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WO2013059909A1 - Injection de vapeur d'eau avec injection d'oxygène et stimulation cyclique par vapeur d'eau avec injection d'oxygène - Google Patents

Injection de vapeur d'eau avec injection d'oxygène et stimulation cyclique par vapeur d'eau avec injection d'oxygène Download PDF

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Publication number
WO2013059909A1
WO2013059909A1 PCT/CA2012/000898 CA2012000898W WO2013059909A1 WO 2013059909 A1 WO2013059909 A1 WO 2013059909A1 CA 2012000898 W CA2012000898 W CA 2012000898W WO 2013059909 A1 WO2013059909 A1 WO 2013059909A1
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WO
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Prior art keywords
oxygen
steam
well
gas
combustion
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Ceased
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PCT/CA2012/000898
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English (en)
Inventor
Richard Kelso Kerr
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Nexen Inc
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Nexen Inc
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Priority to CN201280052026.XA priority Critical patent/CN103917744A/zh
Priority to BR112014009440A priority patent/BR112014009440A2/pt
Publication of WO2013059909A1 publication Critical patent/WO2013059909A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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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
    • 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
    • E21B43/243—Combustion in situ

Definitions

  • the present invention relates to an enhanced oil recovery process for heavy oil in subterranean reservoirs and specifically processes for cyclic steam stimulation and/or steam flooding both improved by the additional step of injecting oxygen into the reservoir.
  • ASU Air Separation Unit (to produce oxygen gas)
  • Heavyoilinfo.com "Wafra pilot delivers for Chevron", Oct. 21 , 2010.
  • the present invention supplements and improves steam floods (SF) by adding oxygen gas (SFOX) and supplements and improves cyclic steam stimulation (CSS) by adding oxygen gas (CSSOX).
  • SFOX oxygen gas
  • CSS cyclic steam stimulation
  • thermal EOR Perhaps the oldest process for thermal EOR is cyclic steam stimulation (also called the “huff” and "puff process).
  • the process takes place using a vertical well, in three steps— first, steam is injected until injectivity/back-pressure limits injection rates or until a target slug size of steam is injected (the "huff" part of the cycle). For some reservoirs, fracture pressure may be exceeded during this phase to create fractures that aid in steam distribution and provide a conduit for oil flow. Second, the well is shut in and allowed to "soak” for a few weeks/months. This helps to spread heat by conduction and maximize the heated oil. Third, the well is put on production and oil flows to surface or is pumped to surface (the "puff part of the cycle).
  • CSS can also be conducted using horizontal or deviated wells (Sarker (1993), Escobar (2000)). This can help distribute steam and shorten the flow path of heated heavy oil during the production phase.
  • CSS heats oil and reduces viscosity so the oil can more-easily flow to the production well. Steam also provides some gas drive during the production cycle. CSS also uses a form of gravity drainage, particularly if a partial steam chamber is retained around the vertical well during the soak phase ( Figure 3). Oil can drain downward and replace steam as it condenses (Butler (1991 )). The process has been labeled a "stimulation" process, because even if the native oil has some mobility but rates are low, by heating oil and the matrix rock, steam can reduce near-well-bore resistance to oil flow and increase recovery rates.
  • the process can be changed to a steam flood, where steam is injected continuously into one (or more) well and "pushes" heated oil to one (or more) production wells.
  • Figure 9 shows the simple SF geometry using vertical wells. Usually the wells are arranged in regular patterns (e.g. Figure 12). SF processes can recover more oil than CSS, but, one of the problems with SF processes is steam override, where steam rises to the top of the pay zone and breaks through to the production well, bypassing the heated oil bank. This can reduce productivity or even cause a premature abandonment of the process. If the reservoir dips, it is advantageous to arrange the wells so the steam injector is higher than the producer to take advantage of gravity drainage and to minimize steam override (e.g. California heavy oils).
  • Horizontal wells are also being considered to improve productivity and recovery (Green Car Cong. (201 1 )).
  • SAGD ( Figure 2) can be considered as a vertical SF using gravity drainage as the dominant recovery mechanism (Butler, (19 1 )).
  • Tangleflags, Sask. is an example of a vertical SF using a combination of vertical steam injectors and horizontal production wells ( Figure 7, Thomas (2008)).
  • SF based solely on horizontal wells is also feasible ( Figure 10).
  • SF EOR began in the USA in the 1950-1960's (Lake (1992)) and the USA has continued as a dominant player (Figure 5).
  • California SF projects produced about 400 KBD using 20,000 vertical wells in the Bakersfield area (Stevens (1998)).
  • Chevron is the largest US producer (Green, (201 1)).
  • the largest single SF project is the Duri field, operated by Caltex, in Indonesia, currently producing about 300 KBD (Jakarta Post (201 1 ), Figure 8).
  • SF technology has also been introduced to the Mid East (heavyoilinfo (2010), Arabian Oil & Gas (201 1 )).
  • Some of the problems with SF include the following:
  • Start-up may be difficult or prolonged because of injectivity limitations or lack of communication between injectors and producers. Often, SF is started by CSS.
