Patent Application
20200001232
The invention relates to separation and removal of carbon dioxide (CO2) from steam product from the direct contact steam generation process.
Climate change has been widely recognized as an environmental threat to the world. A recent report by the International Energy Agency shows that with the current climate policies, temperature is likely to increase by between 3.6 and 5.3° C., with most of that increase occurring in this century. A temperature increase of this magnitude would cause significant hardship to mankind, for example, in the form of rising sea levels, reduced freshwater and food availability.
Globally, annual emissions of carbon dioxide, the primary greenhouse gas, reached 37.1 billion tonnes in 2018, their highest level ever. During the last decade, worldwide annual emissions growth was higher than at any time in the past. So far, the world has not effectively responded to this challenge. Because of the global nature of climate change, most countries have been reluctant to undertake significant effort to reduce emissions without a guarantee that others will do the same, perceiving that the majority of benefits from such an effort will accrue to other countries. The European Union has implemented an emission trading system as well as renewable energy targets, and conditions the stringency of its domestic emission reduction targets on action by other countries. Canada and other countries have also taken modest steps to reduce emissions. However, Canada is falling behind other countries in the ambition and scope of its climate policies, and appears almost certain to miss (by a significant margin) its 2020 emission reduction target. Canada has repeatedly affirmed its commitment to avoiding dangerous climate change.
The direct contact steam generation process was initially developed in response to, inter alia, interests by Canadian oil producers to investigate the benefits of co-injection of CO2 into Steam Assisted Gravity Drainage reservoirs. The approach generates a mixed stream of steam and CO2.
Generally speaking, a field unit oxygen-fired steam generator utilizing the direct contact steam generation technology operating at ambient pressure or above may produce a flue gas stream containing <15 mol % CO2 content.
Concerns over the impact of the high CO2 concentration on an oil well's overall production rates, throughout its active life, lead to the need for a method of controlling the CO2 content of the injected steam prior to its injection.
Therefore, a method of separating CO2 from flue gas is required in order to generate a high purity CO2 stream (>85 mol % CO2) suitable for sequestration. The remaining flue gas is predominantly steam for Steam Assisted Gravity Drainage applications.
Current carbon capture methods utilize chemical scrubbing, membrane gas separation, or other techniques, for example, biological technologies. It is possible to get a low degree of separation by utilizing a condensation/evaporator scheme.
In order for chemical scrubbing to be applied to Steam Assisted Gravity Drainage and CO2 sequestration operations, additional equipment and energy are required for chemical regeneration and release of the captured CO2 from the absorbent chemical.
Currently, commercially available membranes that selectively transmit CO2 are typically used for natural gas processing. The CO2 permeability of these membranes are negatively impacted by condensable species in the flue gas, making them inappropriate for separating CO2 from steam. Additionally, the separated CO2 is at low pressure, thus require recompression to make suitable for sequestration.
Current biological technologies are generally unsuitable for high temperature applications, making it infeasible for separating CO2 from steam. An impractically large volume of biomass would also be required for processing the projected system output rate.
Current single stage condensation/evaporator schemes have low separation efficiencies and are thermally inefficient.
Therefore, there remains the need for a method of efficiently controlling the CO2 fraction of the injected steam.
The present disclosure describes a method for removal of carbon dioxide (CO2) from steam product from the direct contact steam generation process.
According to one aspect of the invention, there is provided a system for carbon dioxide removal from product from a direct contact steam generation system, comprising:
wherein the direct contact steam generation system converts a gaseous, liquid or solid fuel, in the presence of an oxidant and using a moderator water, said fuel, oxygen and water are introduced into the direct contact steam generation system through inlets, to produce a mixed vapour stream,
wherein said mixed vapour stream is then led into the pressurized heat recovery system through connecting means between the direct contact steam generation system and pressurized heat recovery system to produce a partially condensed product,
wherein said partially condensed product is led into the CO2 separation system through connecting means between the pressurized heat recovery system and pressurized heat recovery system,
wherein the CO2 separation system reduce the CO2 content from said partially condensed product to produce a CO2-lean liquid product, and
wherein the pressurized heat recovery system utilizes latent heat of the mixed vapour stream to produce a lower pressure vapour stream from the CO2-lean liquid product exiting the CO2 separation system.
According to one embodiment of the invention, the pressurized heat recovery system comprises at least one heat exchangers.
According to one embodiment of the invention, the pressurized heat recovery system comprises a plurality of heat exchangers, said heat exchangers are arranged in parallel, series, or a combination thereof, configurations.
According to one embodiment of the invention, duty of any single heat exchanger has an upper limit of 100 MW (thermal).
According to one embodiment of the invention, the vapour stream is at a pressure of 0-200 bar and in a temperature range from 100 to 1000° C.
According to one embodiment of the invention, pressure differential between outlet of the direct contact steam generation and outlet of the CO2 separation system is such that the minimum approach temperature of the heat exchangers is at least 30° C.
According to one embodiment of the invention, removal of CO2 content in the CO2 separation system is by at least one of a single stage flash, multi-stage flash, packed column and trayed column.
