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

Definitions

• This invention relates to a process for recovering viscous hydrocarbons from a subterranean reservoir using in-situ combustion, a vertical oxidizing gas injection well, and a separate horizontal well, and in particular to an improved process which does not employ separate additional gas venting wells.
• the pyrolyzing agent can be a hot mixture of air and water but it must be injected at a temperature over 500 °F and the temperature in the formation must be controlled to 600-950 °F to prevent damage to the minerals.
• the present invention does not require rubbleization of the reservoir or utilize top-down burning. Rather, an established combustion front moves laterally along a horizontal well bore.
• US Patent 3,515,212 (Allen et al) discloses an in situ combustion process combining forward and reverse in situ combustion between vertical wells.
• the region of an injection well is heated with steam to auto-ignition temperature and air is injected from an offset well and flows in the direction of the injection well. As the air enters the
• CAL_LAW 165542411 heated zone oil zone near the injection well ignition occurs. Combustion gas is withdrawn at the ignition well and the combustion front grows towards the offset well, in a reverse in situ combustion process. After the front approaches the offset well, air injection is undertaken at that well and the original injector is converted to an oil producer, and a forward in situ combustion process is initiated wherein the combustion front moves toward the original injection well, and is produced from the original injection well.
• US Patent 4,566,537 (Gussis) relates to the production of immobile oil, such as the Athabasca bitumen.
• the problem of communication between vertical wells is overcome by conducting a series of cyclic steam cycles to heat the oil near the injector and create voidage.
• air is injected high in the reservoir at one of the wells and combustion gases are produced at the other well, establishing communication between the wells at the top of the reservoir.
• This process is different than the process of the present invention, which as discussed below, utilizes gravity drainage into a horizontal producer and does not requiring a steam drive stage. Further, continuous removal of oil and combustion gas occurs in the same well.
• US Patent 4,410,042 discloses a method of conducting the early stage of in situ combustion that utilizes pure oxygen. Until the combustion front reaches a distance of 30 feet from the injector, the oxygen is diluted with carbon dioxide. Thereafter pure oxygen is injected. By way of contrast, as discussed in the Summary of the Invention and the detailed description, the process of the present invention does not employ mixtures of pure oxygen with carbon dioxide at any stage.
• US Patent 4,418,751 discloses an in situ combustion process wherein water is injected into the upper part of an oil reservoir separately from oxygen that is injected near the base. The water and combustion gases mix in the reservoir, vaporizing the water and scavenging heat. The present process does not require or employ the simultaneous injection of oxygen and water. In fact the injection of oxygen near the horizontal well at the base of the reservoir would be very dangerous since oxygen
• CAL_LAW ⁇ 1655424M would enter the wellbore and burn oil therein, causing high temperatures that would threaten the integrity of the wellbore and deposit coke that would partially plug the wellbore.
• US Patent 4, 493,369 discloses essentially the same well and fluid arrangement as '751 with injection of oxidizing gas at the base of the reservoir and water at the top.
• US Patent 5,456,315 discloses an in situ combustion process wherein an oxidizing gas is injected into vertical wells that are perforated in the upper part of an oil reservoir.
• the vertical wells are placed in a row directly above a horizontal well that is situated at the base of the reservoir. This orientation of wells is the same as the present process.
• '315 requires a row of horizontal/vertical gas vent wells that are placed on either side of and parallel to a horizontal producer, but each situated at the top of the reservoir. The purpose of the vent wells is to withdraw the combustion gasses to the surface separately from the liquids that drain by gravity into the horizontal producer.
• the present process does not utilize separate combustion gas vent wells, but produces the liquids and gases together through the same horizontal well, and so it needs only one horizontal producer well, and thus substantially fewer expensive horizontal wells.
