GB2481601A

GB2481601A - Solvent injection hydrocarbon recovery process

Info

Publication number: GB2481601A
Application number: GB201010917A
Authority: GB
Inventors: Lars Ha Ier; Jostein Alvestad; Aurelie Lagisquet; Eimund Gilje
Original assignee: Statoil ASA
Current assignee: Equinor ASA
Priority date: 2010-06-28
Filing date: 2010-06-28
Publication date: 2012-01-04
Anticipated expiration: 2030-06-28
Also published as: GB201010917D0; GB2481601B

Abstract

A process for the recovery of hydrocarbon such as bitumen/EHO from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well 5, involves the steps of: preheating an area around and between the wells by circulating hot solvent 1 through the completed interval of each of the wells until sufficient hydraulic communication between both wells is achieved; injecting one of more hydrocarbon solvents into the upper injection well at or above critical temperature of the solvent or solvent mixture to create a solvent chamber, thereby causing a mixture of hydrocarbon and solvent to flow by downwards by gravity drainage and sideways by pressure to the lower production well 5; and producing the hydrocarbon to the surface through the lower production well 5. A non-compressible gas may also be injected into the solvent chamber.

Description

O

SOLVENT INJECTION RECOVERY PROCESS

Field of the Invention

The present invention relates to a solvent injection method for recovery of bitumen and extra heavy oil (EHO).

Background of the Invention

Recent recovery methods include steam assisted drainage (SAGD) and the solvent co-injection variant thereof. Another method is the so-called N-Solv process.

SAGD (Albahiani, A.M., Babadagli, T., "A Critical review of the Status of SAGD: Where Are We and What is Next?", SPE 113283, 2008 SPE Western Regional, Bakersfield California) is a method of recovering bitumen and EHO which dates back to the 1960's.

A pair of wells is drilled, one above the other. The upper well is used to inject steam, optionally with a solvent. The lower well is used to collect the hot bitumen or EHO and condensed water from the steam. The injected steam forms a chamber that grows within the formation. The steam heats the oil/bitumen and reduces its viscosity so that it can flow into the lower well. Gases thus released rise in the steam chamber, filling the void space left by the oil. Oil and water flow is by a countercurrent gravity driven drainage into the lower well bore. Condensed water and the bitumen or EHO is pumped to the surface. Recovery levels can be as high as 70% to 80%. SAGD is more economic than with the older pressure-driven steam process.

The solvent co-injection variant of the SAGD process (Gupta, S., Gittins, S., Picherack, P., "Insights Into Some Key Issues With Solvent Aided Process", JCPT, February 2003, Vol 43, No 2) aims to improve the performance of SAGD by introducing hydrocarbon solvent additives to the injected steam. The operating conditions for the solvent co-injection process are similar to SAGD.

In the N-SoIv process (Nenniger, J.E., Gunnewiek, L, "Dew Point vs Bubble Point: A Misunderstood Constraint on Gravity Drainage Processes", CIPC 2009, paper 065; Nenniger, J.E., Dunn, S.G. "How Fast is Solvent Based Gravity Drainage", CIPC 2008, paper 139), heated solvent vapour is injected into a gravity drainage chamber. Vapour flows from the injection well to the colder perimeter of the chamber where it condenses, delivering heat and fresh solvent directly to the bitumen extraction interface. The N-Solv extraction temperature and pressure are lower than with in situ steam SAGD. The use of solvent is also capable of extracting valuable components in bitumen while leaving high molecular weight coke forming species behind. Condensed solvent and oil then drain by gravity to the bottom of the chamber and are recovered via the production well. Some details of solvent extraction processes are described in CA 2 351 148, CA 2299 790 and CA2 552482.

Definition of the Invention In its broadest sense, the present invention provides a process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, wherein there is hydraulic communication between said wells, the method comprising the steps: injecting one of more hydrocarbon solvents into the upper injection well at or above critical temperature of the solvent or solvent mixture, thereby causing a mixture of hydrocarbons and solvent to collect in the lower production well; and extracting the hydrocarbons from the lower production well.

