Patent Application
20090308606
This invention relates to a process for improved productivity when undertaking oil recovery from an underground reservoir by the toe-to-heel in situ combustion process employing a horizontal production well, such as disclosed in U.S. Pat. Nos. 5,626,191 and 6,412,557. More particularly, it relates to an in situ combustion process in which a diluent, namely a hydrocarbon condensate, is injected at the toe of a vertical-horizontal well pair adapted for use in an in situ combustion process.
U.S. Pat. Nos. 5,626,191 and 6,412,557, incorporated herein in their entirety, 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. Air, or other oxidizing gas, such as oxygen-enriched air, is injected through wells 102, which may be vertical wells, horizontal wells or combinations of such wells.
The process of U.S. Pat. No. 5,626,191 is called “THAI™”, an acronym for “toe-to-heel air injection” and the process of U.S. Pat. No. 6,412,557 is called “Capri™”, the Trademarks being held by Archon Technologies Ltd., a subsidiary of Petrobank Energy and Resources Ltd., Calgary, Alberta, Canada.
What is needed is one or more methods to increase productivity when undertaking oil recovery from an underground reservoir by the toe-to-heel in situ combustion process employing horizontal production wells.
The invention, in a broad embodiment, comprises injecting a diluent in the form of a hydrocarbon condensate via tubing at the toe of the toe-to-heel in situ combustion process employed a horizontal production well, which adds to well productivity and advantageously results in various production economies over the THAI and CAPRI processes to date employed.
A hydrocarbon condensate is typically a low-density, high-API gravity liquid hydrocarbon phase that generally occurs in association with natural gas. Its presence as a liquid phase depends on temperature and pressure conditions in the reservoir allowing condensation of liquid from vapor.
The production of condensate from reservoirs can be complicated because of the pressure sensitivity of some condensates. Specifically, during production, there is a risk of the condensate changing from gas to liquid if the reservoir pressure (and thus temperature) drops below the dew point during production. Reservoir pressure (and thus temperature) can be maintained by fluid injection if gas production is preferable to liquid production. Gas produced in association with condensate is called wet gas. The API gravity of condensate is typically 50 degrees to 120 degrees.
The benefit of injection a high-API hydrocarbon condensate (40+API Gravity) into the tubing in a THAI™ or CAPRI™ in situ hydrocarbon extraction method is that a steam generator or water treatment facilities, as are typically required in THAI™ and CAPRI™ in situ hydrocarbon extraction methods, would not be required. This results in a significant expense savings, not only in avoiding the cost of having to divert a portion of the produced hydrocarbon to produce heated steam, but also in having to have the necessary steam generation equipment and pollution control equipment present to do so. Process operations costs would not be increased since the diluent in liquid form is purchased anyway, and typically in prior art methods involving THAI and CAPRI, mixed with the extracted hydrocarbon at the surface in order to better pump the hydrocarbon to storage facilities or refineries.
The diluent would dissolve in the liquid oil in the horizontal wellbore and reduce its viscosity, which would advantageously reduce pressure drop in the horizontal well. It would also reduce the density of the oil, facilitating its rise to the surface by gas-lift.
The addition of a diluent in the form of a hydrocarbon condensate, preferably a liquid, via tubing at the toe of a horizontal production well in a toe-to-heel in situ combustion hydrocarbon recovery process, may be done in combination with any of the steam, water, or oxidizing gas injection methods disclosed in any of U.S. Provisional patent application 60/577,779 filed Jun. 7, 2004 and/or Patent Cooperation Patent Application PCT/CA2005/000883 filed Jun. 6, 2005, each of which are incorporated herein by reference in their respective entireties.
Accordingly, in one broad embodiment of the method of the present invention, the invention comprises a process for extracting liquid hydrocarbons from an underground reservoir comprising the steps of:
In a further broad embodiment of the invention, the present invention comprises a process for extracting liquid hydrocarbons from an underground reservoir, comprising the steps of:
In a still further embodiment of the invention, the present invention comprises the combination of the above steps of injecting a hydrocarbon diluent 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 hydrocarbon condensate contemplated is preferably a condensate selected from the group of condensates consisting of ethane, butanes, pentanes, heptanes, hexanes, octanes, and higher molecular weight hydrocarbons, or mixtures thereof, but may be any other hydrocarbon diluent, such as volatile hydrocarbons such as naphtha or gasoline.
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.
The elements 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.
For example, using an array of parallel horizontal leg as described in U.S. Pat. Nos. 5,626,191 and 6,412,557, 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.
length A-E is 250 m; width A-F is 25 m; height F-G is 20 m.
The positions of the wells are as follows:
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
The operation of the THAI™ 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, is injected into the upper part of the reservoir. 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 of typically 600° C. and as high as 1000° C. are achieved from the high-temperature oxidation of the coke fuel. In the Mobile Oil Zone (MOZ), these hot gases and steam heat the oil to over 400° C., partially cracking the oil, vaporizing some components and greatly reducing the oil viscosity. The heaviest components of the oil, such as asphaltenes, remain on the rock and will constitute the coke fuel later when the burning front arrives at that location. In the MOZ, gases and oil drain downward into the horizontal well, drawn by gravity and by the low-pressure sink of the well. The coke and MOZ zones move laterally from the direction from the toe towards the heel of the horizontal well. The section behind the combustion front is labeled the Burned Region. Ahead of the MOZ is cold oil.