  • COFCAW (combination of forward combustion and waterflood) is a version of an ISC process that injects water to produce steam in the reservoir. It produces a steam + oxygen (or air) mixture, upstream of the combustion front (Parrish (1969)). But, the process is a modified ISC process, not a modified SF process, and it is suited to a vertical well geometry, not to a horizontal well geometry. If liquid water is allowed to impinge on the combustion front, HTO will be quenched and either oxygen gas will break through to the production well or LTO oxidation will occur. LTO is undesirable because oxygen use is incomplete, heat release per unit oxygen consumed is less than HTO, and oxidation products include organic acids that can create undesirable emulsions that can cause reservoir blockages and/or oil/water (treating) separation problems.
  • Pfefferle (2008) suggested using oxygen + steam mixtures in a SAGD process, as a way to reduce steam demands and to partially upgrade heavy oil. Combustion was purported to occur at the bitumen interface (the chamber wall) and combustion temperature was controlled by adjusting oxygen concentrations. But, as shown by Yang, combustion will not occur at the chamber walls. It will occur inside the steam chamber, using residual bitumen as a fuel not bitumen from/at the chamber wall. Also, combustion temperature is almost independent of oxygen concentration (Butler, 1991). It is dependant on fuel (coke) lay-down rates by the combustion/pyrolysis process. Pfefferle also suggested oxygen injection over the full length of a horizontal well and did not address the issues of corrosion, nor of maintaining minimum oxygen flux rates if a long horizontal well is used for injection.
  • a process to recover heavy oil from a hydrocarbon reservoir comprising injecting oxygen- containing gas and steam separately injected via separate wells into the reservoir to cause heated hydrocarbon fluids to flow more readily to a production well, wherein:
  • the hydrocarbon is heavy oil (API from 10 to 20; with some initial gas injectivity)
  • the ratio of oxygen/steam injectant gas is controlled in the range from 0.05 to 1 .00 (v/v)
  • the process uses Cyclic Steam Stimulation or Steam Flooding techniques and well geometry, with extra well(s) or a segregated zone to inject oxygen gas, wherein the oxygen contact zone within the reservoir is less than substantial ly 50 metres long.
  • a separate well or segregation is used for non-condensable gas produced by combustion.
  • the oxygen-containing gas has an oxygen content of 95 to 99.9% (v/v).and preferably wherein the oxygen-containing gas has an oxygen content of 95 to 97% (v/v).
  • the oxygen-containing gas is air.
  • the oxygen-containing gas is enriched air with an oxygen content of substantially 20 to 95% (v/v).
  • the oxygen injection well within the reservoir is less than substantially 50 metres long proximate a steam swept zone.
  • the oxygen-containing gas injection step is started only after a steam-swept zone is formed around the injection point, preferably controlled by:
  • a separate produced gas removal well is used to minimize steam override to production wells.
  • oxygen/steam (v/v) ratios start at about 0.05 and ramp up to 1.00 as the process matures.
  • oxygen/steam (v/v) ratio is held between 0.4 and 0.7 and most preferably 0.35.
  • the ratio of oxygen/steam is between 0.4 and 0.7 and the oxygen purity in the oxygen-containing gas is between 95 and 97% (v/v).
  • the process further comprises an injector well (either a separate vertical well or the segregated portion of a well) having a maximum perforated zone (or zone with slotted liners) of less than substantially 50 m so that oxygen flux rates can be maximized.
  • Oxygen is injected proximate a steam-swept zone, whereby combustion of residual fuel in the reservoir is the source of energy for said combustion, said zone being preheated, at start-up, so spontaneous High Temperature Oxidation can occur.
  • an improved Cyclic Steam Stimulation Enhanced Oil Recovery process to recover heavy oil comprising adding oxygen gas during a typical steam-injection cycle (the "huff), the "soak” and ''puff' cycles being similar to conventional CSS, wherein the injection of Oxygen provides extra energy from combustion of residual oil , for heavy oil recovery while creating CO2 in the reservoir and removing produced C0 2 separately to better control the process.
  • an extra oxygen injection well is utilized.
  • the process further comprises segregating oxygen injection within steam injection wells using separate tubing and a packer.
  • oxygen injection is segregated near the top of the injector well or using a separate 0 2 well, during the "huff cycle, by injecting steam and oxygen; and during the "puff cycle removing produced gases (mainly C0 2 ) separately to better control the process.
  • the CSSOX process is the startup process for a SFOX process.
  • an improved Steam Flooding (SFOX EOR) process Enhanced Oil Recovery to recover heavy oil basically similar to a conventional SF process, the improvement comprising injection of oxygen gas continuously injected near (or at) the steam injector to provide an added source of energy from in situ combustion of residual fuels, said Steam and oxygen being injected in a vertical-well geometry, with producer/injector wells arranged in regular patterns.
  • separate wells are provided to remove non-condensable combustion gases.
  • the process further comprises use of horizontal wells, especially for the more viscous heavy oils.
  • the pipe sizes for CSSOX or SFOX wells can be much smaller than for steam-only processes because oxygen carries about ten times the heat content, per unit volume.
  • FIG. 1 illustrates World EOR Production.
  • FIG. 2 illustrates the SAGD EOR Process.
  • FIG. 3 illustrates the CSS Process.
