Method and system for managing impure CO2 injection

Abstract

A method comprising: reducing the pressure of a carbon dioxide injection stream using a first pressure reducer having a depth and producing a reduced-pressure carbon dioxide stream; reducing the pressure of the reduced-pressure carbon dioxide stream using a second pressure reducer located at a lower depth than the first pressure reducer to produce a further reduced-pressure carbon dioxide stream; and injecting the further reduced-pressure carbon dioxide stream into a reservoir having a depth; wherein the pressure of the carbon dioxide stream at the depth of the first pressure reducer is greater than the bubble point pressure of the carbon dioxide injection stream at the depth of the first pressure reducer; and wherein the pressure of the further reduced-pressure carbon dioxide stream at the depth of the reservoir is less than the minimum fracture pressure of the reservoir at the depth of the reservoir.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims priority to U.S. Provisional Patent Application No. 63 / 353,039, filed on June 17, 2022. Background Art

[0003] Existing industrial processes, such as power generation, will require the capture of carbon dioxide (CO2) to mitigate the effects of climate change. The captured CO2 stream typically requires the removal of water and light components, such as nitrogen, before utilization or storage. However, some components, such as hydrogen, are not easily removed. Hydrogen can exacerbate phase separation, leading to the formation of a hydrogen-rich gas phase that can embrittle metals in pipelines or wells. Other impurities can exacerbate the formation of the gas phase.

[0004] It is desirable to maintain a single-phase CO2 flow at the injection site to ensure smooth flow into the injection well, prevent hydrogen embrittlement, and prevent acid formation. Single-phase flow can be ensured by maintaining the pressure above the bubble point pressure, which is defined as the pressure at which the first vapor bubble forms in the liquid phase at a given temperature. For deeper formations, injection pressures high enough are required to keep the CO2 in a single phase. However, shallower reservoirs require lower injection pressures and therefore run the risk of phase separation. The reservoir itself imposes additional constraints, with a minimum fracture pressure, above which the formation may be damaged to the point where the CO2 can escape from the reservoir. Summary of the Invention

[0005] Disclosed herein is a method and system for injecting a CO2 stream into an underground formation. The CO2 stream can pass through a first pressure reducer (such as a control valve) at the surface, which can bring a first pressure drop to the CO2 stream and maintain the CO2 stream above its bubble point pressure. The CO2 stream can then enter a vertical wellbore that includes a second pressure, such as a control valve, an orifice plate, or a throttle valve, to produce a second pressure drop. The CO2 stream then enters the reservoir at a pressure lower than the minimum fracture pressure to avoid initiating and expanding the fracture of the reservoir rock. The pressure at the point of injection into the reservoir rock can be measured in real time and fed to a ground controller that actuates the control valve to open to maintain desired pressure. The controller operation can be designed to include both the first pressure drop and the second pressure drop to simultaneously eliminate the release of hydrogen caused by phase separation at the surface and to alleviate the excessive pressure at the bottom of the well.

[0006] Chemical additives can also be used in the CO2 stream to reduce the bubble point pressure, thereby ensuring that the CO2 stream remains above the bubble point pressure and below the minimum burst pressure. Chemical additives can also change the composition of the CO2 stream to an extent that reduces the risk of phase separation and hydrogen release. BRIEF DESCRIPTION OF THE DRAWINGS

[0007] These drawings illustrate certain aspects of some of the embodiments of the present disclosure and should not be used to limit or define the present disclosure:

[0008] Figure 1 is a schematic diagram depicting a method of injecting a stream of carbon dioxide into a subterranean reservoir according to the present disclosure.

[0009] Figure 2 It is a depiction Figure 1 Schematic diagram of a modification of the invention wherein the bypass stream is combined with one or more chemical additives.

[0010] Figure 3 is a two-phase envelope diagram of two carbon dioxide streams with different compositions.

[0011] Figure 4 This is a graph showing the pressure and temperature distribution of the injection well as a function of depth under three conditions. DETAILED DESCRIPTION

[0012] The present disclosure relates to methods and systems for injecting a CO2 stream into an underground formation. In addition, the present disclosure includes methods and systems for using a pressure reducer to meet the dual constraints of bubble point pressure and minimum fracture pressure, so that the CO2 stream remains single-phase and maintains the integrity of the underground formation. The methods and systems disclosed herein can be used in processes such as submarine drilling and enhanced oil recovery. The CO2 stream can pass through a first pressure reducer (such as a control valve) at the surface, which can cause a first pressure drop to the CO2 stream and keep the CO2 stream above its bubble point pressure. The CO2 stream can then enter a vertical wellbore that includes a second pressure reducer, such as a control valve, orifice plate, or throttle valve, to produce a second pressure drop. The CO2 stream then enters the reservoir at a pressure below the minimum fracture pressure to avoid initiating and extending fractures in the reservoir rock. The pressure at the point of injection into the reservoir rock can be measured in real time and fed to a surface controller that actuates the control valve to open to maintain the desired pressure. The controller operation can be designed to include a first pressure drop and a second pressure drop to simultaneously minimize or eliminate the release of hydrogen caused by phase separation at the surface and alleviate excessive bottom hole pressure.

