Patent Application
20140096961
The present invention relates to a method for effectively directing thermal energy into a heavy hydrocarbon zone overlying a lower zone. More particularly steam, gas or combinations thereof are introduced to the lower zone for contact and thermal heat transfer upward and for stimulation of the overlying heavy hydrocarbons. In one embodiment the lower zone is a water zone, introduced gas being used to drive water radially away from a point of introduction and injected steam riding over the heavier injected gas. Injected steam condenses and gravity drains downward while the associated non-condensable gas accumulates around the point of introduction, creating an insulating layer between the thermal energy and the surrounding heat sinks or thief zones. The result is that heat rises into the overlying heat sink, lessening thermal losses to the underlying water zone. The gas and the steam can be formed in-situ by a downhole burner. In another embodiment, the lower zone is a hydrocarbon zone, steam being used both for lower zone stimulation and for thermal heat transfer upward to the overlying hydrocarbon zone.
It is known to conduct enhanced oil recovery (EOR) of hydrocarbons from subterranean hydrocarbon-bearing formations after primary recovery processes are no longer feasible. Viscous, heavy oil, including bituminous deposits, can be too deep for surface recovery and in-situ methodologies are employed.
Thermal methods include such as in-situ combustion and steam flood, which use various arrangements of stimulation or injection wells and production wells. In some techniques the injection and production wells may serve both duties. Other techniques include cyclic steam stimulation (CSS), in-situ combustion and steam assisted gravity drainage (SAGD). SAGD uses closely coupled generally parallel wells, a horizontally-extending steam injection well forming a steam chamber for mobilizing heavy oil for recovery at a substantially parallel and horizontally-extending production well. Thermal in-situ approaches are typically applied for oilsands which are heavy and viscous, having a gravity of 8-10° API and viscosities ranging from 10,000 to 300,000 cp. Non-thermal approaches include Cold Heavy Oil Production with Sand (CHOPS) in which sand is co-produced with the heavy oil, the oil typically having viscosities in the range of 500 to 15000 cp. In Alberta, the Energy Resources Conservation Board (ERCB) has deemed or classified heavy oils by gravity as an ERCB Crude Oil Density (See directive 17 http://www.ercb.ca/docs/documents/directives/Directive017.pdf, as of October 2009, “crude bitumen wells and heavy oil wells density of 920 kilograms per cubic metre [kg/m3] or greater at 15° C.”). This specific gravity of about 0.92 is equivalent to about 22.3 API or heavier, while bitumen having a specific gravity of about 1.0 has an API gravity of about 10.
Where a heavy oil formation overlies a water zone, where the water forms a base of the formation, typically known as a basal water zone, in-situ techniques become more limited, in part due to the huge thermal heat sink of the water zone. One recovery approach which incorporated the water zone in the recovery was implemented by Shell Canada Limited and the Alberta Oilsands Technology and Research Authority (AOSTRA) in the late 1970's and 1980's in the Peace River leases of Alberta Canada. The approach was termed the pressure-cycle steam drive (PCSD). The PCSD utilized steam injection to heat the basal water zone underlying the oilsand. Once communication was established between wells, continuous steam injection was begun, with the injection and production rates controlled to alternately pressure up and blow down the reservoir (see Alberta Oil Sands Technology and Research Authority, AOSTRA Technical Handbook on Oil Sands, Bitumens and Heavy Oils. Edmonton, 1989). Shell Canada Limited set forth a historical review of resource recovery alternatives in their 2009 application to the Energy Resources Conservation Board (ERCB) of Alberta, CANADA, Carmon Creek Project. Reviewing their own PCSD concept, Shell stated: “steam is injected into the bottom water zone (the lowest 4 m to 6 m of the 25 m-thick reservoir) at high injection rates and pressures. Production rates at producers would vary between periods of low and high rates. This caused cycles of high reservoir pressure during low production rates and low reservoir pressure during high production rates. Expectations were that steam would be forced into the upper parts of the reservoir, and bitumen would be produced by gravity drainage. These expectations were not met during the large-scale development stage, and recovery was found to be uneconomic.”