• the withdrawal of combustion gas separately from the liquids as done in the process of '315 eliminates convective heat transfer in the oil drainage zone, making the process of '315 less energy efficient. Specifically, by inhibiting mixing of combustion gas with liquids, '315 removes produced hydrogen from contact with hot oil so that the degree of in situ hydrocracking and oil in situ upgrading is greatly reduced.
• CAL_LAW ⁇ 1655424U temperature attained from the burnt (and sometimes burning) vent gas inside the reservoir. Furthermore, recalling that the air injection wells and the vent wells are all at the top of the reservoir and are in communication, there is likelihood of oxygen mixing with hydrocarbon liquids and gases in the vent wells so as to create an explosive mixture therein or at the surface.
• US Patent 5,339,897 discloses a process similar to '315 for producing hydrocarbons from tar sands wherein a vertical well is placed at the top of the oil- bearing reservoir over a horizontal producer and a second vertical well is emplaced offset from the first vertical well, also at the top of the reservoir, and laterally from the horizontal producer. Communication is accomplished between the vertical wells using hot fluids, then an oxidizing gas is injected in the well over the producer and combustion gas is withdrawn via the offset well. Heated oil drains downward to the producer. Additionally, '897 process of injecting a cracking fluid such as superheated steam into the accumulated oil above the horizontal producer induce cracking reactions.
• a cracking fluid such as superheated steam
• US Patent 5,626,191 discloses an in situ process wherein an oxidizing gas injector is placed near the top of an oil reservoir in the vicinity of the toe of a horizontal producer that is emplaced at the base of the reservoir.
• a combustion front is developed that is quasi-vertical, extends laterally and moves from the toe of the producer towards the heel of the producer. Oil and gas drain together into the same horizontal producer.
• the present invention as described below, is a valuable improvement over ' 191 because by placing the injector midway along the horizontal producer or placing multiple injectors above the producer as in the present invention greatly enhances the oil production rate and degree of oil upgrading at moderate cost.
• each injector sustains two combustion/drainage fronts instead on only one using ' 191. Surprisingly, the combustion/drainage fronts advance at equal rates toward the toe and the heel of the producer.
• US Patent 5.626,191 is incorporated herein in its entirety.
• US Patent 6,412,557 (Ayasse et al) is an improvement on ' 191 wherein a catalyst is emplaced in, on or around the horizontal producer well to enhance oil upgrading.
• US Patent 7,493,952 (Ayasse) discloses an improvement on ' 191 and '557 wherein a non-oxidizing gas is injected within the horizontal producer at the toe to prevent oxygen entry and enhance process safety by controlling temperature and pressure within the wellbore.
• US Patent 7,493,952 is incorporated herein in its entirety.
• US Patent Publ. 20090308606 discloses an improvement to ' 191 and '952 wherein a diluent such as naphtha or other hydrocarbon solvent, or C0 2 is injected in a long tubing extending to the toe of the horizontal producer well in order to control wellbore pressure and temperature and to facilitate flow of wellbore oil by density and viscosity reduction.
• a diluent such as naphtha or other hydrocarbon solvent, or C0 2
• US Patent Pat. Pub. 20090200024 discloses a new process, similar to ' 191, wherein oxidizing gas is injected near the heel of a horizontal well, having a tubing extending to the toe. A combustion front develops with movement from the heel to the toe.
• the advantage of the process of the present invention, as more fully described below, over US ' 191 is that unlike US ' 191 the drilling of a distant vertical injector near the toe is not required.
• the injector could be drilled away from the toe, such as midway along the horizontal leg
• the injector could be drilled away from the toe, such as midway along the horizontal leg
• the advantage of the present process over US Application '881 is that a single injector well may be placed midway between the toe and heel of the horizontal producer well and dual combustion fronts will move towards the toe and heel without concern about burning up the vertical segment of the horizontal producer as could happen with '881 wherein the air injection point is nearby or at the vertical segment.
