WO2023225467A1 - Carbon dioxide sequestration in horizontal subterranean wells - Google Patents

Abstract

A method of injecting carbon dioxide for sequestration uses a horizontal wellbore extending through a suitable target zone in a subterranean formation.

Description

TITLE: CARBON DIOXIDE SEQUESTRATION IN

HORIZONTAL SUBTERRANEAN WELLS

Inventors:

Ibrahim Mohamed, Houston, Texas

Omar Abou-Sayed, Houston, Texas

Yashesh Panchai, Houston, Texas

Amin Amirlatifi, Starkville, Mississippi

Omar Sameh, Cairo, Egypt

Mahmoud Mostafa, Cairo, Egypt

CROSS-REFERENCE TO RELATED APPLICATIONS

This is an International Application for Patent filed under the auspices of the Patent Cooperation Treaty claiming priority to U.S. Provisional Application Nos. 63/342,143, filed May 15, 2022, and 63/369,238, filed July 24, 2022, both incorporated herein by reference for all purposes.

FIELD

[0001] The disclosed methods and apparatus generally relate to disposal of carbon dioxide in a subterranean formation. More specifically, the disclosure relates to methods for injecting carbon dioxide waste into a relatively thin formation utilizing horizontal wellbores.

BRIEF DESCRIPTION OF THE DRAWING

[0002] For a more complete understanding of the features and advantages of the present disclosure, reference is now made to the detailed description of the disclosure along with the accompanying figures in which corresponding numerals in the different figures refer to corresponding parts and in which: [0003] FIG 1 is a schematic of an exemplary injection operation, in cross-section, according to an aspect of the invention.

[0004] FIGS. 2A-B are comparative schematics showing exemplary CO2 plumes in a vertical injection well and a horizontal injection well.

[0005] FIG. 3 is a graph indicating flowrate through the wellbore in tone per day in relation to the length, in feet, of the horizontal section of the wellbore.

[0006] FIG. 4 is a chart showing the number of wells needed to inject 5000 tons of CO2 per day against a vertical well and several horizontal wells of varying section length.

[0007] FIGS. 5A-B are charts showing a comparison of injection at the same flow rate and injection at the well capacity for both a vertical and a horizontal well, charting pressure against injection days.

DETAILED DESCRIPTION

[0008] The rising environmental and health concerns caused by an increase in greenhouse gas (GHG) concentration in the atmosphere led the United Nations Framework Convention on Climate Change (UNFCCC) to form a stated objective “to achieve stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.” This objective was further emphasized by an international treaty to limit global warming. To achieve it, techniques must be developed to curb the GHG level in the atmosphere.

[0009] Carbon Capture and Storage (CCS) has gained attention along with other techniques to curb the GHG level in the atmosphere. With CO2 accounting for 82% of the greenhouse gases, managing CO2 is of particular concern. Typical CCS technology involves capturing CO2 from anthropogenic sources, compressing it for transportation to the injection site, and injecting it into a pre-selected deep geological formation where it stays in the supercritical phase for permanent storage, also known as carbon sequestration. Sequestration is the technique in which CO2 is stored in underground structures, like saline aquifers, depleted oil and gas reservoirs, and unmineable coal beds. The United States has many potential formations with significant capacity to sequester CO2.

[0010] The Carbon Storage Assurance Facility Enterprise (CarbonSAFE) focuses on developing geological storage sites that can accommodate more than 50 million metric tons of CO2. Few formations can accept this volume of CO2 through a classic vertical injection well. To perform this scale of storage, multiple injection wells would be needed to handle the targeted CO2 volume, with well spacing of several miles to avoid any pressure interference between the inj ectors. Further, acceptable subterranean sequestration sites may not be located close to the CO2 emissions which are targeted for sequestration.

[0011] For example, Nebraska is among the largest ethanol -producing states, with 25 ethanol plants producing over 17 million metric tons of ethanol per year. These plants produce a significant volume of CO2, as a typical ethanol plant produces around 150,000 metric tons of CO2 annually. Several techniques have been proposed to capture and sequestrate the emitted CO2, including mineral carbonation and carbon geological storage. Carbon geological storage is the most feasible option, especially sequestration in deep saline aquifers given the larger volume that can be stored underground and lower cost of disposal. However, most of the ethanol plants are in eastern Nebraska, while geological evaluation suggests that thick aquifers, capable of handling large volumes of CO2 are in the southwest of the state. Due to the high cost of building pipelines to transport the CO2 to relatively thick aquifers, thin aquifers have been identified near the plants to receive the CO2. However, conducting CO2 injection operations through multiple scattered wells increases costs, including pore space rights, well drilling cost, land acquisition, CO2 transportation between sites, multiple injection systems and high-pressure pumps, labor, and monitoring.

[0012] Disclosed herein are methods to solve these issues utilizing horizontal wellbores to inject the CO2 into a target zone, even where the target zone is a relatively thin zone.

[0013] Drilling or utilizing horizontal wells can maximize the volume of CO2 that can be injected in a single well. Further, a horizontal injection operation can be performed at a lower injection pressure than a vertical well. The long horizontal section of the horizontal wellbore exposes a larger formation volume and increases the surface area available for CO2 to flow through.

[0014] An exemplary thin target formation with appropriate properties is the St. Peter formation in eastern Nebraska. The feasibility of utilizing horizontal wellbores for injection in relatively thin zones has been confirmed using injection modeling. A study showed that a single horizontal well with a lateral of 2,000 to 3,000 ft can replace at least three classic vertical injection wells.