[0013] In some embodiments, the CO2 stream can pass through a plurality of pressure reducers, wherein the plurality of pressure reducers can be at least two, at least three, or at least four pressure reducers, wherein at least two, at least three, or at least four pressure drops can be applied to the CO2 stream. Alternatively, the CO2 stream can pass through two or more pressure reducers, wherein the two or more pressure reducers can produce two or more pressure drops on the CO2 stream. In some embodiments, the controller operation can be designed to include two or more pressure drops to minimize or eliminate hydrogen release caused by phase separation at the surface and to alleviate excessive bottom hole pressure.

[0014] Chemical additives can also be used in the CO2 stream to lower the bubble point pressure, thereby ensuring that the CO2 stream remains above the bubble point pressure and below the minimum burst pressure. Chemical additives can also change the composition of the CO2 stream to mitigate the risk of phase separation and hydrogen release.

[0015] Chemical additives suitable for use in the disclosed methods and systems include, but are not limited to, methane, cyclohexane, and dimethyl ether of polyethylene glycol. Chemical additives suitable for use in the disclosed methods and systems can be effective solvents for CO2 and hydrogen. Chemical additives suitable for use in the disclosed methods and systems can react with hydrogen. The reaction of the chemical additive with hydrogen can be exothermic.

[0016] Figure 1 is a schematic diagram depicting a method for injecting a CO2 stream into a subsurface reservoir according to the present disclosure. The CO2 injection stream 102 can be delivered via a pipeline or other form of transport, such as a tanker, railcar, ship, or any suitable means of transport. The CO2 injection stream 102 can contain impurities such as hydrogen, nitrogen, carbon monoxide, oxygen, hydrogen sulfide, and water. The CO2 injection stream 102 can be reduced in pressure by a first pressure reducer 110. In some embodiments, the first pressure reducer 110 can be located at the surface 120. In some embodiments, the first pressure reducer 110 can be a dynamic pressure reducer, which can be defined as a pressure reducing device with a variable flow coefficient, such as a control valve. The reduced pressure of the CO2 stream 112 exits the first pressure reducer 110 and can be further reduced in pressure by a second pressure reducer 130 at a depth lower than the first pressure reducer 110. In some embodiments, the second pressure reducer 130 can be a static pressure reducer, which can be defined as a pressure reducing device with a flow coefficient that is solely a function of the flow characteristics and the geometry of the pressure reducer, such as an orifice plate or throttle valve. In some embodiments, the second pressure reducer 130 can be a dynamic pressure reducer. The further depressurized CO2 stream 132 can then be injected into the reservoir 140. In some embodiments, the second depressurizer 130 can be located at a depth near the first depressurizer 110 or the reservoir 140, or at the same depth as the reservoir 140, and the depth can be selected based on the flow characteristics and composition of the CO2 injection stream 102.

[0017] The CO2 injection stream 102 can be maintained above the bubble point pressure to maintain the CO2 injection stream 102 in a single phase and also to maintain the further depressurized CO2 stream 132 below the minimum fracture pressure of the reservoir 140. The formation of a gas phase at the wellhead may result in corrosion from acid gas shedding and hydrogen embrittlement, and if two-phase flow occurs, expensive corrosion-resistant alloys may be required. Operating under these two constraints may be complicated by the fact that the static head of the CO2 column increases the pressure at the bottom of the injection well 100 due to gravity. The use of a first pressure reducer 110 and a second pressure reducer 130 (which may be static pressure reducers) offsets the pressure increase of the static head and allows both constraints to be met at a given flow rate of CO2 into the reservoir 140.

[0018] The second pressure reducer 130 can also be used to reduce the temperature difference between the formation and the CO2 near the confined zone. The confined zone can be defined as the geological layer that forms the top of the reservoir 140 by preventing the vertical flow of CO2 and / or other fluids. When the second pressure reducer 130 is located below the confined zone, for a given flow rate, the pressure drop from the surface 120 to the reservoir 140 can be transferred from the first pressure reducer 110 to the second pressure reducer 130. The reduced pressure drop across the first pressure reducer 110 can result in a lower temperature drop, which can increase the temperature of the depressurized CO2 stream 112 and can reduce the thermal expansion difference between the well casing, concrete, and the formation, especially near the bottom of the confined zone.

[0019] In some embodiments, the flow coefficient of the second pressure reducer 130 can be changed, for example, by removing and replacing the second pressure reducer 130 in the case of a static pressure reducer, or by utilizing a dynamic pressure reducer as the second pressure reducer 130. The flow coefficient of the second pressure reducer 130 may need to be changed due to changes in the behavior of the reservoir 140, seasonal changes in ground temperature, regulation conditions requiring low injection flow rates, gradual increases in reservoir 140 pressure over time as more CO2 is injected, and changes in the composition of the CO2 injection stream 102.