• the present invention also has the advantage of placing a vertical air injector well back from the toe of the horizontal well (for example at 500 meters from the toe for a 1 OOOmeter horizontal producer leg) so that surface inaccessibility, such as caused by a bog or lake at the toe region, will not prohibit the drilling of a vertical injector there and inhibit reservoir exploitation.
• This invention is directed to an improved process for recovering viscous hydrocarbons from a subterranean reservoir using in-situ combustion, utilizing at least one oxidizing gas injection well and a separate horizontal well, and in particular to an improved process which does not employ separate additional vent gas wells and instead uses a horizontal well bore situated low in a formation to collect not only heated oil but also hot combustion gases, and to thereafter produce both to surface, where the oil is thereafter separated from the high temperature combustion gases.
• the vertical injection well is disposed and completed in the upper part of the reservoir, for injecting oxygen-containing gas into the reservoir to support in-situ combustion therein.
• Such vertical injection well is situated above the horizontal well and approximately at a midpoint along said horizontal well, and upon injection of an oxidizing gas into the reservoir via the injection well and upon ignition of hydrocarbons in such reservoir proximate such vertical injection well a combustion front is generated proximate the vertical injection well which combustion front propagates outwardly from the injection well in mutually opposite directions each mutually opposite direction being along the horizontal well, as well as laterally to the horizontal well.
• Both high temperature combustion gases and heated oil are drawn downwardly from the hydrocarbon formation and collected within the horizontal well, and thereafter are together produced to surface via such horizontal well, where at surface the hot combustion gases are separated from the oil using a multi-phase separator, vortex separating techniques or other techniques well known to persons of skill in the art, and further where desired the hot combustion gases are used to heat water so as to produce steam, preferably for use in powering steam turbines for the production of electrical power.
• the combustion gases which contain flammable components such as methane, ethane, propane, carbon monoxide, hydrogen and hydrogen sulfide, may be combusted at the surface to produce electricity with a steam turbine or gas turbine. In processes with gas vent wells, these gases are combusted in the upper reaches of the reservoir and must be cooled to protect the vent wells from thermal damage, so that the energy is wasted.
• each vertical oxidizing gas injection well is completed above and appropriately spaced along the horizontal well bore, and dual combustion fronts of hot combustion gases and draining oil are created at each injector, which combustion fronts propagate along the horizontal wellbore substantially orthogonal to the horizontal well bore and through the hydrocarbon formation, in mutually opposite directions from the vertical injection well bore as well as towards the toe and the heel of the horizontal well.
• the inner diameter of the horizontal leg of the producer well should be greater than 3- inches so as to maintain frontal advancement symmetry, preferably greater than 5- inches and most preferably greater than 7-inches to permit sufficient diameter in the producer well.
• Also contemplated within this invention is a process whereby a plurality of vertical oxidizing gas wells may be initially completed above the horizontal well bore along a line thereof, and an oxidizing gas is injected initially into the formation at one of said vertical injection wells located approximately midsection of the horizontal well and a
• CAL_LAW ⁇ 1655424M combustion front is formed proximate thereto, which advances in mutually opposite directions along the horizontal well.
• further oxidizing gas may then be injected into one or each of said additional injection wells so as to sustain combustion and permit the combustion front(s) to continue to advance along the horizontal well bore.
• the hot combustion gases which are drawn into the horizontal production well along with the heated oil serve to keep the oil continuously heated and thus improve not only collection rates of such oil from the hydrocarbon formation but also ensures the viscosity of the heated oil remains low and thus such oil may be lifted to surface using gas "lift", eliminating the use and necessity of pumps;
• hot combustion gases may be thereafter be used at surface to heat water so as to produce steam, which may be used for heating and/or to power steam turbines so as to generate electrical power, and thus energy which otherwise which would have been lost is thereby able to have been made use of in this process.
• the heated oil and water and the heated combustion gas may all drain under the influence of gravity and pressure forces and further be collected in the horizontal well free of oxygen or oxidizing gas, which greatly reduces the chance of explosion.