With the advancement of the combustion front, 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.
In order to quantify the effect of fluid injection into the horizontal wellbore, a number of computer numerical simulations of the process were conducted. Steam was injected at a variety of rates into the horizontal well by two methods: 1. via tubing placed inside the horizontal well, and 2. via a separate well extending near the base of the reservoir in the vicinity of the toe of the horizontal well. Both of these methods reduced the predilection of oxygen to enter the wellbore but gave surprising and counterintuitive benefits: the oil recovery factor increased and build-up of coke in the wellbore decreased. Consequently, higher oxidizing gas injection rates could be used while maintaining safe operation.
It was found that both methods of adding steam to the reservoir provided advantages regarding the safety of the THAI™ Process by reducing the tendency of oxygen to enter the horizontal wellbore. It also enabled higher oxidizing gas injection rates into the reservoir, and higher oil recovery.
Extensive computer simulation of the THAI™ Process was undertaken to evaluate the consequences of reducing the pressure in the horizontal wellbore by injecting steam or non-oxidizing gas. The software was the STARS™ In Situ Combustion Simulator provided by the Computer Modelling Group, Calgary, Alberta, Canada.
Table 4. List of Model Parameters.
Simulator: STARS™ 2003.13, Computer Modelling Group Limited
Length 250 m, 100 grid blocks, each
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).
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.
Oxidizing gas(air) injection points: 20, 1, 1:4 (upper 4-grid blocks)
Oxidizing gas injection rates: 65,000 m3/d, 85,000 m3/d or 100,000 m3/d
Steam injection points: 20, 1, 19:20 (lower 2-grid blocks)
Components: water, bitumen, upgrade, methane, CO2, CO/N2, oxygen, coke
Heterogeneity: Homogeneous sand.
Permeability: 6.7 D (h), 3.4 D (v)
Porosity: 33%
Saturations: Bitumen 80%, water 20%, gas Mole fraction 0.114
Bitumen viscosity: 340,000 cP at 10° C.
Bitumen average molecular weight: 550 AMU
Upgrade viscosity: 664 cP at 10° C.
Upgrade average molecular weight: 330 AMU
Reservoir temperature: 20° C.
Native reservoir pressure: 2600 kPa.
Bottomhole pressure: 4000 kPa.
1. 1.0 Bitumen→0.42 Upgrade+1.3375 CH4+20 Coke
2. 1.0 Bitumen+16 O2̂0.05→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
However, as may be seen from the data below, injection of low levels of steam at levels of 5 and 10 m3/day (water equivalent) at a point low in the reservoir (E in
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.
In this example, 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%. Operating with the simultaneous injection of 12 m3/day (water equivalent) of steam at the base of the reservoir via vertical injection well C (see
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
In order to further test the effects of high air injection rates, several runs were conducted with 100,000 m3/day air injection. Results in Table 3a indicate that with simultaneous steam injection at the base of the reservoir (i.e. at location B-E in vertical well C-ref.
Table 3b shows the consequence of injecting steam into the well tubing G (ref.
Table 4 below shows comparisons between injecting oxygen and a combination of non-oxidizing gases, namely nitrogen and carbon dioxide, into a single vertical injection well in combination with a horizontal production well in the THAI™ process via which the oil is produced, as obtained by the STARS™ In Situ Combustion Simulator software provided by the Computer Modelling Group, Calgary, Alberta, Canada. The computer model used for this example was identical to that employed for the above six examples, with the exception that the modeled reservoir was 100 meters wide and 500 meters long. Steam was added at a rate of 10 m3/day via the tubing in the horizontal section of the production well for all runs.
As may be seen from above Table 4 comparing Run 1 and Run 2, when the oxygen and inert gas are reduced by 50% as in Run 2, the oil recovery is nevertheless the same as in Run 1, providing that the inert gas is CO2. This means that the gas compression costs are cut in half in Run 2, while oil is produced faster.
As may further be seen from above Table 4, Run #1 having 17.85 molar % of oxygen and 67.15% nitrogen injected into the injection well, estimated oil recovery rate was 41 m3/day. In comparison, using a similar 17.85 molar % oxygen injection with 67.15 molar % carbon dioxide as used in Run #4, a 3.3 times increase in oil production (136 m3/day) is estimated as being achieved.
As may be further seen from Table 4 above, when equal amounts of oxygen and CO2 are injected as in Run 6, still with a total injected volume of 85,000 m3/day, oil recovery was increased 2.7-fold.
Run 7 shows the benefit of adding CO2 to air as the injectant gas. Compared with Run 1, oil recovery was increased 1.7-fold without increasing compression costs. The benefit of this option is that oxygen separation equipment is not needed.
Referring now to
For a fixed amount of steam injection, 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). Moreover, with carbon dioxide injected in the vertical well, and/or in the horizontal production well, production rates improved production rates can be expected.
Although the disclosure described and illustrates preferred embodiments of the invention, it is to be understood that the invention is not limited to these particular embodiments. Many variations and modifications will now occur to those skilled in the art. For definition of the invention, reference is to be made to the appended claims.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/CA2007/000312 | 2/27/2007 | WO | 00 | 1/29/2009 |
| Number | Date | Country | |
|---|---|---|---|
| 60777752 | Feb 2006 | US |