[0020] When considering multiple injection wells that share a pipeline or a connecting pipeline network, it is also beneficial to change the flow coefficient of the second pressure reducer 130. The pipeline can operate at a sufficiently high pressure to inject CO2 into the injection well 100 that requires the highest pressure, due to factors including but not limited to the greater depth of the reservoir 140, the higher CO2 temperature (i.e., closest to the CO2 compressor), the lower injection rate and the higher CO2 flow rate. The injection rate can be defined as the difference between the reservoir 140 pressure and the bottom pressure of the injection well 100, as a function of the CO2 flow rate, in units of flow rate per unit pressure. In some embodiments, the injection well 100 may require a lower pressure to inject and may require a larger pressure drop across the second pressure reducer 130, which corresponds to a larger temperature drop by Joule-Thompson cooling. In turn, a lower CO2 temperature may increase the density of CO2, thereby further reducing the wellhead pressure.

[0021] The temperature of the CO2 injection stream 102 can also be controlled by increasing or decreasing the temperature of a compressor (not shown) that delivers the CO2 injection stream 102 to a pipeline (not shown). As a surprising result, the thermal mass of the CO2 injection stream 102 can be high enough to maintain a high temperature over tens of kilometers of pipeline without the CO2 injection stream 102 reaching ambient temperature. The elevated temperature can then reduce the differential expansion between the well casing, concrete, and the formation (not shown).

[0022] The injection well 100 may include a central conduit through which a decompressed CO2 stream 112 is injected, the central conduit being surrounded by an annular space (not shown) isolated at the top and bottom of the annular space. A heat transfer fluid (such as water) may be circulated through the annular space to transfer geothermal heat to the well along the length of the annular space, thereby reducing thermal stress. The heat transfer fluid may also be monitored to perform pressure tests and / or radioactive tracer tests. The heat transfer fluid may be circulated through a piping loop (not shown) inserted into the annular space. The piping loop may be attached and / or clamped to the well.

[0023] In some embodiments, the first pressure reducer 110 can be controlled by a controller 160, which can change the flow coefficient of the first pressure reducer 110 in response to one or more sensors, including a flow sensor F1 on the CO2 injection stream 102, a first pressure sensor P1 on the reduced-pressure CO2 stream 112, and a second pressure sensor P2 located at or near the reservoir 140. In this way, the flow coefficient of the first pressure reducer 110 can be changed to maintain the pressure of the further reduced-pressure CO2 stream 132 below the minimum fracture pressure of the reservoir 140. The temperature of the reduced-pressure CO2 stream 112 and / or the temperature of the further reduced-pressure CO2 stream 132 can also be measured, as the bubble point is also a function of temperature. Furthermore, the reduction in the temperature of the carbon dioxide in the injection well 100 can create a positive feedback loop in which the density of the carbon dioxide increases, thereby causing an increase in the static head pressure drop between the reservoir 140 and the surface 120, which in turn increases the Joule-Thompson cooling of the first pressure reducer 110 and / or the second pressure reducer 130, further reducing the temperature of the reduced pressure CO2 stream 112 and / or the temperature of the further reduced pressure CO2 stream 132.

[0024] In some embodiments, controlling the pressure of the further decompressed CO2 stream 132 using the first pressure reducer 110 can allow injection into a deeper reservoir 150. The deeper reservoir 150 can be another portion of the same reservoir as the reservoir 140 or another geological formation. The deeper reservoir 150 is located beneath heavier rock and, therefore, may have a higher minimum fracture pressure than the reservoir 140. In at least some embodiments, without changing the flow coefficient of the first pressure reducer 110, the further decompressed CO2 stream 132 can be above the minimum fracture pressure at the depth of the reservoir 140, but below the minimum fracture pressure at the depth of the deeper reservoir 150. Changing the flow coefficient of the first pressure reducer 110 allows CO2 to be injected into a wider range of depths while maintaining safe operation below the minimum fracture pressure. The control scheme can be designed so that the second pressure reducer 130 can ensure that the further decompressed CO2 flow 132 is above the bubble point pressure throughout the injection depth range, and the flow coefficient of the first pressure reducer 110 is changed to control the pressure of the further decompressed CO2 flow 132 to a level below the minimum fracture pressure of the current target injection depth.

[0025] In some embodiments, multiple injection wells 100 in fluid flow communication with the same CO2 source can also be controlled using a first pressure reducer 110 and a second pressure reducer 130, with each injection well 100 being at a lower depth than the first pressure reducer 110. The second pressure reducer 130 for each injection well 100 can be at the same or different depths. This can allow each injection well 100 to be independently controlled and the CO2 pressure at the depth of each reservoir 140, 150 to be maintained below the corresponding minimum fracture pressure. In the event that the pressure of the wellhead with the highest pressure approaches the pipeline pressure, the second pressure reducer 130 for the wellhead with the highest pressure can be eliminated.