• the present process Compared with the process of vent gas withdrawal by separate vent wells, the present process preserves the valuable flammable components for production to the surface rather than burning them in the reservoir where the heat is wasted, and it utilizes some of the generated hydrogen to hydrocrack the hot oil, thus producing a stable partially upgraded oil.
• such process comprises an improved in situ combustion process for reducing the viscosity of oil contained in an oil-bearing reservoir and recovering said oil along with combustion gases from the reservoir, which process does not employ one or more separate combustion gas venting wells, comprising:
• said at least one injection well comprises at least one vertical injection well situated along a length of the horizontal well and intermediate mutually opposite ends thereof extending downwardly from surface towards said horizontal leg portion, and upon injection of oxidizing gas and ignition thereof said injection well supplies said oxidizing gas to at least two combustion fronts which each move in opposite directions outwardly from said vertical injection well and in a direction along said horizontal leg portion of said production well.
• said at least one injection well comprises a horizontal well extending both above and along said horizontal leg portion of said production well, for injecting said oxidizing gas above said horizontal leg portion of said production well.
• such method comprises an improved in-situ combustion process for reducing the viscosity of oil contained in an oil-bearing reservoir and recovering said oil of reduced viscosity from the formation, which process does not employ one or more separate combustion gas venting wells, further comprising: (a) drilling at least one production well having a substantially vertical portion extending downwardly into said reservoir and having a horizontal leg portion in fluid communication with said vertical portion and extending horizontally outwardly therefrom, said horizontal leg portion completed relatively low in the reservoir;
• oxidizing gas is injected into said reservoir at said succession further vertical injection wells to accelerate movement of the vertical combustion fronts in both directions along said horizontal well.
• such improved in-situ combustion process (which process does not employ one or more separate combustion gas venting wells) comprises:
• CAL_LAW ⁇ 1655424U further one of said plurality of injection wells, oxidizing gas is injected into said reservoir at said further one of said injection wells.
• cyclically or directly stimulating the reservoir with steam through the injection well and the production well may be initially conducted prior to initiating in situ combustion, in order to establish fluid communication between the injection well and the horizontal oil production well, to better ensure the flow of heated combustion gases and heated oil once in-situ combustion is initiated.
• oil ignition may be enabled or assisted by the known technique of injecting linseed oil or other fluid which is easily ignited into the reservoir through the air perforations.
• Co-production of combustion gas and hydrocarbon liquids also improves the oil production rate because C0 2 present in the combustion gas permeates the oil ahead of the drainage front and acts as a solvent to further reduce oil viscosity and facilitate oil drainage into the horizontal well. Also, C0 2 in the combustion gas has its highest solubility in cold oil, so that the drainage zone is made wider as a consequence of C0 2 dissolving in cold oil;
• Figure 1 is a cross section through an oil-bearing reservoir, showing the arrangement of wells used to carry out the method of the invention, such cross section cutting through both the vertical injection well and horizontal/vertical production well pair.
• a layer of overburden lies over the oil-bearing reservoir, into which are placed a vertical oxidizing gas injection well and a vertical/horizontal well pair for producing the oil;
• Figure 2 is a cross-sectional through the oil-bearing reservoir shown in Figure 1, taken along plane B-B, with the horizontal production well shown in cross-section;
• Figure 3 is a partially-transparent top view of the oil-bearing reservoir shown in Figure 1 from numerical simulation;
• Figure 4 is a cross-section through an oil-bearing reservoir similar to Figure 1, showing a variation of the method of the present invention, where a plurality of oxidizing gas injection wells are used to advance a combustion front in two mutually opposite directions; and
• FIG. 5 is similar to Figure 1 , but employing 5- oxidizing gas injection wells as simultaneous injectors.
• an oil-bearing reservoir 20 shown in Figure 1 is typically covered by an overburden 1, preferably constituted of shale or cap rock sufficiently thick to be substantially impermeable to gas flow so that the injected oxygen-containing gas 22 will be contained within the oil-bearing reservoir 20.
