Patent Application
20190169970
The general technical field relates to in situ hydrocarbon recovery operations, and more particularly to steam-assisted hydrocarbon recovery operations.
Many in situ techniques exist for recovering hydrocarbons from subsurface reservoirs. One technique is called Steam-Assisted Gravity Drainage (SAGD) and employs a pair of vertically-spaced horizontal wells drilled into a reservoir. High-pressure steam is continuously injected into the overlying injection well to heat the hydrocarbons and reduce viscosity, causing the heated hydrocarbons and condensed water to drain under the force of gravity into the underlying production well. Multiple SAGD well pairs typically extend in parallel relation to each other from a well pad.
In SAGD operations, steam generation and water treatment are typically performed in a central processing facility, while the well pairs are located in remote hydrocarbon recovery areas that include at least one well pad and several SAGD wells. Production fluids recovered from the production wells are also pumped from each remote hydrocarbon recovery area to the central processing facility for treatment. Production fluids are typically water-hydrocarbon emulsions and can also include vapours. The pipeline infrastructure between the central processing facility and remote hydrocarbon recovery areas is thus designed and operated to accommodate large flow rates of steam and production fluid. High pressure steam pipelines running over long distances can be costly to install and maintain, and high flow rate production fluid pipelines require large pipes and pumps to enable transportation of the hydrocarbons and water.
In the central processing facility, there are various units for treating the production fluid in order to recover the hydrocarbons as well as treat the produced water phase to enable reuse in steam generation. Typical steam generators, such as Once-Through Steam Generators (OTSG) and drum boilers, can be large and expensive and can be shared by more than one remote hydrocarbon recovery area and/or multiple well pads.
Generation of steam at the central processing facility and transportation of steam and production fluids between the central processing facility and remote hydrocarbon recovery areas can lead to various inefficiencies and costs.
Various challenges still exist in the area of SAGD hydrocarbon recovery, steam generation as well as water treatment and recycling.
In some implementations, there is provided a Steam-Assisted Gravity Drainage (SAGD) method for recovering hydrocarbons from a reservoir, the method including: generating steam and CO2 from feedwater, fuel and oxygen; transferring a steam-CO2 mixture comprising at least a portion of the steam and at least a portion of the CO2, to a proximate SAGD injection well; injecting the steam-CO2 mixture into the SAGD injection well; obtaining produced fluids from a SAGD production well underlying the SAGD injection well; transferring the produced fluids for separation proximate to the SAGD production well; separating the produced fluids to obtain a produced gas and a produced emulsion; transferring the produced emulsion for separation proximate to the SAGD production well; separating the produced emulsion to obtain a produced hydrocarbon-containing component and produced water; supplying at least a portion of the produced water as at least part of the feedwater; and supplying the produced hydrocarbon-containing component to a central processing facility.
In some implementations, transferring the steam-CO2 mixture includes transferring all of the CO2.
In some implementations, the steam-CO2 mixture comprises between about 1 wt % to about 12 wt % of CO2.
In some implementations, the feedwater further comprises makeup water.
In some implementations, the concentration of the makeup water in the feedwater is about 0 wt % to about 90 wt %.
In some implementations, the concentration of the makeup water in the feedwater is about 0 wt % to about 20 wt %.
In some implementations, the concentration of the makeup water in the feedwater is about 0 wt % to about 10 wt % of the feedwater.
In some implementations, the concentration of the makeup water in the feedwater is about 0 wt % to about 5 wt % of the feedwater.
In some implementations, the method further includes: controlling contaminants in the feedwater by regulating relative proportions of the makeup water and the produced water.
In some implementations, there is provided a Steam-Assisted Gravity Drainage (SAGD) system for recovering hydrocarbons from a reservoir, the system including: a central processing facility; and a remote hydrocarbon recovery facility connected to the central processing facility by a supply line, the remote hydrocarbon recovery facility including: a steam generator for receiving feedwater and generating a steam-based mixture therefrom; a well pad supporting a SAGD well pair comprising: a SAGD injection well in fluid communication with the steam generator to receive the steam-based mixture; and a SAGD production well for recovering produced fluids from the reservoir; a water-hydrocarbon separator in fluid communication with the SAGD production well to receive the produced fluids and produce a produced water component and a produced hydrocarbon-containing component, the supply line being in fluid communication with the separator to transport the produced hydrocarbon-containing component to the central processing facility.