  • Figure 4 illustrates an oil viscosity chart.
  • FIG. 5 illustrates USA/Canada Steam EOR.
  • Figure 6 illustrates a cost comparison of EOR methods.
  • Figure 7 illustrates Tangleflags steam flood.
  • Figure 8 charts the Kern River, California and Duri, Indonesia SF projects.
  • Figure 9 illustrates SF geometry
  • Figure 10 illustrates a horizontal well SF.
  • Figure 1 1 illustrates a SFOX geometry
  • Figure 12 illustrates a 5-spot pattern for SFOX.
  • Figure 13 illustrates well geometry for CSSOX 1.
  • Figure 14 illustrates well geometry for CSSOX 2.
  • Figure 15 illustrates residual bitumen in steam-swept zones.
  • Figure 16 illustrates SFOX geometry
  • Figure 17 illustrates another SFOX geometry.
  • Figure 18 illustrates CSSOX with produced gas removal.
  • ( 1 ) CO in the product gases is about 10% of the carbon combusted (see Moore (1994)) for HTO.
  • HTO combustion T is between (380-800°C).
  • the CSSOX EOR process to recover heavy oil is similar to CSS (previously described) but oxygen gas is added during the steam-injection cycle (the "huff).
  • the "soak” and “puff cycles are similar to CSS.
  • Oxygen provides extra energy from combustion, and creates CO2 in the reservoir.
  • FIGS 13 and 14 show how CSSOX can be conducted using an extra oxygen injection well or by segregating oxygen injection within the steam injection wells using separate tubing and a packer. Alternately, steam and oxygen can be injected at separate times, as long as oxygen injection follows steam, so the reservoir is preheated for auto-ignition of HTO combustion.
  • the SFOX EOR process to recover heavy oil is similar to SF (previously described) but oxygen gas is continuously injected near (or at) the steam injector to provide an added source of energy from in situ combustion. Steam + oxygen are injected in a vertical-well geometry, with producer/injector wells arranged in regular patterns.
  • Figures 9, 1 1 and 12 show how SFOX can be arranged. We can also use horizontal wells as shown in Figure 10, especially for the more viscous heavy oils.
  • SF and SAGD process can sometimes be subtle.
  • SAGD can be considered as a top-down steamflood, aided by gravity drainage.
  • Figure 7 shows an example of a hybrid process (SF and SAGD) where a vertical well is used as an injector and a lower horizontal well is used as a producer.
  • Table 1 shows that and equal mix (v/v) of oxygen and steam contains over 450 percent more energy than pure steam. This can increase production rates.
  • Carbon dioxide is produced by combustion. When CO2 dissolves into periphery heavy oil, it will provide a dissolved-gas-drive mechanism and add to production and to ultimate recovery (Balog (1 82), Luo (2005)).
  • Oxidation or HTO combustion occurs at 380-800°C, much higher than saturated steam temperatures for typical reservoir pressures ( 1 to 4 MPa).
  • CSSOX or SFOX can have reduced C0 2 emissions compared to their steam-only counterparts.
  • Table 3 also demonstrates for a wide range of oxygen + steam mixes, if we wish to deliver oxygen gas at a segregated section in an existing steam injector (e.g. Figure 14), there is enough room for an oxygen tube and steam in the annulus, even for mixes as lean as 5% oxygen.
  • This invention applies to heavy oil with some initial oil mobility and initial gas injectivity. It does not apply to bitumen (AP 10) that is better suited to the SAGD- version SAGDOX (in a separate patent).
  • Oxygen is different in its effectiveness compared to steam. Steam has a positive effect (adding heat) no matter how low the flux rate is or no matter how low the concentration.
  • oxygen is mixed with steam and injected into a long horizontal well (500 to 1000 m) the oxygen flux is dispersed/diluted over a long distance. Even if the average oxygen flux is suitable to initiate and sustain HTO combustion, heterogeneities in the reservoir can cause local flux rates to be below the minimum needed.
  • Oxygen + steam mixtures are very corrosive particularly to carbon steel.
  • the preferred embodiment solution to these issues is to inject oxygen and steam in separate wells or at segregated points to minimize corrosion.
  • the injector well (either a separate vertical well or the segregated portion of well) should have a maximum perforated zone (or zone with slotted liners) of about 50 m so that oxygen flux rates can be maximized.
  • Oxygen concentration in steam/oxygen injectant mix is a convenient way to quantify oxygen levels and to label processes (e.g. SFOX (35) is a process that has 35% oxygen in the mix). But, in reality we expect to inject oxygen and steam as separate gas streams without any expectations of mixing in the reservoir or in average or actual in situ gas concentrations. Rather than controlling "concentrations", in practice would control to flow ratios of oxygen/steam (or the inverse). So SFOX (35) would be a SFOX process where the flow ratio of oxygen/steam was 0.5385 (v/v).
  • the preferred range for oxygen/steam ratios is 0.05 to 1 .00 (v/v) corresponding to a concentration range of 5 to 50% (v/v) of oxygen in the mix.
  • a cryogenic air separation unit can produce oxygen gas with a purity variation from about 95 to 99.9 (v/v) % oxygen concentration.
  • the higher end (99.0-99.9%) purity produces "chemical” grade oxygen.
  • the lower end of the range (95-97%) purity consumes about 25% less energy (electricity) per unit oxygen produced (Praxair (2010)).
  • the "contaminant” gas is primarily argon. Argon and oxygen have boiling points that are close, so cryogenic separation becomes difficult and costly. If argon and nitrogen in air remain unseparated, the resulting mixture is 95.7% "pure” oxygen.
  • argon is an inert gas that should have no impact on the process.
  • the preferred oxygen concentration is 95-97% purity (i.e. the least energy consumed in ASU operations)
  • API density (API scale)