• an overburden 1 preferably constituted of shale or cap rock sufficiently thick to be substantially impermeable to gas flow so that the injected oxygen-containing gas 22 will be contained within the oil-bearing reservoir 20.
• At least one vertical oxidizing gas injection well 6a is drilled from the surface 30 downwardly into an upper portion of the reservoir 20, and is perforated so as to permit injection of oxidizing gas 22 into reservoir 20 proximate the top of the oil-bearing reservoir 20, such oxidizing gas being compressed and forced within well 6a via compressor 71.
• a horizontal/vertical production well pair 9 is provided, having a vertical well portion 10 and a horizontal portion 8.
• the horizontal well portion 8 is completed low in the reservoir 20 and preferable extending substantially across a length of an oil-bearing reservoir 20 or a portion thereof from which oil is desired to be recovered by the process of the present invention.
• the casing of the horizontal well is perforated as shown in Figures 1 and 4, or may consist of porous screens, as shown and taught in PCT/CA to the assignee herein, Archon Technologies Ltd., narrow slots or FacsRiteTM 1 screen plugs and the such to permit ingress of hot oil 3 and hot combustion gases 5 from the reservoir 20 into the horizontal well 8, for subsequent production to surface 30.
• the inner diameter of the horizontal producer well is preferably greater than 3- inches so as to maintain frontal advancement symmetry, and preferably greater than 5- inches and most preferably greater than 7-inches (ie an inner diameter of approximately 9 5/8 inches in typical current standard wellbore size) to permit sufficient diameter in the producer well.
• FacsRiteTM is a trademark of Shlumberger Inc. for producing well sand screens.
• the at least one oxidizing gas injector well 6a in accordance with the method of the present invention, is located above and approximately midway along horizontal well bore 8 (i.e. wherein distance "di" is approximately equal to distance "d 2 " as shown in Figure 1), although the precise position may be altered based on known reservoir heterogeneity or other factors.
• the first step in starting and conducting the oil recovery process of the present invention in a preferred embodiment, is to establish fluid communication between the vertical injection well 6a and the horizontal production well 8 so that oxidizing gas 22 can more easily be injected into the reservoir 20 and heated oil 3 and combustion gas 5 can be removed from the reservoir 20 via horizontal/vertical well pair 9.
• steam may be injected cyclically or continuously in the vertical well 6a, and also injected from surface into horizontal well 8 and circulated therein to heat the horizontal well 8 and increase mobility of heated oil 3 therein.
• the pressure of the initially-injected steam is not to be so great so as to force large volumes of steam directly through reservoir 20 and into horizontal well 8, but merely sufficient to assist viscous liquids in reservoir 20 to be assisted under such assisting pressure to drain downwards in reservoir 20 to an area of lower pressure, namely the region of horizontal well 8 which horizontal well 8 removes fluids from such region and thereby creates an area of relatively lower pressure, and thus establishes fluid flow in such direction).
• steam may also be injected via the injection well 6a in a continuous manner, relying on reservoir dilation to achieve steam injectivity.
• preheating the horizontal production well 8 prevents oil 3 from solidifying in the horizontal well 8 and inhibiting production, especially when the production well 8 must be shut-in, as may happen should difficulties occur with the surface oil-treating facilities.
• Such pre-heating may be conducted by circulating steam in the horizontal leg 8 from the toe 40 to the heel 42 of the horizontal well 8.
• the circulation is achieved by placing a long tubing (not shown) within the horizontal well 8 for injecting steam that flows via the tubing to the toe 40 and returns back the heel 42 via the annular space between the tubing and horizontal well casing 8 and thereafter to surface 30. Once fluid communication is established between the injector well 6a and horizontal
• an oxygen-containing gas for example air, oxygen-enriched air, C0 2 - enriched air or an oxygen-C0 2 mixture
• injector well 6a as shown in Figure 1.