In some implementations, the steam generator comprises a Direct-Fired Steam Generator (DFSG).
In some implementations, the steam-based mixture comprises a steam-CO2 mixture that includes steam and combustion gases produced by the DFSG.
In some implementations, the system further includes: a gas-emulsion separator in fluid communication with the SAGD production well to receive the produced fluids and produce a produced gas and gas-depleted produced fluids, the water-hydrocarbon separator being configured to receive the gas-depleted produced fluids.
In some implementations, the system further includes a produced gas line for transporting the produced gas from the gas-emulsion separator to the central processing facility.
In some implementations, the system further includes: a water recycle line for recycling at least a portion of the produced water from the water-hydrocarbon separator as at least part of the feedwater to the DFSG.
In some implementations, recycling at least a portion of the produced water includes recycling all of the produced water.
In some implementations, the feedwater further comprises makeup water.
In some implementations, the system further includes: a makeup water line for supplying the makeup water to the steam generator from a water source.
In some implementations, the water source comprises a water tank located at the remote hydrocarbon recovery facility.
In some implementations, the water source comprises a water treatment facility.
In some implementations, the water source comprises a natural water source.
In some implementations, the system further includes: a fuel line for supplying fuel from the central processing facility to the steam generator.
In some implementations, the system further includes: an oxygen supply assembly for supplying an oxygen-containing gas to the steam generator for combustion.
In some implementations, the water-hydrocarbon separator comprises a free water knockout drum.
In some implementations, the water-hydrocarbon separator further comprises a treater.
In some implementations, the water-hydrocarbon separator further comprises a skim tank.
In some implementations, the water-hydrocarbon separator further comprises an induced floatation unit.
In some implementations, the water-hydrocarbon separator further comprises a walnut shell filtering unit.
In some implementations, the water-hydrocarbon separator further comprises a slop-oil tank.
In some implementations, the system further includes: a diluent line to supply a diluent to the produced fluids to produce diluted produced fluids that are separated in the water-hydrocarbon separator.
In some implementations, the diluent line is connected upstream of the water-hydrocarbon separator.
In some implementations, the diluent line is in fluid communication with the central processing facility to receive the diluent therefrom.
In some implementations, the diluent line is in fluid communication with a diluent tank or diluent truck located at the remote hydrocarbon recovery facility.
In some implementations, the hydrocarbon-containing component is a hydrocarbon mixture containing an amount of water.
In some implementations, the amount of water in the hydrocarbon mixture is of up to about 10 wt %.
In some implementations, the central processing facility comprises a second water-hydrocarbon separator for receiving the hydrocarbon mixture and separating the hydrocarbon mixture into treated water and produced hydrocarbons.
In some implementations, the system further includes: a second recycle line for conveying at least a portion of the treated water back to the remote hydrocarbon recovery facility to recycle at least a portion of the treated water as part of the feedwater to the steam generator.
In some implementations, there is provided a method for generating steam for a Steam-Assisted Gravity Drainage (SAGD) operation comprising a SAGD well pair that includes a SAGD injection well overlying a SAGD production well extending into the reservoir from a well pad, the method including: supplying makeup water from a distant central processing facility to the well pad; and proximate to the well pad: separating produced fluids recovered from the SAGD production well into produced water and a produced hydrocarbon-containing component, and generating steam from feedwater comprising at least a portion of the produced water and at least a portion of the makeup water.
In some implementations, the concentration of the makeup water in the feedwater is about 0 wt % to about 90 wt %.
In some implementations, the concentration of the makeup water in the feedwater is about 0 wt % to about 20 wt %.
In some implementations, the concentration of the makeup water in the feedwater is about 0 wt % to about 10 wt % of the feedwater.