[0026] Due to geology, flow conditions, or CO2 composition, conditions may exist where the dual constraints of bubble point pressure and minimum fracture pressure cannot be met simultaneously. In such cases, one or more chemical additives 152 may be used to lower the bubble point pressure of the raw CO2 stream 154 to produce a CO2 injection stream 102 more suitable for injection into the reservoir 140. In some embodiments, one or more chemical additives 152 may be added to the raw CO2 stream 154. In at least some embodiments, the raw CO2 stream 154 may have a high bubble point pressure due to the presence of more than 0.1 mol%, more than 0.5 mol%, or more than 2 mol% hydrogen. As described above, capturing CO2 that may have a high concentration of hydrogen may be preferable because removing hydrogen from the CO2 at the capture point incurs additional capital and operating costs. For example, when capturing CO2 using an absorption system such as an amine absorber, reducing the hydrogen concentration in the captured CO2 requires high-pressure flashing and / or operating the reboiler at a higher heating load. In some embodiments, the maximum concentration of hydrogen will be at the solubility limit of hydrogen in CO2 at the temperature and pressure of the raw CO2 stream 154. The one or more chemical additives 152 may operate by physical means, wherein the critical point of the CO2 stream is increased, and / or the solubility of carbon dioxide in the gas phase where impurities may form, in which case the desired properties of the one or more chemical additives 152 may include high solubility for CO2 and hydrogen. The one or more chemical additives 152 may operate by chemical or electrochemical means, wherein impurities are consumed by chemical reactions with the one or more chemical additives 152 and / or the bulk CO2.

[0027] In some embodiments, the one or more chemical additives 152 may be used during cold start conditions, or restart after regulation, during which the pressure of the CO 2 injection stream 102 may be lower than the normal steady-state operating pressure.

[0028] Figure 2 It is a depiction Figure 1Schematic diagram of a modification of the process in which the bypass stream is combined with one or more chemical additives. The raw carbon dioxide stream 154 is divided into a raw bypass stream 252 and a second raw carbon dioxide stream 254. The raw bypass stream 252 can be fed into an inline reactor 270, where the one or more chemical additives 152 can be combined with the raw bypass stream 252. The inline reactor 270 can include a catalyst in a fixed bed or monolithic form. The inline reactor 270 can include an electrochemical converter that oxidizes at least a portion of the hydrogen present in the raw bypass stream 252 at the anode and reduces a reactant, such as carbon dioxide or atmospheric oxygen, at the cathode. In the case of carbon dioxide reduction, the electricity required to drive the reaction can be provided by renewable energy. In the case of oxygen reduction, no electricity is required, as the electrochemical converter functions as a hydrogen fuel cell, generating useful electricity. In some embodiments, the hydrogen in the raw bypass stream 252 can react with carbon dioxide and / or atmospheric oxygen without the addition of one or more chemical additives 152. The treated bypass stream 256 can then be recombined with the second raw carbon dioxide stream 254 to form the carbon dioxide injection stream 102. In at least some embodiments, this configuration allows an operator to control the amount of chemical and / or electrochemical reaction by varying the fraction of the raw carbon dioxide stream 154 that is split to form the raw bypass stream 252 .

[0029] In at least some embodiments, the treated bypass stream 256 can be reduced in pressure at a second first pressure reducer and recombined with the reduced pressure carbon dioxide stream 112 downstream of the first pressure reducer 110 (not shown). In this case, the first pressure reducer 110 can be completely closed, and the second first pressure reducer is used to control the pressure of the reduced pressure CO2 stream 112 and the further reduced pressure CO2 stream 132.

[0030] In some embodiments, the inline reactor 270 may be used under cold start conditions, or restarted after a turnaround, during which the pressure of the CO 2 injection stream 102 is lower than the normal steady-state operating pressure.

[0031] In some embodiments, the one or more chemical additives 152 and / or the inline reactor 270 may be used without the second pressure reducer 130 .

[0032] Figure 3Figure 2 is a two-phase envelope diagram for two carbon dioxide streams with different compositions. The two-phase envelope is plotted on a pressure-temperature diagram: the solid line represents a mixture of 98 mol% CO2 and 2 mol% H2, while the dashed line represents a mixture of 95 parts of the 98 mol% CO2 and 2 mol% H2 mixture with 5 parts methanol. The bubble point curve (i.e., the point at which vapor bubbles first form in the liquid phase) is the top portion of the curve, while the dew point curve (i.e., the point at which liquid droplets first form in the gas phase) is the bottom portion of the curve. The liquid and gas phases coexist between the top and bottom portions of the curve. In at least some embodiments, both the pressure and temperature of the carbon dioxide stream increase with depth. Therefore, maintaining the carbon dioxide stream above the bubble point curve at the depth of the first pressure reducer 110 maintains a single-phase flow down the injection well 100. It can be seen that the addition of methanol lowers the bubble point curve at ambient temperatures below approximately 30°C, which in turn allows the further depressurized carbon dioxide stream 132 to be injected into the reservoir 140 at a lower pressure.