• relatively moderate air rates are used, but these rates are ramped up to the target maximum while keeping the wellbore temperature below about 350 °C as measured by a string of thermocouples placed in the wellbore.
• combustion by-products such as C0 2 will appear at the surface in the produced gas, indicating that combustion has been achieved in the reservoir.
• Pre-heating the reservoir 20 near the vertical injector well 6a serves a second important purpose because oil at steam temperatures is usually able to auto ignite and start the burning and oil production processes. It also reduces the oil saturation in the sand near the vertical injector, which serves to reduce the strength of the combustion exotherm and prevent over-heating the injector well.
• Coke in region 4 (see Figures 1-4), is constituted of small carbonaceous particles dispersed on the sand grains.
• the hydrogen/carbon ratio is typically 1.13 as measured in laboratory reactors and refinery cokers involving Athabasca bitumen.
• the sands containing coke particles remain substantially permeable to gas, so that the oxidizing gas 22 and the produced combustion gas 4 can readily flow through, contacting cold oil and transferring heat.
• the convective oil heating is so extensive that oil hydrocracking occurs on account of high temperatures produced during coke combustion and the presence of generated hydrogen.
• the present process will operate similarly to the THAI 2 TM (Toe-to-Heel Air Injection) process with regard to the burning mechanism and drainage front.
• Petrobank Energy and Resources Ltd. operating the THAITM process at Conklin, Alberta has reported reservoir temperatures over 600 °C, up to 8 volume percent hydrogen in the produced gas and 3-4 points of bitumen
• THAITM is a registered trademark of Archon Technologies Ltd, of Calgary, Alberta, for the services of licensing of a particular patented method/technology for enhanced oil recovery from petroleum formations.
• Figure 2 is a cross-sectional view along plane B-B of the oil-bearing reservoir 20 and present method shown in Figure 1, with identical components identically itemized to those of Figure 1. This figure shows how the protective oil layer over the horizontal well is formed.
• Figure 3 is a top-down view of the present process showing the oil-bearing reservoir 20, the burned zone 2, the coke fuel deposit zone 4 and the fluid drainage zone 15.
• the oxygen-containing gas injector well 6a is located in the upper part of the oil-bearing reservoir 20 and the horizontal segment 8 of the production well pair 9 is at the base of the reservoir 20.
• the vertical segment 10 of the horizontal/vertical well pair 9 is connected to the horizontal segment 8 at the heel 42 of the production well 9 and connects to the surface oil treating facilities (not shown). While the fluid drainage zone 15 intersects the horizontal well 8 at two points, 17 and 18, nevertheless all produced oil 3 moves inside the horizontal well 8 towards the heel 42 of the horizontal well 8.
• the distance between the projection of the injector well 6a and the drainage entry points 17, 18 into the horizontal well 8 remains substantially equal throughout the operation of the process.
• portion (entry point) 18 of the drainage zone 15 moving towards the heel 42 of the horizontal producer well 8 would advance much faster than that portion (entry point) 17 of drainage zone 15 that moves towards the toe 40, since portion (entry point) 18 is nearer the low pressure heel 42-however that is not the case.
• the cap rock overburden 1 prevents fluids, including oxidizing gas 22, from escaping the oil-bearing reservoir 20.
• Figure 1 also shows the burned zone 2, the coke fuel deposit zone 4, the fluid drainage zone 15, the oxygen-containing gas injector 6a, the horizontal leg 8 of the production well pair 9, and the vertical segment of the horizontal producer 9.
• each of the coke zones 4 and fluid drainage zones 15 move laterally outwardly from the injection well 6a, in two mutually opposite directions, firstly towards the toe 40 and secondly towards the heel 42 of the production well pair 9, as do the fluid entry points 17, 18, and the burned zone 2 expands, (cf Figure 1, and Figure 4) This process continues until the fluid drainage zones 15 reach the toe 40 and the heel 42, which will occur at approximately the same time if the injector well 6a is placed midpoint along the horizontal well 8 of the production well pair 9.