In some implementations, the concentration of the makeup water in the feedwater is about 0 wt % to about 5 wt % of the feedwater.
In some implementations, the step of generating steam is performed in a Direct-Fired Steam Generator (DFSG) and comprises producing an injection gas mixture of steam and CO2 for injection into the SAGD injection well.
In some implementations, the method further comprises: controlling a content of the CO2 in the injection gas mixture.
In some implementations, the content of the CO2 in the injection gas mixture is maintained at or below about 12 wt %.
In some implementations, the content of the CO2 in the gas mixture is maintained at or below about 4 wt %.
In some implementations, the content of the CO2 in the injection gas mixture is maintained sufficiently low such that the produced fluids include at most about 12 wt % CO2.
In some implementations, the content of the CO2 in the injection gas mixture is maintained sufficiently low such that the SAGD operation has an oil rate, a cumulative oil recovery, and/or a steam-to-oil ratio (SOR) substantially similar to no CO2 injection.
In some implementations, the method further includes: controlling contaminants in the feedwater by regulating relative proportions of the makeup water and the produced water.
In some implementations, there is provided a method for recovering hydrocarbons in a Steam-Assisted Gravity Drainage (SAGD) operation the SAGD operation comprising a SAGD well pair that includes a SAGD injection well overlying a SAGD production well extending into the reservoir from a well pad, the method comprising: proximate to the well pad: recovering produced fluids from the SAGD production well; separating the produced fluids into produced water and a produced hydrocarbon-containing component; generating steam from feedwater comprising the produced water; and injecting the steam into the SAGD injection well; and supplying the produced hydrocarbon-containing component to a distant central processing facility.
In some implementations, the method further includes: proximate to the well pad: separating the produced fluids recovered from the SAGD production well into a produced gas and a produced emulsion; and separating the produced emulsion into the produced water and the produced hydrocarbon-containing component.
In some implementations, the method further includes: supplying the produced gas to the distant central processing facility.
In some implementations, the feedwater further comprises makeup water at least partially obtained from the distant central processing facility.
In some implementations, there is provided a method for recovering hydrocarbons from a reservoir, including: generating steam from feedwater; transferring the steam to a proximate SAGD injection well, injecting the steam mixture into the SAGD injection well; obtaining produced fluids from a SAGD production well underlying the SAGD injection well; transferring the produced fluids for separation proximate to the SAGD production well; separating the produced fluids to obtain a produced gas and a produced emulsion; transferring the produced emulsion for separation proximate to the SAGD production well; separating the produced emulsion to obtain a produced hydrocarbon-containing component and produced water; supplying at least a portion of the produced water as at least part of the feedwater; and supplying the produced hydrocarbon-containing component to a central processing facility.
In some implementations, the feedwater further comprises makeup water transported from a water source.
In some implementations, the water source is a water tank located at the remote hydrocarbon recovery facility.
In some implementations, the water source is a water treatment facility.
In some implementations, the water source is a natural water source.
In some implementations, the step of generating steam further includes generating an injection gas mixture comprising steam and CO2 using a Direct-Fired Steam Generator (DFSG).
It should be understood that various implementations of the methods and systems described herein can include various further features described herein.
Various techniques are described for recovering oil from a reservoir in a SAGD operation using remote steam generation and water-hydrocarbon separation. Instead of being located and operated solely at a central processing facility, steam generators and water-hydrocarbon separators can be located and operated directly at corresponding remote hydrocarbon recovery facilities located at a distance from the central processing facility. The water-hydrocarbon separators can be used to separate water from production fluids and the produced water can be recycled as feedwater to the steam generators. In some implementations, remote steam generation and water-hydrocarbon separation can reduce heat loss, pipeline and pump sizes, and energy losses.