[0033] Those skilled in the art will understand that Figure 3 The amount of reduction in the bubble point curve in the stream is relatively small. Physical solvents are more effective in reducing the bubble point curve of carbon dioxide streams where the content of light components such as hydrogen is negligible. Physical solvents such as methanol have good solubility with CO2, but tend to have poor solubility with H2, which reduces their overall effectiveness. In at least some embodiments, it may be more effective if one or more chemical additives operate chemically. In the case of H2 exceeding 0.5%, the one or more chemical additives may include a copper-based catalyst that reacts hydrogen with carbon dioxide to form methanol, a compound that is more soluble in carbon dioxide. Industrially, most copper-based catalysts have low conversion rates for the methanol formation reaction, such as 20%-40%. However, in the present disclosure, the low conversion rate of hydrogen to methanol may be sufficient to reduce the bubble point pressure to meet the dual constraints of bubble point pressure and minimum burst pressure. In at least some embodiments, one or more chemical additives can catalyze the reaction of hydrogen with carbon dioxide to form formate or formic acid. One or more chemical additives may be operated by both physical and chemical / electrochemical methods, either a single chemical additive satisfies both methods or two separate chemical additives, one operated by physical methods and the other by chemical / electrochemical methods. The chemical / electrochemical methods may include hydrogen consumption reactions such as

[0034] H2+CO2=>HCOOH

[0035] or

[0036] 3H2+CO2=>CH3OH+H2O

[0037] The reaction occurs in a packed catalyst bed or at the cathode of an electrochemical cell. The electrochemical process can involve oxidizing hydrogen gas at the anode to form 2H+ ions, which then combine with reactants such as oxygen or carbon dioxide at the cathode. In the case of electrochemical processes combining with carbon dioxide, the relative amounts of formic acid and methanol formed can be a function of the overpotential voltage.

[0038] In at least some embodiments, the chemical reaction that consumes the hydrogen can be an exothermic reaction. The heat of reaction generated by the consumption of the hydrogen can have the additional beneficial effect of increasing the temperature of the CO2 injection stream 102 to reduce the risk of freezing at low ambient temperatures and / or to reduce thermal expansion differences between the well casing, concrete, and the formation.

[0039] Aspect 1: A method comprising: delivering a carbon dioxide injection stream to a first wellhead; reducing the pressure of the carbon dioxide injection stream with a first pressure reducer having a depth and producing a reduced-pressure carbon dioxide stream; reducing the pressure of the reduced-pressure carbon dioxide stream with a second pressure reducer, wherein the second pressure reducer is located at a lower depth than the first pressure reducer and produces a further reduced-pressure carbon dioxide stream; and injecting the further reduced-pressure carbon dioxide stream into a reservoir having a depth; and wherein the pressure of the carbon dioxide injection stream at the depth of the first pressure reducer is greater than the bubble point pressure of the carbon dioxide stream at the depth of the first pressure reducer; and wherein the pressure of the further reduced-pressure carbon dioxide stream at the depth of the reservoir is less than the minimum fracture pressure of the reservoir at the depth of the reservoir.

[0040] Aspect 2: The method according to aspect 1, wherein the carbon dioxide injection stream contains at least 0.1 mol% hydrogen.

[0041] Aspect 3: The method according to aspect 1 or aspect 2, wherein a confined interval is located above the depth of the reservoir, and the second pressure reducer is located at a lower depth than the confined interval.

[0042] Aspect 4: The method according to any one of aspects 1 to 3 further includes combining at least one chemical additive with a raw carbon dioxide stream having a bubble point pressure to produce the carbon dioxide injection stream; wherein the bubble point pressure of the carbon dioxide injection stream is lower than the bubble point pressure of the raw carbon dioxide stream.

[0043] Aspect 5: The method according to aspect 4, wherein the raw carbon dioxide stream comprises hydrogen; and wherein the at least one chemical additive causes a chemical reaction that consumes at least a portion of the hydrogen in the raw carbon dioxide stream.

[0044] Aspect 6: The method according to aspect 5, wherein the chemical reaction that consumes at least a portion of the hydrogen in the raw carbon dioxide stream is an exothermic reaction.

[0045] Aspect 7: The method according to any one of Aspects 1 to 6, further comprising reacting carbon dioxide with hydrogen in a raw carbon dioxide stream having a bubble point pressure in the presence of a catalyst to produce a treated carbon dioxide stream; wherein the bubble point pressure of the treated carbon dioxide stream is lower than the bubble point pressure of the raw carbon dioxide stream; and wherein the carbon dioxide injection stream comprises the treated carbon dioxide stream.