Applicant understands that CSS techniques were subsequently employed to continue exploitation of this resource. CSS in this circumstance is still associated with difficulties. Typically, an upper injection well, for injecting steam and forming a steam chamber for mobilizing oil, and a lower producer well would have been provided for collecting heated, mobilized oil. The producer well is located about 5 m above the base of the oilsand formation and the injector well another about 5 m above the producer well. The location of the producer well, being about 5 m above the base, is known to be an arrangement to avoid or delay breakthrough from a thief zone or basal water zone. This also results in lost potential to exploit this lower 5 m of what might only be a 15 to 25 m thick zone. This and other thin payzones are still greatly underexploited.
Applicant believes the expense of surface steam production, only to be lost to the large heat sink of the water zone, contributed to the discontinuance of this methodology.
Another well known issue with underlying water zones is the tendency for water coning. The water, being more mobile, preferentially migrates to the production well to the exclusion of the oil resource.
Further, in thermal EOR, heat transfer to overburden has conventionally been an unfortunate energy loss.
Applicant believes that in-situ processes to date have not successfully accommodated due to energy losses and compromised as a result of underlying water. Further, some formations have had stimulation limited to cold production, such as heavy oil in unconsolidated sand, which can be situated in payzones too narrow for SAGD.
Improved techniques are required which recover more of the resource and with favourable economics.
In one embodiment, a method of thermal EOR for subterranean formation is provided comprising introducing thermal energy to a lower zone which underlies a first oil formation in an upper zone. Thermal energy, travelling upwardly through the lower zone, heats this first oil formation from below. The heated oil become mobilized for ready production from the upper zone.
In another embodiment, the lower zone might be isolated from the upper zone by a substantially impermeable layer, such as a caprock or shale layer. Accordingly, the thermal energy travels to the upper zone by conduction, and production from the upper zone is conventional or implements a drive to assist in the production of the mobilized oil.
In another embodiment, the lower zone itself is a second oil formation isolated from the upper, first oil formation. The thermal energy received by the upper zone can be heat lost to the overburden from a thermal EOR being conducted in the lower zone.
A variety of known methodologies can be employed for introducing thermal energy into the lower zone including SAGD arrangements, steam injection, in-situ steam generation and downhole burners.
In another embodiment, a method of thermal EOR is provided comprising introducing gas and steam to a lower zone containing basal water, both of which underlie an oil formation in an upper zone. The heavier gas and lighter steam gravity separate to stratify, forming an insulating layer of gas below a steam layer. Accordingly, the steam is insulated from the substantially infinite heat sink of the basal water wherein the steam transfers a predominate fraction of its thermal energy upwardly to the oil formation thereabove. As above, the thermal energy heats the oil, reducing its viscosity, and mobilizing the oil for production. Where the lower zone is in communication with the upper zone, the steam also serves to drive the mobilized oil to one or more production wells spaced laterally from the location of introduction of the steam. Basal water in the lower zone is progressively driven radially outward, forming a bowl-like interface or inverted cone, exposing ever greater areas of the upper zone to thermal energy. As the steam condenses, the greater density of the condensed water causes it to percolate down through the gas layer to the underlying basal water. In an embodiment, the one or more production wells are completed within the oil formation. In another embodiment, one or more of the temperature, viscosity, or gas is monitored for detection of, location of, or extent of oil mobilization and the one or more production wells are correspondingly completed within the oil formation where the oil has been mobilized. The production wells can be re-completed at different elevations as the mobilization conditions change.
In another embodiment, one or both of the first or second oil formations are heavy oil formations. In another embodiment, the oil formations are oilsand formations. In another embodiment, oil formation is an oilsand formation too thin for conventional exploitation using SAGD. In another embodiment, and as a source of thermal energy, gas and steam are introduced into the lower zone from the operation of a downhole burner. In another embodiment, the downhole burner produces high temperature, hot CO2 gas, and steam is created by the interaction of the hot gas and water, the water being selected from in-situ basal water or injected water.
