-06-07 2005-06-07 Oilfield enhanced in situ combustion process

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US (2) US20080066907A1 (ru)
KR (1) KR20070043939A (ru)
CN (2) CN1993534B (ru)
AR (2) AR050826A1 (ru)
AU (1) AU2005252272B2 (ru)
BR (1) BRPI0511304A (ru)
CA (1) CA2569676C (ru)
CU (1) CU20060240A7 (ru)
EC (2) ECSP067085A (ru)
GB (1) GB2430954B (ru)
HK (1) HK1109438A1 (ru)
MX (1) MXPA06014207A (ru)
PE (1) PE20060517A1 (ru)
RO (1) RO123558B1 (ru)
RU (1) RU2360105C2 (ru)
WO (1) WO2005121504A1 (ru)

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20060207762A1 (en) * 2004-06-07 2006-09-21 Conrad Ayasse Oilfield enhanced in situ combustion process
US20080169096A1 (en) * 2004-06-07 2008-07-17 Conrad Ayasse Oilfield enhanced in situ combustion process
US20110061868A1 (en) * 2009-09-11 2011-03-17 Excelsior Energy Limited System and Method for Enhanced Oil Recovery from Combustion Overhead Gravity Drainage Processes
US20130062058A1 (en) * 2011-03-03 2013-03-14 Conocophillips Company In situ combustion following sagd

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CA2492306A1 (en) * 2005-01-13 2006-07-13 Encana In situ combustion following primary recovery processes utilizing horizontal well pairs in oil sands and heavy oil reservoirs
RU2406819C2 (ru) * 2006-02-27 2010-12-20 Арчон Текнолоджиз Лтд. Способ извлечения жидких углеводородов из подземного пласта (варианты)
US7740062B2 (en) 2008-01-30 2010-06-22 Alberta Research Council Inc. System and method for the recovery of hydrocarbons by in-situ combustion
US7841404B2 (en) 2008-02-13 2010-11-30 Archon Technologies Ltd. Modified process for hydrocarbon recovery using in situ combustion
TR201006697T1 (tr) 2008-02-13 2011-04-21 Archon Technologies Ltd. Yerinde yanma kullanılan hidrokarbon geri kazanımına yönelik modifiye edilmiş proses
US20090260812A1 (en) * 2008-04-18 2009-10-22 Michael Anthony Reynolds Methods of treating a hydrocarbon containing formation
RU2475629C2 (ru) * 2008-10-17 2013-02-20 Арчон Текнолоджиз Лтд. Сегмент обсадного хвостовика для обогащения углеводородов и способ обогащения углеводородов
US7793720B2 (en) * 2008-12-04 2010-09-14 Conocophillips Company Producer well lugging for in situ combustion processes
US8132620B2 (en) 2008-12-19 2012-03-13 Schlumberger Technology Corporation Triangle air injection and ignition extraction method and system
US8176980B2 (en) * 2009-02-06 2012-05-15 Fccl Partnership Method of gas-cap air injection for thermal oil recovery
CA2692885C (en) * 2009-02-19 2016-04-12 Conocophillips Company In situ combustion processes and configurations using injection and production wells
CA2709241C (en) * 2009-07-17 2015-11-10 Conocophillips Company In situ combustion with multiple staged producers
CA2729218C (en) * 2010-01-29 2016-07-26 Conocophillips Company Processes of recovering reserves with steam and carbon dioxide injection
CA2698454C (en) * 2010-03-30 2011-11-29 Archon Technologies Ltd. Improved in-situ combustion recovery process using single horizontal well to produce oil and combustion gases to surface
US9163491B2 (en) 2011-10-21 2015-10-20 Nexen Energy Ulc Steam assisted gravity drainage processes with the addition of oxygen
CN103748316B (zh) * 2011-07-13 2017-06-16 尼克森能源无限责任公司 用蒸汽和氧气的原位燃烧和分别注入的烃采收
CA2815737C (en) 2012-05-15 2020-05-05 Nexen Inc. Steam assisted gravity drainage with added oxygen geometry for impaired bitumen reservoirs
RU2547848C2 (ru) * 2013-01-16 2015-04-10 Открытое акционерное общество "Нефтяная компания "Роснефть" Способ разработки нефтяных низкопроницаемых залежей
CN103089230B (zh) * 2013-01-24 2015-10-14 中国石油天然气股份有限公司 一种溶剂辅助火驱重力泄油开采油藏的方法
RU2570865C1 (ru) * 2014-08-21 2015-12-10 Евгений Николаевич Александров Система для повышения эффективности эрлифта при откачке из недр пластового флюида
CN104594865B (zh) * 2014-11-25 2017-05-10 中国石油天然气股份有限公司 一种可控反向火烧油层开采稠油油藏的方法
CN106246148B (zh) * 2016-08-01 2019-01-18 中嵘能源科技集团有限公司 一种采用连续管向水平井注空气的采油方法
CN111197474B (zh) * 2018-11-19 2022-06-03 中国石油化工股份有限公司 模拟稠油热采流场变化实验装置
CN112196505A (zh) * 2020-09-04 2021-01-08 中国石油工程建设有限公司 一种油藏原位转化制氢系统及其制氢工艺