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Abstract

La présente invention a trait à un processus permettant de récupérer de l'huile lourde à partir d'un réservoir d'hydrocarbure, ledit processus comprenant une étape consistant à injecter un gaz contenant de l'oxygène et de la vapeur d'eau séparément via des puits séparés dans le réservoir afin que les fluides hydrocarbures chauffés circulent plus facilement vers un puits de production, dans laquelle : (i) l'hydrocarbure est une huile lourde (degré API situé dans la plage allant de 10 à 20 ; avec une certaine injectivité du gaz initial) (ii) le rapport dans le gaz d'injection oxygène / vapeur d'eau est contrôlé pour être dans la plage allant de 0,05 à 1,00 (v/v) ; (iii) le processus utilise des techniques de stimulation cyclique par vapeur d'eau ou d'injection de vapeur d'eau et la géométrie du puits, avec un ou plusieurs puits supplémentaires ou une zone distincte permettant d'injecter de l'oxygène gazeux, la longueur de la zone de contact de l'oxygène à l'intérieur du réservoir étant inférieure ou égale à pratiquement 50 mètres.
PCT/CA2012/000898 2011-10-24 2012-09-27 Injection de vapeur d'eau avec injection d'oxygène et stimulation cyclique par vapeur d'eau avec injection d'oxygène Ceased WO2013059909A1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
CN201280052026.XA CN103917744A (zh) 2011-10-24 2012-09-27 伴注氧的蒸汽驱、以及伴注氧的周期蒸汽刺激
BR112014009440A BR112014009440A2 (pt) 2011-10-24 2012-09-27 inundação de vapor com injeção de oxigênio, e estimulação cíclica de vapor com injeção de oxigênio

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US201161550479P 2011-10-24 2011-10-24
US61/550,479 2011-10-24

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US (1) US20130098607A1 (fr)
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WO (1) WO2013059909A1 (fr)

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BR112014009440A2 (pt) 2017-04-11
US20130098607A1 (en) 2013-04-25
CN103917744A (zh) 2014-07-09
CA2791318A1 (fr) 2013-04-24

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