In a broad embodiment, heat of thermal energy is introduced to a lower zone for delivering heat to an overlying upper zone having at least a first oil formation which benefits from a heated formation, including heavy oil suitable for enhanced oil recovery (EOR). The lower zone can be underburden, even including a water or basal zone, or can be another zone undergoing EOR.
In one embodiment, this first oil formation is a heavy oil zone unsuitable for SAGD for one reason or another, including being too narrow or shallow to accommodate parallel injection and production wells, can benefit from thermal stimulation as disclosed therein. One such form of formation is one produced using Cold Heavy Oil Production with Sand or CHOPS. In conventional CHOPS, oil is co-produced with formation sand with the formation of “wormholes” in the sand formation which allows more oil to reach the production wells. As Applicant understands the mechanism, a low pressure area is created near the production wells, typically using progressive cavity pumps. Solution gas phase changes into a vapour, fluidizes oil and sand that flows into the low pressure area and is produced. In Alberta, Canada, co-production of sand, wormholes and fluidization produces between 3% to 8% of the original oil in place. Further, Applicant believes the existence of wormholes, prevalent in an upper portion of the formation, can contraindicate use of steam enhanced recovery as the wormholes can preferentially channel steam away from target oil.
However, Applicant notes that introducing an additional factor, by creating a foamy oil drive by increasing the temperature by a few degrees, is heretofore unknown in CHOPS production. Herein, a Stimulated Foamy Oil Drive (SFOD) is applicable to virgin or depleted fields with appropriate reservoir conditions. The process can enhance and extend the life of wormhole development. The SFOD process stimulates the first oil formation by subjecting the target reservoir to heat from below, which is received from the underburden or lower zone. This creates a generally linear contiguous temperature increase within the overlying target formation which enhances solution gas release from the liquid oil/water phase. Any source delivering thermal energy to the bottom of the reservoir underburden will facilitate the process. Solution gas is stimulated to disassociate from the fluid state by raising the temperature, enhancing the original drive and recovery mechanisms to a predominant temperature drive. Herein, if a thermal EOR project is already implemented in a lower zone, waste heat will drive the process in the upper zone.
As the overlying heavy oil reservoir responds to the thermal propagation, a foamy oil drive is created which flows through a network of worm-holes into a gathering system of production wells. As voidage is created, and the network of high permeability channels (wormholes) expands, breakthrough occurs which creates a network. Over time, production shifts to a free flowing gravity drain exploitation. The wormhole network grows as the process mobilizes oil, creating voidage which provides a route for bypassed virgin oil to flow into the production wells.
Applying SFOD to depleted CHOPS reservoirs will extend the life of the field, resulting in an increase in oil recovery. For optimal advantage, certain geological and reservoir conditions can dictate which formations are candidates for underburden thermal stimulation. Ideally the lower zone is a second oil formation capable of supporting a thermal EOR project and which happens to be separated from the first oil formation of the upper zone by a low to non-permeable layer or caprock. The target zone is one suitable for supporting a foamy oil drive.
Having reference to
Having reference to
Thermal energy from the process occurring in the lower zone 12 is transferred by conduction, through the substantially non-permeable layer 16, and into the overlying, heavy oil upper zone 10. Heavy oil 20 in the upper zone 10 is mobilized and produced therefrom. Mobilized oil, water, oil or emulsion can be removed as necessary using the producers or recovery wells 24 completed in the lower zone 12, spaced from the thermal source 14.