In some implementations, the steam generators located and operated at the remote hydrocarbon recovery facilities include Direct-Fired Steam Generators (DFSG). A DFSG is a steam generator that generates steam by directly contacting feedwater with a hot combustion gas. It is to be noted that a DFSG can also be referred to as a Direct-Contact Steam Generator (DCSG). The hot combustion gas is produced using fuel, such as natural gas, and an oxidizing gas, such as air or an oxygen-enriched gas mixture. Depending on the oxidizing gas and fuel that are used, the combustion gas can include carbon dioxide (CO2) as well as other gases such as carbon monoxide (CO), nitrogen based compounds such as nitric oxide (NO) and nitrogen dioxide (NO2) and/or sulfur based compounds such as sulfur oxides. Typically, a DFSG includes a fuel inlet for receiving fuel supply, an oxidizing gas inlet for receiving oxygen supply and a water inlet for receiving feedwater supply. The fuel and oxidizing gas can be premixed prior to reaching a burner and a flame is generated in a combustion chamber. Feedwater is typically not allowed to come in direct contact with the flame and can be run down the combustion chamber in jacketed pipes and into an evaporation chamber. The hot combustion gas evaporates the feedwater in the evaporation chamber, generating an outlet stream including steam and combustion gas.
Using DFSGs at the remote hydrocarbon recovery facilities is facilitated due to their small size and scalability. The CO2 included in the combustion gas can be co-injected with the steam directly into the SAGD injection well. Co-injection of the CO2 with the steam can reduce the need to separate and dispose of the CO2 by other means.
In some implementations, a water-hydrocarbon separation unit at each of the remote hydrocarbon recovery facilities allows for at least some of the produced water to be directly recycled back to the DFSG as feedwater for steam generation. This recycling of produced water is facilitated by the DFSG's ability to operate effectively with lower feedwater quality, in some scenarios with feedwater quality that is considered unacceptable for use in an OTSG or drum boiler.
Hydrocarbon Recovery with DFSG Located Proximate to Well Pad and Water Recycling
Referring to
It should be understood that “located at a distance” means that the hydrocarbon recovery facilities are not located in proximity to the central processing facility. It is typical for the central processing facility to be located several kilometers from the remote hydrocarbon recovery facilities being supported. It should also be understood that a “remote hydrocarbon recovery facility” is a facility that is located in a geographical area and includes at least one well pad with corresponding SAGD well pairs, at least one steam generator and at least one water-hydrocarbon separator. The steam generator and the water-hydrocarbon separator are installed in proximity to the at least one well pad. In this context, it should be understood that “in proximity” means that the steam generator and water-hydrocarbon separator are located on the well pads for supplying steam to the wells of the same well pad and treating production fluids retrieved from the same well pad; on an adjacent well pad of the same hydrocarbon recovery facility; or in the general area as the well pads of the given hydrocarbon recovery facility and remote from the central processing facility. Some examples of “in proximity” could mean that the steam generator and water-hydrocarbon separator are located within about 200 meters, about 100 meters, about 50 meters, or even about 20 meters of the well pads.
Referring to
Still referring to
Still referring to
Various implementations of remote steam generation and water separation for reuse as boiler feedwater can provide certain economic advantages, such as (i) using smaller and less expensive lines for conveying the produced hydrocarbon-containing component 30 back to the central processing facility 27, (ii) not using a steam line between the central processing facility 27 and the remote hydrocarbon recovery facility 15, and (iii) in some cases, not using a boiler feedwater pump. In some implementations, the production wells are equipped with subsurface pumps that enable the feedwater to have sufficient pressure to be directly fed to the DFSG 14.
Referring to
It is understood that the produced hydrocarbon-containing component 30 can refer to either the hydrocarbon mixture 130 or the produced hydrocarbons 131. The hydrocarbon mixture 130 refers to a produced hydrocarbon-containing component including and an amount of water. The produced hydrocarbons 131 refer to a produced hydrocarbon-containing component from which water has been substantially removed by at least one water-hydrocarbon separation component such as a treater.
Referring to
Now referring to
Still referring to
In some implementations, a FWKO is located at the remote hydrocarbon recovery facility 15 while at least one other type of water-hydrocarbon separation component is located at the central processing facility 27 or a separate water treating facility 15. Such water-hydrocarbon separation components can include a treater, a skim tank, a gas assisted floatation unit, a walnut shell filtration unit or a slop-oil tank.