In another broad sense, the present invention also provides a process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well wherein there is hydraulic communication between said wells, the method comprising the steps: injecting one of more hydrocarbon solvents into the upper injection well so that the temperature of the solvent or solvent mixture in the upper injection well is 90°C or more, thereby causing a mixture of hydrocarbons and solvent to collect in the lower production well; and extracting the hydrocarbons from the lower production well.

A first aspect of the present invention provides a process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, the method comprising the steps: preheating an area around and between the wells by circulating hot solvent through at least part of both of the wells until hydraulic communication between both wells is achieved; injecting one of more hydrocarbon solvents into the upper injection well at or above critical temperature of the solvent or solvent mixture, thereby causing a mixture of hydrocarbons and solvent to collect in the lower production well; and extracting the hydrocarbons from the lower production well.

A second aspect of the present invention provides a process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, the method comprising the steps: preheating an area around and between the wells by circulating hot solvent through the completed interval of each of the wells until hydraulic communication between both wells is achieved; injecting one of more hydrocarbon solvents into the upper injection well so that the temperature of the solvent or solvent mixture in the upper injection well is 90°C or more, thereby causing a mixture of hydrocarbons and solvent to collect in the lower production well; and extracting the hydrocarbons from the lower production well.

A third aspect of the present invention provides a process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, the method comprising the following steps: preheating an area around and between the wells by circulating hot solvent through at least part of both of the wells until sufficient hydraulic communication between both wells is achieved; injecting one or more hydrocarbon solvents into the upper injection well at or above critical temperature of the solvent or solvent mixture, thereby: i) creating a hot solvent chamber consisting of solvent vapour and liquid, ii) mixing of the bitumen and the solvent at the boundary of the solvent chamber so formed, and iii) causing a mixture of the hydrocarbon and solvent to drain downwards by gravity and sideways by pressure gradient towards the lower production well; and producing the mixture to the surface through the lower production well.

A fourth aspect of the present invention provides a process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, the method comprising the steps: preheating the region between the wells by circulating hot solvent through at least part of both of the wells until hydraulic communication between both wells is achieved; injecting one or more hydrocarbon solvents into the upper injection well so that the temperature of the solvent or solvent mixture within the upper injection well is 90°C or more, thereby: i) creating a hot solvent chamber consisting of solvent vapour and liquid, ii) mixing of the bitumen and the solvent at the boundary of the solvent chamber so formed, and iii) causing a mixture of the hydrocarbon and solvent to drain downwards by gravity and sideways by pressure gradient towards the lower production well; and producing the mixture to the surface through the lower production well.

The N-Solv process operates at low temperatures (typically up to 70 °C,) and uses propane as the preferred solvent. This can result in low drainage rates.

SAGD and SAGD with solvent co-injection operate above 200 °C so the energy usage is high.

The present invention offers lower energy utilisation rates and does not require any use of water. 002 emissions are also considerably lower. The present invention also achieves faster oil drainage rates than the N-Solv process due to employing a significantly higher solvent chamber temperature than N-Solv extraction temperature.

De-asphalting of the bitumen/EHO at the boundary layer between the solvent chamber and the bitumen/EHO region can occur also in the high temperature solvent injection process of the present invention.

Detailed Description of the Invention

In essence, the present invention is a gravity-based thermal recovery process of bitumen and extra heavy oil.

The following are features of a non-limiting preferred class of embodiments of this recovery process entails use of a pair of substantially parallel horizontal wells, located above each other, at a vertical distance of typically from 2 to 20 metres, say 5 metres, placed at the bottom of the reservoir. In this configuration, parallel wells may be understood to include equidistant wells, horizontal wells and highly deviated wells.

The area around and between the wells is heated by circulating hot solvent through the completed interval of each of the wells until sufficient hydraulic communication between the wells is achieved.

After the pre-heating period is finished the upper well is converted to an injector and the bottom well to a producer.

A hydrocarbon solvent (or mixture of hydrocarbon solvents) of technical grade is injected in the upper well at or above critical temperature.

