CARBON DIOXIDE REMOVAL FROM STEAM PRODUCT FROM DIRECT CONTACT STEAM GENERATION PROCESS

Abstract

A system for carbon dioxide removal from product from a direct contact steam generation system is provided. The system comprises a direct contact steam generation system, a pressurized heat recovery system, and a CO.sub.2 separation system, wherein the direct contact steam generation system converts a gaseous, liquid or solid fuel, in the presence of oxygen, using a moderate water, to produce a mixed vapour stream to be then led into the pressurized heat recovery system to produce a partially condensed product, which is led into the CO.sub.2 separation system to reduce the CO.sub.2 content to produce a CO.sub.2-lean liquid product, and the pressurized heat recovery system utilizes latent heat of the mixed vapour stream to produce a lower pressure vapour stream from the CO.sub.2-lean liquid product exiting the CO.sub.2 separation system.

Claims

1. A system for carbon dioxide removal from a product from a direct contact steam generation system, comprising: the direct contact steam generation system; a pressurized heat recovery system; a CO.sub.2 separation system; 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, the fuel, oxygen and water are introduced into the direct contact steam generation system through inlets, to produce a mixed vapour stream; wherein the mixed vapour stream is then led into the pressurized heat recovery system through connecting means between the direct contact steam generation system and the pressurized heat recovery system to produce a partially condensed product; wherein the partially condensed product is led into the CO.sub.2 separation system through connecting means between the pressurized heat recovery system and the pressurized heat recovery system; wherein the CO.sub.2 separation system reduces the CO.sub.2 content from the partially condensed product to produce a CO.sub.2-lean liquid product; and wherein the pressurized heat recovery system utilizes a latent heat of the mixed vapour stream to produce a lower pressure vapour stream from the CO.sub.2-lean liquid product exiting the CO.sub.2 separation system.

2. The system according to claim 1, wherein the pressurized heat recovery system comprises at least one heat exchanger.

3. The system according to claim 1, wherein the pressurized heat recovery system comprises a plurality of heat exchangers and the heat exchangers are arranged in parallel, series, or a combination thereof.

4. The system according to claim 2, wherein a duty of any single heat exchanger has an upper limit of 100 MW (thermal).

5. The system according to claim 1, wherein the vapour stream is at a pressure of 0-200 bar and in a temperature range from 100 to 1000 C.

6. The system according to claim 1, wherein a pressure differential between an outlet of the direct contact steam generation and an outlet of the CO.sub.2 separation system is such that the minimum approach temperature of the heat exchangers is at least 30 C.

7. The system according to claim 1, wherein removal of the CO.sub.2 content in the CO.sub.2 separation system is by at least one of a single stage flash, multi-stage flash, packed column and trayed column.

8. The system according to claim 1, wherein the CO.sub.2 separation system comprises one or more low pressure CO.sub.2 separators, one or more high pressure CO.sub.2 separators, or both.

9. The system according to claim 1, wherein the CO.sub.2 content in the CO.sub.2-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.

10. The system according to claim 1, wherein the water and gas introduced into the direct contact steam generation system are produced from a Steam Assisted Gravity Drainage system.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0035] By way of example only, preferred embodiments of the present invention are described hereinafter with reference to the accompanying drawings, wherein:

[0036] FIG. 1 is a process flow diagram of the general process and system according to the present disclosure for removing CO.sub.2 from steam.

[0037] FIG. 2 is a process flow diagram of the process and system according to an illustrative preferred embodiment of the present disclosure for removing CO.sub.2 from steam using a CO.sub.2 separation column.

[0038] FIG. 3 is a process flow diagram of the process and system according to an illustrative preferred embodiment of the present disclosure for removing CO.sub.2 from steam using multiple heat exchangers.

DETAILED DESCRIPTION OF THE INVENTION

[0039] The present invention discloses a method and system of processing flue gas to separate the CO.sub.2 from the steam for sequestration.

[0040] The system comprises three components: [0041] a direct contact steam generation system; [0042] a pressurized heat recovery system; and [0043] a CO.sub.2 separation system.

[0044] 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 CO.sub.2 content.

[0045] Referring to FIG. 1, an embodiment of the system of the present invention is shown.

List of Reference Characters in FIG. 1

[0046] 1 direct contact steam generation system [0047] 2 pressurised heat recovery system [0048] 3 CO.sub.2 separation system [0049] 4 a gaseous, liquid, or solid fuel entering the direct contact steam generation system [0050] 5 oxidant entering the direct contact steam generation system [0051] 6 moderator water entering the direct contact steam generation system [0052] 7 mixed vapour stream exiting the direct contact steam generation system and entering the pressurised heat recovery system [0053] 8 blowdown/Ash exiting the direct contact steam generation system to the atmosphere [0054] 9 blowdown exiting the pressurised heat recovery system [0055] 10 partially condensed steam and CO.sub.2 mixture exiting the pressurised heat recovery system and entering the CO.sub.2 separation system [0056] 11 CO.sub.2-lean liquid product exiting the CO.sub.2 separation system and entering the pressurised heat recovery system [0057] 12 low pressure vapor stream exiting the pressurised heat recovery system [0058] 13 blowdown exiting the CO.sub.2 separation system [0059] 14 CO.sub.2 exiting the CO.sub.2 separation system

[0060] Referring to FIG. 1, the three components operating together are further described in detail below:

[0061] 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 CO.sub.2.

[0062] 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.

[0063] The mixed vapour stream 7 exiting the direct contact steam generation system 1 is then led into a pressurized heat recovery system 2.