[0046] Aspect 8: The method according to any one of Aspects 1 to 7 further includes measuring the pressure of the further decompressed carbon dioxide flow at the depth of the reservoir; and controlling the pressure of the further decompressed carbon dioxide flow at the depth of the reservoir by changing the flow coefficient of the first pressure reducer and / or the flow coefficient of the second pressure reducer.

[0047] Aspect 9: According to the method according to any one of aspects 1 to 8, the further decompressed carbon dioxide flow is injected into a deeper reservoir having a depth; wherein the pressure of the further decompressed carbon dioxide flow at the depth of the deeper reservoir is less than the minimum fracture pressure of the deeper reservoir at the depth of the deeper reservoir.

[0048] Aspect 10: The method according to any one of aspects 1 to 9, further comprising controlling the temperature of the further reduced-pressure carbon dioxide stream by changing the flow coefficient of the first pressure reducer and / or the second pressure reducer.

[0049] Aspect 11: The method according to any one of Aspects 1 to 10 further includes delivering a portion of the carbon dioxide injection stream to a second wellhead; reducing the pressure of the portion of the carbon dioxide injection stream with a third pressure reducer having a depth and producing a second reduced-pressure carbon dioxide stream; reducing the pressure of the second reduced-pressure carbon dioxide stream with a fourth pressure reducer, wherein the fourth pressure reducer is located at a lower depth than the third pressure reducer and produces a second further reduced-pressure carbon dioxide stream; and injecting the second further reduced-pressure carbon dioxide stream into a second reservoir having a depth; wherein the pressure of the portion of the carbon dioxide injection stream at the depth of the third pressure reducer is greater than the bubble point pressure of the portion of the carbon dioxide stream at the depth of the third pressure reducer; and wherein the pressure of the second further reduced-pressure carbon dioxide stream at the depth of the second reservoir is less than the minimum fracture pressure of the second reservoir at the depth of the second reservoir.

[0050] Aspect 12: A method comprising: delivering a carbon dioxide injection stream to a first wellhead; reducing the pressure of the carbon dioxide injection stream with a first pressure reducer having a depth and producing a reduced-pressure carbon dioxide stream; reducing the pressure of the reduced-pressure carbon dioxide stream with at least a second pressure reducer, wherein the at least second pressure reducer is located at a lower depth than the first pressure reducer and produces a further reduced-pressure carbon dioxide stream; and injecting the further reduced-pressure carbon dioxide stream into at least one reservoir having a depth; wherein the pressure of the carbon dioxide injection stream at the depth of the first pressure reducer is greater than the bubble point pressure of the carbon dioxide stream at the depth of the first pressure reducer; wherein the pressure of the further reduced-pressure carbon dioxide stream at the depth of the at least one reservoir is less than the minimum fracture pressure of the at least one reservoir at the depth of the at least one reservoir.

[0051] Aspect 13: A system comprising: a first pressure reducer, the first pressure reducer being in fluid flow communication with a carbon dioxide injection stream; a second pressure reducer, the second pressure reducer being in fluid flow communication with the first pressure reducer, wherein the second pressure reducer is located at a lower depth than the first pressure reducer; a reservoir, the reservoir being in fluid flow communication with the second pressure reducer; a controller, the controller being configured to receive an electrical signal from at least one of a first pressure sensor downstream of the first pressure reducer, a second pressure sensor downstream of the second pressure reducer, and a flow sensor on the carbon dioxide stream; and outputting an electrical signal to control a flow coefficient of the first pressure reducer.

[0052] Aspect 14: The system according to aspect 13, further comprising an injector in fluid flow communication with the first pressure reducer, the injector configured to combine at least one chemical additive with the raw carbon dioxide stream.

[0053] Aspect 15: The system according to aspect 13 or aspect 14, further comprising a reactor in fluid flow communication with the first pressure reducer, the reactor being configured to receive at least a portion of the raw carbon dioxide stream and produce a treated carbon dioxide stream.

[0054] Aspect 16: The system according to any one of Aspects 13 to 14, further comprising a reactor in fluid flow communication with the first pressure reducer, the reactor being configured to receive at least a portion of the raw carbon dioxide stream and produce a treated carbon dioxide stream; wherein the reactor comprises an electrochemical converter comprising an anode configured to oxidize hydrogen and a cathode configured to reduce at least one of carbon dioxide and oxygen.

[0055] Aspect 17: The system of any one of aspects 13 to 16, further comprising a deeper reservoir at a fourth level in fluid flow communication with the second pressure reducer.

[0056] Aspect 18: The system of aspect 13, further comprising at least a third pressure reducer in fluid flow communication with the first pressure reducer, wherein the at least third pressure reducer is located at a lower depth than the first pressure reducer.

[0057] Aspect 19: The system of aspect 13, wherein the controller is further configured to receive an electrical signal from at least a third pressure sensor downstream of at least a third pressure reducer.