• the oxidizing gas injection rate must be reduced or halted to prevent over-pressuring the reservoir which would either cause fracturing of the reservoir, or force oxygen entry into the horizontal well 8.
• ingress of oxygen or oxygen-containing gas into the horizontal well 8 or vertical well 8 is to be prevented because otherwise oil 3 therein will be capable of burning or exploding thus causing very high temperatures that could damage the production well pair 9 and cause extensive coke formation that could plug the production well pair 9.
• One way of controlling temperature and pressure in horizontal well 8 is to continue the circulation of steam or non- oxidizing gas through wellbore tubing (not shown, but described above) that was used for pre-heating the horizontal well 8. Very low steam rates, typically 1-10 m Id are adequate.
• a thermocouple string (not shown) placed alongside the tubing (not shown) in the horizontal well 8 will alert operators that the steam rate needs to be increased to reduce temperature of horizontal well 8.
• Provision of tubing in horizontal well 8 in addition to allowing provision of steam to pre-heat horizontal well bore 8 and surrounding areas of horizontal well bore 8 and to initiate fluid communication between reservoir 20 and horizontal well 8, may also advantageously be used to supply a diluent to oil 3 in horizontal wellbore 8, and in particular a hydrocarbon diluent such as VAPEX, hydrocarbon solvents or naphtha, or alternatively C0 2 , as suggested in co-pending US patent application 20090308606
• injecting C0 2 into tubing within horizontal well 8 has the advantages of not only acting as a diluent to the oil 3 being collected within the horizontal well 8 and in pool 24 surrounding horizontal well 8, but further serves to slightly pressurize the horizontal well 8 and thereby assist in preventing any ingress of oxidizing gas 22, which if permitted to enter the horizontal well 8 after drawdown of oil layer 24, could create a potentially explosive mixture with the oil 3 therein.
• a new stage of operation begins- the drawdown stage. Specifically, at this point in time there will no longer be sufficient quantities of high temperature gases 5 produced to provide natural gas lift of oil 3 to surface 30 because the entire length of the horizontal well 8 will be covered by layer 24 and sealed with oil 3. Therefore, liquid pumping or artificial gas lift is required to recover the large pool of hot upgraded oil 3 remaining at the base of the reservoir 20.
• the oxidizing gas 22 injection rate into the injector well 6a is then adjusted to maintain an injection pressure substantially below reservoir fracture pressure. A maximum oxidizing gas injection pressure of less than 70% over the reservoir pressure is preferred, and less than 50% over reservoir pressure is most preferred during the drawdown stage.
• the drawdown stage is advantageous because compressed gas requirements are low and output of the compressor 71 providing compressed air as the oxidizing gas 22 can be substantially redirected to new operations that initially require large volumes of oxidizing gas 22.
• the gas/oil ratio is much lower during the drawdown stage which boosts the overall energy efficiency of this process.
• the cumulative air oil ratio can be as low as 715: 1 (m 3 air/m 3 Oil).
• SAGD steam-assisted gravity drainage
• CAL LAW 1655424U In situations where poor reservoir permeability exists, it may be necessary to use a plurality of oxidizing gas injector wells 6a, 6b, as shown in Figure 4 and adapt the method of the present invention accordingly. Accordingly, in a further refinement of the present invention, upon combustion fronts 50 proceeding a specified distance from original oxidizing gas injector well 6a, additional oxidizing gas injector wells 6b, (completed on mutually opposite sides of injector well 6a) may further be, after combustion fronts have progressed outwardly past them as shown in Figure 4, each provided with oxidizing gas (air) 22 via compressor 71 for injection into the reservoir 20 to ensure combustion fronts 50 continue to advance outwardly in the direction of toe 40 and heel 42 of horizontal well and do not fail to advance and/or become extinguished.