[0064] As shown in FIG. 1, the pressurized heat recovery system 2 is connected to the direct contact steam generation system 1 and the CO.sub.2 separation system 3, such that the pressurized heat recovery system 2 utilizes the latent heat of the mixed vapour stream 7 to produce a lower pressure vapour stream 12 from the CO.sub.2-lean liquid product 11 exiting the CO.sub.2 separation system 3, achieved in a single or multiple heat exchanger(s) (not shown) arranged in parallel or series (or a combination thereof) configurations contained within the pressurized heat recovery system 2.

[0065] A preferred embodiment would place an upper limit of 100 MW (thermal) on the duty of any single heat exchanger.

[0066] In general, it would be preferable to select the pressure differential between the direct contact steam generation outlet and the CO.sub.2 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.

[0067] 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.

[0068] The CO.sub.2 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 CO.sub.2 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 CO.sub.2 in the liquid phase (predominantly water) is controlled.

[0069] Depending on system configuration, the CO.sub.2 content in the CO.sub.2-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.

[0070] FIG. 2 is a scheme of an illustrative preferred embodiment comprising a direct contact steam generation system, pressurized heat recovery system, and a CO.sub.2 separation system using a CO.sub.2 separation column.

List of Reference Characters in FIG. 2

[0071] 1 direct contact steam generation system (combustor/steam generator) [0072] 2 pressurized heat recovery system [0073] 3a carbon dioxide/water separation column (may act as, or being part of, a CO.sub.2 separation system) [0074] 15 recycled water heat exchanger [0075] 16 reflux condenser [0076] 17 recycle water pump [0077] 18 reflux pump [0078] 19 boiler feed pump [0079] 20 reflux vessel

[0080] Referring to FIG. 2, flue gas (shown as stream 21) coming out of the direct contact steam generation (combustor/steam generator) 1 is condensed inside of a pressurized heat recovery system 2.

[0081] 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 CO.sub.2/Water Separation Column (shown as 3a) where it flows counter-current to injected liquid condensate, which further removes water from the flue gas.

[0082] CO.sub.2/Water Separation Column 3a may act as, or being part of, a CO.sub.2 separation system 3 as noted hereinabove.

[0083] 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 CO.sub.2 composition of >85 mol % suitable for sequestration.

[0084] 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).

[0085] 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 % CO.sub.2 (shown as stream 32) suitable for Steam Assisted Gravity Drainage applications.

[0086] 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.

[0087] FIG. 3 is a process flow diagram of the process and system according to an illustrative preferred embodiment of the present disclosure for removing CO.sub.2 from steam using multiple heat exchangers.

List of Reference Characters in FIG. 3

[0088] 1 direct contact steam generation (DC SG) system [0089] 40 superheater [0090] 41 heat exchanger 1 [0091] 42 heat exchanger 2 [0092] 43 heat exchanger 3 [0093] 44 heat exchanger 4 [0094] 45 heat exchanger 5 [0095] 46 feed water heater 1 (FWH1) [0096] 47 feed water heater 2 (FWH2) [0097] 48 high pressure CO.sub.2 separator (HP SEP) [0098] 49 high pressure separator chiller (HPSC) [0099] 50 low pressure CO.sub.2 separator (LP SEP) [0100] 51 low pressure separator chiller (LPSC) [0101] 52 pump 1 [0102] 53 pump 2 [0103] 54 pump 3 [0104] 55 pump 4 [0105] 55 air cooler 1 (AC1) [0106] 57 vessel 1 [0107] 58 vessel 2

[0108] The Streams as depicted in FIG. 3 and their characteristics are summarized below:

TABLE-US-00001 Stream # Description Comments 61 Oxidant supply 62 Produced gas from Steam Assisted Gravity Drainage (SAGD) facility 63 Fuel supply 64 Produced water from SAGD facility 65 Produced water/Recycle Water 66 Preheated water 67 Preheated water 180-300 C., 20-200 barg 68 Blowdown 1-5% of stream 6 69 direct contact steam generation 200-1000 C. product gas 70 Partially condensed DCSG product gas 71 Partially condensed DCSG product gas 72 Partially condensed DCSG product gas 73 Partially condensed DCSG product gas 74 Partially condensed DCSG product gas 75 Partially condensed DCSG product gas 76 Partially condensed DCSG product gas 77 Partially condensed DCSG product gas 150-350 C. 78 HP SEP off-gas 110-300 C., 10-100 barg, 79 HP SEP off-gas condensate 80 Chilled HP SEP off-gas 20-200 C. 81 HP SEP condensate 82 HP SEP condensate 83 LP SEP off-gas 100-300 C. 84 LP SEP off-gas condensate 85 Chilled LP SEP off-gas 20-200 C. 86 LP SEP condensate 87 CO.sub.2 88 Dry CO.sub.2 89 CO.sub.2 dryer condensate 90 LP SEP condensate 91 Recycle water 92 Evaporator feed water 93 Partially evaporated water 94 Partially evaporated water 95 Partially evaporated water 96 Partially evaporated water 97 Partially evaporated water 98 Blowdown 99 Saturated vapour 100 Superheated steam (CO.sub.2 lean) 150-350 C., 0-5% CO.sub.2

[0109] The system and method describe herein uses a new process configuration for separating CO.sub.2.

[0110] 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 CO.sub.2 separation if required.

[0111] By utilizing this system, the product stream can be varied over the life of a reservoir.

[0112] The system and method described can vary the amount of CO.sub.2 separation and can be used to vary the CO.sub.2 separation over the life of a reservoir.

[0113] Preferably, the CO.sub.2 fraction of the injected steam is controlled to within 0-5% by mass.

[0114] 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.