[0058] Aspect 20: The system of aspect 13, further comprising at least a second reservoir in fluid flow communication with the second pressure reducer or at least a third pressure reducer.

[0059] In order to facilitate a better understanding of the present disclosure, the following examples of some aspects of some of the methods and systems are given. The following examples should in no way be interpreted as limiting or defining the entire scope of the present disclosure.

[0060] Example

[0061] Three CO2 injection wells were modeled using proprietary thermodynamic data for a CO2 stream containing 2% H2. Figure 4 The following plots the pressure and temperature distribution of an injection well as a function of depth for three conditions. The first case models a single well near the surface with a first pressure reducer using a wellhead pressure of 1265 psig and 90°F. Figure 4 Figure 2 plots the pressure and temperature distribution of the injection well as a function of depth for three conditions. The corresponding bubble point is 1088 psig, safely below the wellhead pressure and therefore single-phase. The pipeline pressure is 1300 psig, so any Joule-Thompson cooling through the first reducer is negligible. The second scenario considers adding a second well in the same pipeline, requiring higher pressure, increasing the pipeline pressure to 2000 psig. The first well experiences a much higher pressure drop across the first reducer, with the wellhead temperature dropping from 90°F to 69°F and the wellhead pressure dropping from 1265 psig to 1000 psig. The pressure of the first well is now below the bubble point, resulting in two-phase flow and potential hydrogen embrittlement of the hydrogen-rich gas phase. In the third scenario, a second reducer is added to the first well at a depth of 2000 feet. This shifts most of the pressure drop from 2000 psig to 1265 psig from the first to the second reducer, maintaining the wellhead above the bubble point.

[0062] It should be understood that although individual examples may be discussed herein, this disclosure encompasses all combinations of the disclosed examples, including but not limited to different combinations of components, combinations of method steps, and characteristics of the systems.

[0063] It will be understood that compositions and methods described as "comprising," "containing," or "including" various components or steps may also "consist essentially of" or "consist of" the various components and steps. Furthermore, the indefinite article "a" or "an" used in the claims is defined herein as referring to the element or elements that it introduces.

[0064] All numerical values ​​herein described in the detailed description and claims are modified as "about" or "approximately" relative to the indicated value to account for experimental error and variations that would be expected by a person of ordinary skill in the art.

[0065] For the sake of brevity, only certain ranges are explicitly disclosed herein. However, the range from any lower limit can be combined with any upper limit to list a range that is not explicitly listed. In addition, the range from any upper limit can be combined with any other lower limit to list a range that is not explicitly listed. Similarly, the range from any upper limit can be combined with any other upper limit to list a range that is not explicitly listed. In addition, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range that fall within the range will be specifically disclosed. Specifically, each value range disclosed herein (in the form of "from approximately a to about b", or equivalently "from approximately α to b", or equivalently "approximately ab") should be understood to set forth each number and range included in the wider value range, even if not explicitly listed. Therefore, each point or single value can be used as its own lower limit or upper limit, combined with any other point or single value or any other lower limit or upper limit to list a range that is not explicitly listed.

Claims

1. A method comprising: delivering a carbon dioxide injection stream to a first wellhead; reducing the pressure of the carbon dioxide injection stream using a first pressure reducer having a first depth, and generating a reduced-pressure carbon dioxide stream; reducing the pressure of the decompressed carbon dioxide stream with a second decompressor, wherein the second decompressor is located at a lower depth than the first decompressor and produces a further decompressed carbon dioxide stream; injecting the further depressurized carbon dioxide stream into a reservoir having a reservoir depth; and combining at least one chemical additive with a feed carbon dioxide stream having a bubble point pressure to produce the carbon dioxide injection stream; wherein the pressure of the carbon dioxide injection stream at the first depth is greater than the bubble point pressure of the carbon dioxide injection stream at the first depth; and wherein the pressure of the further decompressed carbon dioxide stream at the reservoir depth is less than the minimum fracture pressure of the reservoir at the reservoir depth; wherein the bubble point pressure of the carbon dioxide injection stream is lower than the bubble point pressure of the feed carbon dioxide stream; and wherein the chemical additive is selected from the group consisting of: methane; Cyclohexane; dimethyl ether of polyethylene glycol; catalyst for the reaction of hydrogen with carbon dioxide to form methanol, formic acid or formic acid.

2. The method of claim 1, wherein the carbon dioxide injection stream comprises at least 0.1 mol% hydrogen.

3. The method of claim 1, wherein a confined interval is located above the depth of the reservoir, and the second pressure reducer is located at a lower depth than the confined interval.

4. The method of claim 1 , wherein the feed carbon dioxide stream comprises hydrogen; and wherein the at least one chemical additive causes a chemical reaction that consumes the at least a portion of the hydrogen in the raw carbon dioxide stream.

5. The method of claim 4, wherein the chemical reaction that consumes at least a portion of the hydrogen in the feed carbon dioxide stream is an exothermic reaction.