A mixture of bitumen/EHO and solvent is produced through the bottom well.

The solvent is separated from the produced well stream and recycled.

Without being bound by any particular theory, it is believed that the mechanisms which underlie the basic process are as follows: -Establishment and expansion of a solvent chamber, -Condensation of the solvent occurs far from the interface with the solvent chamber and the cold bitumen, -The bitumen/EHO is heated by conduction to the solvent temperature in the vicinity of the solvent interface (typically a few meters), -Solubilisation of solvent into oil by mechanical/convective mixing and thereby bitumen/extra heavy oil viscosity reduction, -De-asphalting of the bitumen/EHO (upgrading and viscosity reduction of the bitumen/EHO), -Gravity drainage of bitumen/EHO.

Typical solvents usable in any process of the present invention are hydrocarbons, e.g. lower alkanes, such as propane, butane or pentane, but not limited to these, and mixtures thereof. The critical temperature of a solvent or solvent mixture is readily obtainable from standard texts. However, typical operating well temperature ranges for the process of the present invention, are, particularly for the solvents listed, in the range of 90 -400 °C. The solvent injection rate is adjusted to the reservoir (chamber) properties.

At the end of the production period, the solvent may be back produced by means of injection of non-condensable gas and pressure reduction. However, the injection of non-condensable gas can be employed to advantage in for other purposes.

By "non-condensable gas" is meant any gas or mixture of gases which have condensation (or freezing temperature if not passing through a liquid stage) temperature below 0°C at atmospheric pressure. Typical gauges include nitrogen, lower alkanes such as methane or CO2 and mixtures thereof.

Although the injection of non-condensable gas is particularly preferred in the case of solvent injection recovery process using hot solvent (i.e. using solvent at or above the critical temperature and/or at above 90°C) in the upper injection well, may also be used to advantage in other solvent extraction processes, such as the N-Solv process, where the solvent is injected at a lower temperature.

Thus, a fifth aspect of the present invention provides a process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, the method comprising the steps: circulating solvent through at least part of both of the wells until hydraulic communication between both wells is achieved; injecting one or more hydrocarbon solvents into the upper injection well, thereby: i) creating a solvent chamber consisting of solvent vapour and liquid, ii) mixing of the bitumen and the solvent at the boundary of the solvent chamber so formed, and iii) causing a mixture of the hydrocarbon to be extracted and solvent to drain downwards by gravity and sideways by pressure gradient towards the lower production well; and producing the mixture to the surface through the lower production well; wherein a non-condensable gas is injected into the solvent chamber.

Furthermore, a sixth aspect of the present invention provides a process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, the method comprising the steps: circulating solvent through at least part of both of the wells until hydraulic communication between both wells is achieved; injecting one or more hydrocarbon solvents into the upper injection, thereby: i) creating a solvent chamber, ii) mixing of the bitumen and the solvent at the boundary of the solvent chamber so formed, and iii) causing a mixture of the hydrocarbon and solvent to drain downwards by gravity and sideways by pressure gradient towards the lower production well; and producing the mixture to the surface through the lower production well; wherein a non-condensable gas is injected into the solvent chamber.

Typically non condensable gas injection rate is less than 10% of the solvent rate in order to allow for segregation; the less dense gas (the non-condensable gas) accumulating at the top of the reservoir and creating a blanket while the solvent is pushed downwards and laterally.

The non-condensable gas injection rate is preferably from 25% to 75%, more preferably from 35% to 65%, typically about 50% of the solvent injection rate.

The non-condensable gas or mixture should preferably be injected at a temperature from reservoir temperature up to and including the solvent injection temperature.

Thus, in one preferred class of embodiments according to any aspect of the present invention, a non-condensable gas (which is less dense than the solvent / solvent mixture) may be injected in the injection well so as to displace the solvent / solvent mixture by gravity driven flooding process. In this stage of the process, the solvent / solvent mixture and the injected non-condensable gas are produced through the producer well. The non-condensable gas is separated from the solvent I solvent mixture at the surface and re-injected until sufficient recovery of the solvent I solvent mixture is achieved.