In some implementations, the water-hydrocarbon separator is a high-temperature water-hydrocarbon separator that allows separating water and hydrocarbons at high temperatures between about 210° C. and about 240° C., or between about 220° C. and about 230° C., or of about 225° C., and at pressures between about 2200 kPag and about 2800 kPag, or between about 2300 kPag and about 2700 kPag, or of about 2500 kPag. At such temperatures and pressures, the hydrocarbons (such as bitumen) become sufficiently heavier than water, are separated by gravity and no diluent is added. The hydrocarbons are not diluted for transport, but are kept at a temperature between about 80° C. and about 100° C., or between about 85° C. and about 95° C., or of about 90° C. In such cases, the pipeline conveying the hydrocarbons back to the central processing facility 27 is designed and built to keep the temperature high.
Referring to
In the case of co-injection of steam and CO2 in the injection well, such as when DFSGs are used for steam generation, the CO2 can diffuse and disperse into the hydrocarbons beyond the edge of the depletion chamber. The CO2 is soluble in the hydrocarbon phase, and higher CO2 contents in the hydrocarbon phase lower the hydrocarbon phase viscosity. The presence of CO2 in the vapour phase compensates for the lower steam partial pressure and temperature.
Implementations with Multiple DFSGs
In some implementations, the remote steam generators include multiple DFSGs that are located at each remote hydrocarbon recovery facility. Providing multiple DFSGs at a single remote hydrocarbon recovery facility can facilitate operational flexibility and easier maintenance. For example, in the event the recycled produced water used as feedwater contains high levels of contaminants and impurities (such as residual hydrocarbons, inorganic compounds or suspended solids), fouling can occur in the DFSGs. Fouling can lead to maintenance, in which case one DFSG can be taken off line for maintenance while the other DFSG(s) located at the same remote hydrocarbon recovery facility maintains the required rate of steam injection.
Now referring to
In addition, it should be noted that by preceding an element with the indefinite article “a”, it should be understood that one or several elements can be used. For example, one or several DFSGs, gas-emulsion separators, water-hydrocarbon separators, well pads, Injection wells or production wells can be used at each remote hydrocarbon recovery facility.
Referring to
Simulations were performed with the following operating strategy: a maximum producer rate of 300 m3/day and an initial steam-CO2 gas injection pressure set at about 1500 kPa for about 4.5 years and at about 1000 kPa thereafter. The CO2 content of the gas was set at 0%, 3%, 6% or 12%. The model also took into account geology; oil, gas and water properties; fluid viscosities, well locations and properties.
Table 1 shows simulation results of the amount of CO2 stored in a reservoir as a function of the CO2 fraction in the injected steam-CO2 gas mixture.
These results show that a high proportion of CO2 can be stored in the reservoir. At CO2 fractions of 3% and 6%, the proportion of CO2 stored in the reservoir remains constant, while at 12% the storage percentage decreases by 2%.
Referring to
Simulations were performed with the following operating strategy: a maximum steam rate of 500 m3/day and a producer pressure of about 1500 kPa for about 4.5 years and of about 1000 kPa thereafter. The CO2 content of the gas was set at 0%, 3%, 6% or 12%. The model also takes into account geology; oil, gas and water properties; fluid viscosities, well locations and properties.
Table 2 shows simulation results of the amount of CO2 stored in a reservoir as a function of the CO2 fraction in the steam.
These results show that a high proportion of CO2 can be stored in the reservoir. At CO2 fractions of 3% and 6%, the proportion of CO2 stored in the reservoir remains constant, while at 12% the storage percentage decreases by 1%.
| Number | Date | Country | Kind |
|---|---|---|---|
| 2847881 | Mar 2014 | CA | national |
This application is a Divisional Application under 35 U.S.C. § 120 of U.S. patent application Ser. No. 14/671,104, filed on Mar. 27, 2015, and claims priority under 35 U.S.C. § 119 to Canadian application Serial No. 2,847,881, filed on Mar. 28, 2014, each of which is incorporated herein by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 14671104 | Mar 2015 | US |
| Child | 16269005 | US |