According to one embodiment of the invention, the CO2 separation system comprises one or more low pressure CO2 separators, one or more high pressure CO2 separators, or both.
According to one embodiment of the invention, CO2 content in the CO2-lean liquid product is reduced to between 0 to 5% by mass before being sent back to the pressurized heat recovery system to be re-evaporated.
According to one embodiment of the invention, the water and gas introduced into the direct contact steam generation system are produced from a Steam Assisted Gravity Drainage system.
Other features and advantages of the present invention will become apparent from the following detailed description and the accompanying drawings, which illustrate, by way of example, the principles of the invention.
By way of example only, preferred embodiments of the present invention are described hereinafter with reference to the accompanying drawings, wherein:
The present invention discloses a method and system of processing flue gas to separate the CO2 from the steam for sequestration.
The system comprises three components:
A person skilled in the art would understand that each component as identified above may be oriented in various ways depending on the operator's required capacity and the requirement of the CO2 content.
Referring to
Referring to
The direct contact steam generation system 1 converts a gaseous, liquid or solid fuel 4, in the presence of oxygen 5, all of which have been introduced into the direct contact steam generation system 1 through inlet(s), and using moderator water 6, to produce a mixed vapour stream 7. The mixed vapour stream 7 contains approximately 85-95% by mass of water and 5-15% by mass of CO2.
The combustor in the direct contact steam generation system 1 may be operated in fuel-rich or fuel-lean modes depending on the operator's requirements. The vapour stream may be at a pressure of 0-200 bar and in a temperature range from 100 to 1000° C.
The mixed vapour stream 7 exiting the direct contact steam generation system 1 is then led into a pressurized heat recovery system 2.
As shown in
A preferred embodiment would place an upper limit of 100 MW (thermal) on the duty of any single heat exchanger.
In general, it would be preferable to select the pressure differential between the direct contact steam generation outlet and the CO2 separation system such that the minimum approach temperature (i.e., temperature difference between the leaving process liquid and the entering liquid) of the heat exchangers is at least 30° C. This temperature difference can be reduced. However, the reduction may result in excessively large heat exchanger sizes.
A person skilled in the art would understand that the number and/or size of the heat exchanger(s) to be employed depend on the capacity of the facility and the required steam generation rate.
The CO2 separation system manipulates the partially condensed product, which is produced from the direct contact steam generation system and then passed through the pressurized heat recovery system, in order to reduce the CO2 content in the liquid phase to the desired level. The separation may be achieved through a single stage flash, multi-stage flash, packed column or trayed column. The temperature and pressure of the liquid phase is manipulated such that the solubility of CO2 in the liquid phase (predominantly water) is controlled.
Depending on system configuration, the CO2 content in the CO2-lean liquid product 11 may be reduced to between 0 to 5% by mass before being sent back to the pressurized heat recovery system to be re-evaporated.
Referring to
The vapour phase (shown as stream 22) coming out of the pressurized heat recovery system 2 is then flashed and directed into the bottom of the CO2/Water Separation Column (shown as 3a) where it flows counter-current to injected liquid condensate, which further removes water from the flue gas.
CO2/Water Separation Column 3a may act as, or being part of, a CO2 separation system 3 as noted hereinabove.
The flue gas then follows stream 23 and 24 where it is passed through reflux condenser 16 and into reflux vessel 20 where the condensate (shown as stream 26) is separated from the flue gas (shown as stream 25), which now has a CO2 composition of >85 mol % suitable for sequestration.
The liquid condensate stream out of reflux vessel 20 is then re-pressurized through a reflux pump 18 as stream 27 and mixed with the liquid condensate from pressurized heat recovery system 2 (shown as stream 35) before being injected into the top of separation column 3a (shown as stream 28).
The liquid stream coming out of separation column 3a is re-pressurized and directed to the pressurized heat recovery system 2 (shown as stream 29, 30, and 31) where said stream captures the heat from the direct contact steam generation system 1 (through its outlet) flue gas to produce high-purity steam containing <2 mol % CO2 (shown as stream 32) suitable for Steam Assisted Gravity Drainage applications.
Alternatively, the liquid condensate stream coming out of the separation column 3a may be cooled with recycled water heat exchanger 15 and to within operational limits of recycle water pump shown as 16, and re-pressurized for injection back into the direct contact steam generation system (combustor/steam generator) 1 as shown by streams 36, 37 and 38.
The Streams as depicted in
The system and method describe herein uses a new process configuration for separating CO2.
By operating the system as described herein over a range of pressures, the separation efficiency can be varied thereby allowing the system to produce a high degree of CO2 separation if required.
By utilizing this system, the product stream can be varied over the life of a reservoir.
The system and method described can vary the amount of CO2 separation and can be used to vary the CO2 separation over the life of a reservoir.
Preferably, the CO2 fraction of the injected steam is controlled to within 0-5% by mass.
Although the present invention has been described in considerable detail with reference to certain preferred embodiments thereof, other embodiments and modifications are possible. Therefore, the scope of the appended claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole.
This application claims priority to U.S. Provisional Application Ser. No. 62/691,697, filed Jun. 29, 2018, the entire contents of which are incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 62691697 | Jun 2018 | US |