The use of a non-condensable gas may be implemented in a number of different ways.

It may be injected through the same injector(s) as used for the solvent. Alternatively, the solvent may be injected through one or more, preferably vertical, separate injector wells provided explicitly for that purpose. In the latter configuration, additional injection wells are drilled to inject non-condensable gases only in the upper part of the solvent chamber, thereby placing the non-condensable gas directly through separate wells.

This can secure minimum mixing between the non-condensable injection gas and the hot solvents, but with the additional cost connected to drilling, completion and top-side modifications.

A gradual placement (injection) of the non-condensable gas through such a solution will have similar effects on altering the solvent sweep efficiency, and vaporizing and/or displacing main parts of the hot solvents to the producer. At the end of the solvent injection time, the injection of non-condensable gases is continued for a while in order to displace and produce the rest of the oil. Finally, the reservoir pressure is reduced to expand the non-condensable gas, and back-produce as much as possible of the remaining hot solvents and the non-condensable gas.

After a period of injection of hot solvent the injection is stopped, and a high temperature non-condensable gas (e.g. methane and/or nitrogen), preferably at approximately same temperature as the hot solvent) is injected in the horizontal injector-well. Due to the density difference between the non-condensable gas and hot solvents, the high-temperature non-condensable gas will displace hot solvents, migrate upwards and establish a blanket" in the upper parts of the hot solvent chamber. This establishment will partly reduce temperature loss upwards due to an insulation effect, but also alter the further hot solvent chamber development, which will be lower and wider in its development compared to not applying non-condensable gas injection.

The alteration of the hot solvent chamber will expose new areas of bitumen for the hot solvent (typically bitumen "wedges" between producer/injectors pairs), and potentially increase the bitumen recovery though improved sweep efficiency of the hot solvents. In addition, portions of the hot solvents will be recovered, either through displacement to the producers by the non-condensable gas, and/or as vaporized hot solvent components produced in the high-temperature non-condensable gas.

However, instead of a just a single injection of non-condensable gas at or towards the end of the production period, periods of solvent injection and gas injection may be effected alternately. Thus, the procedure above can be repeated in several cycles, i.e. alternating between hot solvent injection and non-condensable gas injection. This results in a gradually increase of non-condensable gases occupying larger and larger portions of the original hot solvent chamber, filling up the original hot solvent chamber from above, altering the hot solvent sweep efficiency, and vaporizing and/or displacing main parts of the hot solvents to the producer.

In general, solvent and non-condensable gas could be separated from the produced well-stream, ready to be cycled back in the reservoir or sold for other applications.

In the case of alternating cycles of gas and solvent and gas injection, the last injection period of these cycles is preferably a long injection period with non-condensable gas, to displace the remaining gas-phase of the hot solvent and vaporize out remaining intermediate components from the hot solvent and bitumen/EHO in the reservoir, produced out as gas.

The following method is particularly suited to injections in horizontal production/injection well pairs. After the last injection period, the reservoir pressure may be reduced to expand the non-condensable gas, and back-produce as much as possible of the remaining hot solvents and the non-condensable gas.

The injection of non-condensable gas can provide one or more advantages, including increased economic efficiency due to solvent recovery/recycling, impoved overall extraction, less variation of EHO recovery rate over time and higher extraction rates per unit volume of solvent.

As mentioned above, the technique of injecting a non-condensable gas may be used equally in other solvent recovery processes, e.g. the N-Solv process, and therefore, any reference herein to that technique wherein the solvent is at an elevated temperature such as i.e. at or above the critical temperature of the solvent and/or at above 90 °C, and the non-condensable gas is injected at a temperature ranging from reservoir temperature up to and including the solvent critical temperature, should be interpreted as equally, a reference to and disclosure of the same technique wherein the solvent and/or non-condensable gas is at a lower temperature.