6. The method of claim 1 , further comprising measuring the pressure of the further depressurized carbon dioxide stream at the reservoir depth; and The pressure of the further decompressed carbon dioxide stream at the reservoir depth is controlled by changing the flow coefficient of the first pressure reducer and / or the flow coefficient of the second pressure reducer.

7. The method according to claim 1, further comprising: injecting the further depressurized carbon dioxide stream into a deeper reservoir having a deeper reservoir depth; The pressure of the further decompressed carbon dioxide stream at the depth of the deeper reservoir is less than the minimum fracture pressure of the deeper reservoir at the depth of the deeper reservoir.

8. The method of claim 1, further comprising controlling the temperature of the further reduced-pressure carbon dioxide stream by changing a flow coefficient of the first pressure reducer and / or the second pressure reducer.

9. The method according to claim 1, further comprising: delivering a portion of the carbon dioxide injection stream to a second wellhead; reducing the pressure of the portion of the carbon dioxide injection stream with a third pressure reducer having a third depth and producing a second reduced-pressure carbon dioxide stream; reducing the pressure of the second reduced-pressure carbon dioxide stream with a fourth pressure reducer, wherein the fourth pressure reducer is located at a lower depth than the third pressure reducer and produces a second further reduced-pressure carbon dioxide stream; as well as injecting the second further depressurized carbon dioxide stream into a second reservoir having a second reservoir depth; wherein the pressure of the portion of the carbon dioxide injection stream at the third depth is greater than the bubble point pressure of the portion of the carbon dioxide stream at the third depth; The pressure of the second further decompressed carbon dioxide stream at the second reservoir depth is less than the minimum fracture pressure of the second reservoir at the second reservoir depth.

10. A system comprising: a first pressure reducer in fluid flow communication with the carbon dioxide injection stream; a second pressure reducer in fluid flow communication with the first pressure reducer, wherein the second pressure reducer is located at a lower depth than the first pressure reducer; a reservoir in fluid flow communication with the second pressure reducer; a controller configured to receive an electrical signal from at least one of a first pressure sensor downstream of the first pressure reducer, a second pressure sensor downstream of the second pressure reducer, and a flow sensor on the carbon dioxide injection stream; and outputting an electrical signal to control a flow coefficient of the first pressure reducer; and an injector or reactor in fluid flow communication with the first pressure reducer and configured to combine at least one chemical additive with the feed carbon dioxide stream having a bubble point pressure to produce a carbon dioxide injection stream; wherein the pressure of the carbon dioxide injection stream at the first pressure reducer is greater than the bubble point pressure of the carbon dioxide injection stream at the first pressure reducer; wherein the pressure of the carbon dioxide flow decompressed by the second pressure reducer at the depth of the reservoir is less than the minimum fracture pressure of the reservoir at the depth of the reservoir; wherein the bubble point pressure of the carbon dioxide injection stream is lower than the bubble point pressure of the feed carbon dioxide stream; and The chemical additive is selected from the group consisting of: methane; cyclohexane; dimethyl ether of polyethylene glycol; a catalyst for reacting hydrogen with carbon dioxide to form methanol, formic acid or formic acid.

11. The system of claim 10, further comprising a deeper reservoir in fluid flow communication with the second pressure reducer.

12. The system of claim 10, further comprising at least a third pressure reducer in fluid flow communication with the first pressure reducer, wherein the at least third pressure reducer is located at a lower depth than the first pressure reducer.

13. The system of claim 12, wherein the controller is further configured to receive an electrical signal from at least a third pressure sensor downstream of at least a third pressure reducer.

14. The system of claim 12, further comprising at least a second reservoir in fluid flow communication with the second pressure reducer or at least a third pressure reducer.

15. A method comprising: reacting carbon dioxide with hydrogen in the presence of a catalyst in a feed carbon dioxide stream having a bubble point pressure to produce a treated carbon dioxide stream; delivering a carbon dioxide injection stream to a first wellhead; reducing the pressure of the carbon dioxide injection stream using a first pressure reducer having a first depth, and generating a reduced-pressure carbon dioxide stream; reducing the pressure of the reduced-pressure carbon dioxide stream with a second pressure reducer, wherein the second pressure reducer is located at a lower depth than the first pressure reducer and produces a further reduced-pressure carbon dioxide stream; and injecting the further depressurized carbon dioxide stream into a reservoir having a reservoir depth; wherein the pressure of the carbon dioxide injection stream at the first depth is greater than the bubble point pressure of the carbon dioxide injection stream at the first depth; wherein the pressure of the further decompressed carbon dioxide stream at the reservoir depth is less than the minimum fracture pressure of the reservoir at the reservoir depth; wherein the bubble point pressure of the carbon dioxide injection stream is lower than the bubble point pressure of the feed carbon dioxide stream; and wherein the carbon dioxide injection stream comprises the treated carbon dioxide stream.

Images