Having reference to
Having reference to
As shown in
Heavy oil formations benefit most from the embodiments disclosed herein including forms of oil typically recovered using the thermal methods and non-thermal methods described above. The basal water zone 113 is accessed and means are completed for introducing hot non-condensable gases into the water zone. The term non-condensable means the gases are non-condensable at the formation conditions. The term “introducing” includes injecting at a point, such as an injection well 114, into the formation or generation at a point in the formation, such as at a downhole tool 115 situated in the formation. The non-condensable gases can be hot gases which include products of combustion, such as carbon dioxide CO2 which are introduced hot or are formed downhole, such as by a downhole combustor. The pressure injection (Pinj) will be greater than the pressure in the basal water zone (Pbw) and the pressure Pbw in basal water zone 113 will be greater than the pressure in the heavy oil formation Poil. Pressure management can assist with the drive and avoiding gravity drainage of mobilized oil.
Mobility of the heavy oil 120 is poor at initial, in-situ temperature conditions. According, the heavy oil 120 initially forms a low permeability barrier, and hot gases 117, injected into the basal water zone 113, displace the water 112 radially and laterally from the point of introduction, such as the injection well 114, creating a bowl-like interface or inverted cone of rising hot gases 117. The hot gases 117 impart sufficient energy to create steam 116, either from the water 112 in the water zone 113 or injected water. Water is introduced for mixing with the hot gases, or connate water or basal water is heated by the hot gases, creating steam 116. The steam 116 and the hot gases 117 flow out into the basal water zone 113.
Where the hot gas is CO2, the density of the hot gas, at the same downhole pressure and temperature conditions, is several times greater than the density of the steam. Further, the mobility of hot CO2 through the reservoir is less than the steam. Accordingly, the steam 116 tends to gravity separate from the hot gas 117 or CO2 and stratify, the heavier CO2 migrating downward and steam migrating upward. The CO2 forms an insulating layer 119 between the basal water 112 and the steam 116.
Thus the steam 116 rises to contact the overlying heavy oil bearing zone 110, transferring thermal energy Q, as a result of the water's latent heat of vaporization, preferentially to this overlying upper zone 110 as the steam condenses and accordingly heat loss to the basal water 112 is minimized. As steam condenses to water, the water's greater density causes it to percolate down through the CO2 layer and join or mix in with the basal water 112.
Thus transfer of thermal energy Q is maximized to the overlying heavy oil formation 110 and heat loss is minimized to the heat sink of the basal water 112 in the basal water zone 113. In contradistinction, in the prior art PCSD and conventional steam flood processes, introduced heat is designed to flow to the basal water.
As shown in
At original formation conditions the heavy oil can be very viscous, having a viscosity up to the hundreds of thousands of centipoise (cp), being intractable and immobile and unrecoverable using conventional means. In comparison, water has viscosity less than 1 cp. Using a steam 116 and hot gas 117 layer embodiment, having an insulating layer 119, heat Q is now effectively transferred to the heavy oil formation of the upper zone 110. At steam condensation temperatures, the heavy oil viscosity can drop many orders of magnitude and into the hundreds or tens of centipoise, being recoverable using known production well techniques. As heavy oil mobility in the heavy oil formation increases, steam continues to be effectively directed higher and to ever greater radial extent in the heavy oil formation.
As shown in
As shown in
In one embodiment, one can track wellbore temperature and complete or perforate the production well 122 to place perforations 130 in the oil formation according to an oil mobility or thermal profile. The well 122 can be re-completed (
In another embodiment, one would perforate high in the oil zone 110 and rely on bottom water drive to push the mobilized oil up to the production well 122. In another scenario, one might perforate in the middle of the oil zone 110 and rely on a horizontal pressure gradient to push the oil to the production well. And in another scenario, one could operate the hot gas and steam generator injector cyclically. After injection stops, all of the steam will eventually condense and the CO2 migrates to the top of the oil zone forming a gas cap. In this case one could then perforate low in the oil zone 110 and rely on the gas cap to drive the oil to the production well. Any of the scenarios could be used at different stages of the formation or reservoir depletion.
The injection well 114 can inject hot gas, of hot gas and water as water or as steam, or constituents which result in the production of hot gas and steam. One method and apparatus for downhole production of heat in the form of steam and hot combustion gases (primarily CO, CO2, and H2O) is set forth in Applicant's co-pending patent application for apparatus and methods for downhole steam generation and enhanced oil recovery (EOR). The downhole steam generator was filed Jan. 14, 2010 in Canada as serial number 2,690,105 and in the United States published Jul. 22, 2010 as US 2010/0181069 A1, the entirety of both of which are incorporated herein by reference.