Brief Description of the Drawings

Figure IA shows a vertical cross section perpendicular to the horizontal well pair used in a recovery process according to the present invention, viewed along the wells; Figure lB shows an expanded detail of the solvent chamber -bitumen/EHO transition region; Figure 2A shows a vertical cross-section corresponding to that shown in Figure 1A, before injection of non-condensable gas; Figure 2B shows the cross-section of Figure 2A after a single injection of non-condensable gas; and Figure 2C shows the cross-section of Figure 2B after n' cycles of non-condensable gas.

Description of Preferred Embodiments

Figure 1A shows a vertical section perpendicular to the horizontal well pair used in a recovery process according to the present invention. The outer boundary of the solvent chamber is denoted by reference numeral 3. Situated below the upper well 1 is a production well 5. Hot solvent in vapour form is injected into the upper injection well 1 as denoted by arrows 7.

During the start-up period and prior to well conversion, the volume I region between the injection well 1 and the producing well 5, is pre-heated by circulation of hot solvent until sufficient hydraulic communication is established between the upper and lower wells.

Bitumen/EHO flows (9) into the well.

Injection of hydrocarbon solvents as mentioned above causes a mixture of bitumen/EHO and solvent to: -drain downwards by gravity and sideways by pressure gradient to the lower well and -be produced to the surface through the lower well by conventional well lifting means including down-hole pumps.

At the surface, the solvent can be recovered for recycling.

Figure 1 B shows an expanded detail of the solvent chamber -bitumen/EHO transition region. Solubilisation of solvent into the bitumen/EHO occurs by diffusive and convective mixing in the solvent chamber -bitumen/EHO transition region. The bitumen/EHO is de-asphalted in the presence of higher solvent concentration. As a result of both phenomena stated above, a lower viscosity mixture of bitumen/EHO and solvent flows by gravity drainage to the producing well 5.

Figures 2A through 2C show how a non-condensable gas may be used for solvent recovery and/optimised EHO/bitumen recovery.

Figure 2A shows the solvent chamber as used in the process described above with reference to Figures 1A and 1 B. The reference numerals refer to the same integers as in the earlier drawings.

Figure 2B shows the situation after a single injection of non-condensable gas in the form of methane and/or nitrogen. In this case, the gas is injected into the well used for introduction of solvent, after solvent injection has been stopped. It can be seen that a gas blanket 11 forms at the top of the solvent chamber 3. This exposes new bitumen wedges for subsequnt recovery.

Figure 2C shows the situation after subsequent further cycles of solvent injection and gas injection. The gas blanket 11 increases in volume. Recovery is further enhanced.

Eventually, sufficient gas may be injected to displace most of the solvent for recovery, thus improving the overall efficiency of the process.

In the light of the described embodiments, modifications to these embodiments, as well as other embodiments, all within the spirit and scope of the present invention, for example as defined by the appended claims, will now become apparent to persons skilled in the art.