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US3502372A (en) * 1968-10-23 1970-03-24 Shell Oil Co Process of recovering oil and dawsonite from oil shale
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US6412557B1 (en) * 1997-12-11 2002-07-02 Alberta Research Council Inc. Oilfield in situ hydrocarbon upgrading process
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CA2569676C (en) * 2004-06-07 2010-03-09 Archon Technologies Ltd. Oilfield enhanced in situ combustion process

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US3448807A (en) * 1967-12-08 1969-06-10 Shell Oil Co Process for the thermal recovery of hydrocarbons from an underground formation
US3542129A (en) * 1968-03-28 1970-11-24 Texaco Inc Oil recovery of high gravity crudes
US3502372A (en) * 1968-10-23 1970-03-24 Shell Oil Co Process of recovering oil and dawsonite from oil shale
US3565174A (en) * 1969-10-27 1971-02-23 Phillips Petroleum Co Method of in situ combustion with intermittent injection of volatile liquid
US3727686A (en) * 1971-03-15 1973-04-17 Shell Oil Co Oil recovery by overlying combustion and hot water drives
US3794113A (en) * 1972-11-13 1974-02-26 Mobil Oil Corp Combination in situ combustion displacement and steam stimulation of producing wells
US4059152A (en) * 1974-09-23 1977-11-22 Texaco Inc. Thermal recovery method
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Cited By (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20060207762A1 (en) * 2004-06-07 2006-09-21 Conrad Ayasse Oilfield enhanced in situ combustion process
US20080169096A1 (en) * 2004-06-07 2008-07-17 Conrad Ayasse Oilfield enhanced in situ combustion process
US7493952B2 (en) * 2004-06-07 2009-02-24 Archon Technologies Ltd. Oilfield enhanced in situ combustion process
US7493953B2 (en) * 2004-06-07 2009-02-24 Archon Technologies Lcd. Oilfield enhanced in situ combustion process
US20110061868A1 (en) * 2009-09-11 2011-03-17 Excelsior Energy Limited System and Method for Enhanced Oil Recovery from Combustion Overhead Gravity Drainage Processes
US20130062058A1 (en) * 2011-03-03 2013-03-14 Conocophillips Company In situ combustion following sagd

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RU2360105C2 (ru) 2009-06-27
AU2005252272B2 (en) 2009-08-06
AR050826A1 (es) 2006-11-29
MXPA06014207A (es) 2007-05-04
WO2005121504A1 (en) 2005-12-22
ECSP067085A (es) 2007-02-28
GB0624477D0 (en) 2007-01-17
CN102128020A (zh) 2011-07-20
CA2569676A1 (en) 2005-12-22
BRPI0511304A (pt) 2007-12-04
GB2430954A (en) 2007-04-11
RU2007100150A (ru) 2008-07-20
KR20070043939A (ko) 2007-04-26
CN1993534B (zh) 2011-10-12
HK1109438A1 (en) 2008-06-06
CA2569676C (en) 2010-03-09
US20080169096A1 (en) 2008-07-17
PE20060517A1 (es) 2006-06-18
ECSP088779A (es) 2008-11-27
RO123558B1 (ro) 2013-08-30
AU2005252272A1 (en) 2005-12-22
GB2430954B (en) 2008-04-30
CU20060240A7 (es) 2012-06-21
US7493953B2 (en) 2009-02-24
AR088545A2 (es) 2014-06-18
CN1993534A (zh) 2007-07-04

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