• Additional injector wells 6b may be completed on opposite sides of initial injector well 6a prior to initial commencement of the process of the present invention, or alternatively may be drilled and completed upon the process being initiated for a period of time and it becoming apparent that the combustion fronts 50 have advanced to a point where they are too remote from original injector well 6a and require more immediate and proximate supply of oxidizing gas 22 in order for the combustion fronts 50 to progress outwardly along horizontal well 8 and the process thereby continue .
• the further step of utilizing or completing additional gas injection wells 6b may be repeated, as necessary, each on respective outward sides of earlier- completed injection wells 6b, until such time as points of intersection 17, 18 of drainage zone 15 respectively reach toe portion 40 and heel portion 42 of horizontal well 8.
• oxidizing gas injectors are employed from the outset.
• Length 540 meters, 216 grid blocks at 2.5 meters each
• Width 50 m, 20 grid blocks of 2.5 meters each with an element of symmetry, giving a wellbore spacing of 100 m
• a discrete horizontal wellbore of 500 m extended from grid blocks 9 to 208, leaving a 20-meter buffer zone on either end of the horizontal well.
• the inner diameter of the horizontal leg was 9 5/8 inches.
• Run 1 was for the THAI process of US Patent' 191 and is for comparative purposes only.
• Runs 2-7 are with oxidizing gas injectors placed over the horizontal producer well along its length so that the distance between the midpoints between adjacent injectors or the ends of the producer are equal.
• the grid block numbers for the air injector locations were as follows:
• Run 6- 29, 69, 109, 149, 188 It was found that the oil drainage over the horizontal well 8 from each injector well was complete at the same time with this configuration. However, such a configuration of injectors is not imperative. The combustion also worked well with highly asymmetric injector orientations. Compared with the well configuration of US Patent ' 191 (the "THATM" process), where a single injector is placed near the toe of the horizontal producer and has a single drainage front, Runs 2-7 had two drainage fronts for each air injector.
• Runs 1-6 all had the same total maximum air injection rate, 100,000 m /day, so that the efficiency of each Run could be compared with the same air compressor capacity.
• the total air was divided evenly between the injectors.
• Run 2 the single injector 6a received all of the available air, 100,000 m 3 /d
• Run 6 with 5-injectors, received only 20,000 m 3 /d of air per injector.
• Run 7 it was increased from 100,000 to 300,000 m 3 /d total, providing 60,000 m 3 /d of air in each of the 5-injectors.
• the air rate per injector well was ramped-up with the following monthly schedule until the targeted maximum air rate was achieved: 10,000 m 3 /d; 20,000; 33,333; 50,000; 70,000 and 100,000. After all of the desired maximum air rate was the reached this rate was continued until the burning front simultaneously reached the toe and heel of the horizontal producer. At that point, the exit points for the
• 'Peak oil rate' refers to the highest oil rate achieved in a Run. For Runs with 1 or 2-air injectors. Table 2. Numerical simulation results
• Run 2 gave a much higher oil rate after the first year of operation: 47 m 3 /d versus 28 m 3 /d for THAI, for the same injector capital cost and the same rate of air compression cost. This is very important to the economics of oil production and was achieved by simply moving the air injector to a different location relative to THAI.
• the air/oil ratio was substantially lower in Run 2, 1023 instead of 1291.
• a major operating cost of combustion processes is the air compression energy cost and this was accordingly lower by 20% [i.e. (1291 -1023)71291 ] using a single central injector compared with
• CAL_LAW ⁇ 1655424M THAI CAL_LAW ⁇ 1655424M THAI. Additionally to the benefits of high early oil rates and low energy cost, the use of a central injector provided a higher oil recovery factor (percent of original- oil- in - place that is recovered).

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• 2010
  • 2010-03-30 CA CA2698454A patent/CA2698454C/en not_active Expired - Fee Related
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