Claims

CLAIMS: 1. A process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, the method comprising the steps: preheating the region between the wells by circulating hot solvent through at least part of both of the wells until hydraulic communication between both wells is achieved; injecting one or more hydrocarbon solvents into the upper injection well at or above critical temperature of the solvent or solvent mixture, thereby: iv) creating a hot solvent chamber consisting of solvent vapour and liquid, v) mixing of the bitumen and the solvent at the boundary of the solvent chamber so formed, and vi) causing a mixture of the hydrocarbon and solvent to drain downwards by gravity and sideways by pressure gradient towards the lower production well; and producing the mixture to the surface through the lower production well.
2. A process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, the method comprising the steps: preheating the region between the wells by circulating hot solvent through at least part of both of the wells until hydraulic communication between both wells is achieved; injecting one or more hydrocarbon solvents into the upper injection well so that the temperature of the solvent or solvent mixture within the upper injection well is 90°C or more, thereby: i) creating a hot solvent chamber consisting of solvent vapour and liquid, iv) mixing of the bitumen and the solvent at the boundary of the solvent chamber so formed, and v) causing a mixture of the hydrocarbon and solvent to drain downwards by gravity and sideways by pressure gradient towards the lower production well; and producing the mixture to the surface through the lower production well.
3. A process according to either preceding claim, wherein solvent is separated from the extracted mixture for recycling.
4. A process according to any preceding claim, wherein the preheating step heats the region between the upper injection well and the lower production well until sufficient hydraulic communication is established between the upper and lower wells
5. A process according to any preceding claim, wherein during the preheating step, the wall of the upper injection well is preheated to a temperature in the range from 75°C to 500°C, preferably from 90°C to 300°C.
6. A process according to any preceding clam wherein the hydrocarbon comprises bitumen and/or EHO.
7. A process according to any preceding claim, wherein a non-condensable gas is injected into the solvent chamber.
8. A process according to claim 7, wherein the non-condensable gas is injected via one or more injectors used for injection of the solvent or solvent mixture.
9. A process according to claim 7, wherein the non-condensable gas is injected via one or more injector wells communicating directly with the solvent chamber.
10. A process according to any one of claims 7 to 9, wherein the non-condensable gas is injected towards the end of or after the solvent injection.
11. A process according to any of claims 7 to 10, wherein the non-condensable gas and solvent are injected during respective alternating periods.
12. A process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, the method comprising the steps: circulating solvent through at least part of both of the wells until hydraulic communication between both wells is achieved; injecting one or more hydrocarbon solvents into the upper injection well, thereby: vii) creating a solvent chamber consisting of solvent vapour and liquid, viii) mixing of the bitumen and the solvent at the boundary of the solvent chamber so formed, and ix) causing a mixture of the hydrocarbon and solvent to drain downwards by gravity and sideways by pressure gradient towards the lower production well; and producing the mixture to the surface through the lower production well; wherein a non-condensable gas is injected into the solvent chamber.
13. A process for the recovery of hydrocarbons from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, the method comprising the steps: circulating solvent through at least part of both of the wells until hydraulic communication between both wells is achieved; injecting one or more hydrocarbon solvents into the upper injection, thereby: i) creating a solvent chamber, vi) mixing of the bitumen and the solvent at the boundary of the solvent chamber so formed, and vii) causing a mixture of the hydrocarbon and solvent to drain downwards by gravity and sideways by pressure gradient towards the lower production well; and producing the mixture to the surface through the lower production well; wherein a non-condensable gas is injected into the solvent chamber.
14. A process according to claim 12 or claim 13, wherein the non-condensable gas is injected via one or more injectors used for injection of the solvent or solvent mixture.
15. A process according to claim 12 or claim 13, wherein the non-condensable gas is injected via one or more injector wells communicating directly with the solvent chamber.
16. A process according to any one of claims 12 to 15, wherein the non-condensable gas is injected towards the end of or after the solvent injection.
17. A process according to any of claims 12 to 16, wherein the non-condensable gas and solvent are injected during respective alternating periods.t::r: INTELLECTUAL . ...* PROPERTY OFFICE Application No: GB 1010917.1 Examiner: Dr Lyndon Ellis Claims searched: 1-17 Date of search: 14 July 2010 Patents Act 1977: Search Report under Section 17 Documents considered to be relevant: Category Relevant Identity of document and passage or figure of particular relevance to claims X 1-17 W02008/009114 Al (Nenniger) Whole document X 1-17 US2008/0017372 Al (Gates) Whole document Categories: X Document indicating lack of novelty or inventive A Document indicating technological background and/or state step of the art.Y Document indicating lack of inventive step if P Document published on or after the declared priority date but combined with one or more other documents of before the filing date of this invention.same category.& Member of the same patent family E Patent document published on or after, but with priority date earlier than, the filing date of this application.Field of Search:Search of GB, EP, WO & US patent documents classified in the following areas of the UKCX: Worldwide search of patent documents classified in the following areas of the IPC 1E21B The following online and other databases have been ised in the preparation of this search report EPODOC, WPI International Classification: Subclass Subgroup Valid From E21B 0043/24 01/01/2006 E21B 0043/16 01/01/2006 Intellectual Property Office is an operating name of the Patent Office www.ipo.gov.uk