In Applicant's co-pending downhole steam generation and EOR, a downhole burner assembly is fluidly connected to a main tubing string, and is positioned within a target zone. The burner assembly creates a combustion cavity by combusting fuel and an oxidant at a temperature sufficient to melt the reservoir or otherwise create a cavity. The burner assembly then continues steady state combustion to create and sustain hot combustion gases for flowing and permeating into the target zone for creating a gaseous drive front. Water is injected into the target zone, uphole of the combustion cavity for creating a steam drive front. Therein, the burner assembly could be positioned within a cased wellbore at the target zone, the burner assembly having a high temperature casing seal adapted for sealing a casing annulus between the downhole burner and the cased wellbore, and a means for injecting water into the target zone above the casing seal. The high temperature casing seal can pass through casing distortions, and is reusable, not being affected substantially by thermal cycling.
A combustion chamber can be formed operating the burner assembly at a temperature sufficient enough to melt the formation of the target zone. Thereafter, steady state combustion is maintained for sustaining a sub-stoichiometric combustion of the fuel and oxygen for producing hot combustion gases (primarily CO, CO2, and H2O) which enter and permeate through the target zone. The hot combustion gases create a gaseous drive front and heat the target zone adjacent the combustion cavity and the wellbore. Addition of water to the target zone along the casing annulus above the combustion chamber injects water into an upper portion of the target zone adjacent the wellbore for lateral permeation therethrough. The lateral movement of the injected water cools the wellbore from the heat of the hot combustion gases and minimizes heat loss to the formation adjacent the wellbore. The water further laterally permeates through the target zone and converts into steam. The steam and the hot combustion gases in the target zone form a steam and gaseous drive front.
Applied in the context of the basal water displacement scenario, and in an embodiment of the present invention, the use of a downhole burner and in-situ generation of steam meets both objectives of producing a hot gas, containing CO2, and generation of steam 116, either through reaction of the energy from the downhole burner and the basal water or the reaction of the energy from the downhole burner and added water. One can anticipate employing the addition of water, such as through the casing annulus, once the basal water is further and further displaced from the injection well.
In another embodiment, also represented graphically by
Accordingly, the steam 116 tends to separate from the CO2, the heavier CO2 migrating downward and steam migrating upward. The CO2 forms an insulating bubble or layer between the underlying zone and the steam thereabove. Thus the steam 116 rises to contact the overlying heavy oil bearing zone 110, transferring the water's latent heat Q of vaporization to this zone as the steam 116 condenses and heat loss to the underlying zone 113 or basal water 112 is minimized. As the water from the steam/heavy oil interface condenses, its greater density causes it to percolate down through the CO2 layer to the lower zone and, in the case of a basal water zone 113, to join or mix in with the basal water 112.
Advantageously, industrially-produced CO2, such as that earmarked for carbon capture, storage or sequestration can be injected from surface for forming the gas bubble or insulating layer 119 at the lower layer and buoying steam 116 thereabove for heat transfer Q to the overlying zone 110.
This application claims the benefits under 35 U.S.C. 120 of the U.S. patent application Ser. No. 13/103,876, filed May 9, 2011, and published as US 2011/0278001 on Nov. 17, 2011, which claims the benefits under 35 U.S.C 119(e) of U.S. Provisional Application No. 61/333,645, filed May 11, 2010, U.S. Provisional Application No. 61/356,416, filed Jun. 18, 2010, and U.S. Provisional Application No. 61/421,481, filed Dec. 9, 2010, which are all incorporated fully herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 61333645 | May 2010 | US | |
| 61356416 | Jun 2010 | US | |
| 61421481 | Dec 2010 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 13103876 | May 2011 | US |
| Child | 14103366 | US |