[0015] For the thin formations, exploring the larger lateral area by utilizing a horizontal well provides a larger surface area for CO2 flow, which significantly reduces the pressure requirement needed to inject a large volume of CO2 through a single wellbore. The injection volume will be limited due to the cap in the maximum injection pressure.

|0016J The horizontal well technique disclosed herein implemented for CO2 injection will expose the radially farther portions of the formation. The likelihood of a pressure rise due to CO2 inj ection through a horizontal well is less than that of a vertical well, and the attainable CO2 injection rate increases with the horizontal well length for a fixed CO2 injection pressure.

[0017] The benefits of utilizing a horizontal well technique for CO2 injection make it an efficient way to manage the CO2 produced by the ethanol plants in east Nebraska. According to the GHG data provided by the Environmental Protection Agency’s mapping tool, in 2020 ethanol plants in Nebraska and Iowa emitted approximately 6.5 million metric tons of CO2-equivalent, which is more than 36% of the CO2e emitted by all the ethanol producing states. The biggest cluster of ethanol plants is in eastern Nebraska and western Iowa. Western Nebraska has thick saline aquifer formation zones considered particularly suitable for storage of CO2.

[0018] However, transporting CO2 for hundreds of miles is extremely cost intensive. Among transportation options, pipeline is efficient, however, pipeline transportation has its own technical and economic challenges that range from techno-economic, pipeline design, flow assurance, and pipeline integrity, to safeguarding and safety. To transport a large volume of CO2 via pipeline, it must be in a supercritical phase, which makes it sensitive to the existence of steep elevations and impurities. This impacts the fluid dynamics and thermodynamic behavior of the CO2 stream, resulting in different flow regimes that alter the pipeline operating conditions. Using the horizontal injection methods disclosed herein, these costs can be greatly reduced. For example, the methods herein make the saline aquifer zones, of St. Peter sandstone, of southeast Nebraska accessible and useful to store the captured CO2.

[0019] The target zone 14 is a fluid-filled formational zone, such as a saline aquifer, non-salt water aquifer, or hydrocarbon fluid filled formation, with good reservoir qualities, such as good porosity and permeability, plus adequate volume for substantial CO2 storage. Unlike conventional methods which utilize vertical wellbores, however, the disclosed method makes available relatively thin target zones.

[0020] For example, the St. Peter sandstone is characteristically composed of well-sorted, rounded sand, consisting of quartz. In eastern Nebraska, St. Peter sandstone averages 30 - 120 ft in thickness and approximately 30 - 60 ft in the forest city basin. St. Peter possesses excellent reservoir quality with average porosity of 14% - 16% and an average permeability of 150 - 400 mD in some midwestem states. In most of northwestern Missouri and close to Kansas and Nebraska, St. Peter sandstone is overlain by zones of dolomite, limestone, and green clay shale. Great reservoir properties and a thick containment formation zone protecting the Underground Source of Drinking Water, a fresh waterbearing zone, make St. Peter sandstone a suitable candidate for CO2 storage. However, the formation zone has a relatively low formation thickness, which, using traditional methods with vertical wells, makes large-scale storage of CO2 problematic. Utilizing the methods disclosed herein, drilling or using a horizontal well instead of several vertical wells, made CO2 sequestration possible and relatively more economical. Greater CO2 storage can be achieved using a horizontal well than multiple vertical wells.

[0021] FIG. 1 is a schematic of an exemplary onshore oil or gas drilling rig and wellbore, in crosssection, according to an aspect of the invention, the system generally designated 10. Rig 12 is positioned over a subterranean formation, below the earth’s surface 16, having multiple layers or strata of zones with varying properties. The target zone 14 is a formation targeted for injection of carbon dioxide (CO2) disposal or sequestration and has corresponding properties allowing the injection, movement, and storage of fluids. The containment zone 21, above the target zone 14, conversely has properties preventing the flow of fluids and is useful for containing carbon dioxide, and other fluids, present in the target zone 14 from migrating upwards into or past the containment zone 21. Additional zones 15, 17 and 19, can have various properties. For example, in many locations a drinking water zone 19 may be present having relatively fresh water, not briny, used for human consumption.

[0022] The rig 12 is exemplary to generally indicate surface equipment necessary for performing pumping at pressure into the target formation. Such equipment can be used for various operations, such as injection, wellbore flushing, disposal or storage, etc. The rig 12, as shown, can include a derrick 34 for supporting a hoisting apparatus for raising and lowering pipe strings, such as work strings, production strings, and casing 20. Similarly, coiled tubing and wireline operations can be run in the well. Pump 30 is capable of pumping a variety of wellbore compositions of various consistencies into the well. One or more pressure measurement devices 38 provide pressure readings, for example, at the pump discharge, wellhead, primary and annular bores, etc.

[0023] Wellbore 18 has been drilled through the various earth strata, including formation zone 14. Upon completion of drilling, casing 20 is typically cemented in place in the wellbore 18 to facilitate the production of oil and gas from the targeted formation 14 while isolating non-targeted formations such as, for example, aquifer formations 15 and 17, and aquiclude or impermeable layers 19 and 21. The targeted formation zone 14 is bounded above and below by containment layers 21 and 23. The targeted zone 14 is a saline aquifer as the saline aquifer has the properties necessary to inject, allow subterranean movement of, and store large volumes of CO2. It is understood that the aquifer can have additional fluid components.

[0024] Casing 20 extends downhole along wellbore 18 through selected section of the wellbore. As shown, the casing 20 extends along the vertical section of the wellbore, although casing can also be positioned along the horizontal section if desired. The casing annulus between the casing 20 and wellbore wall 18 contains cement to secure the casing 20 in place and prevent leakage upwards on the outside of the casing. If casing is used along the target zone, the casing can be pre-perforated or perforated in place using typical perforation techniques. More often, a liner 25 is positioned in the wellbore, extending or hung from the casing. The liner 25, at the target zone, is pre-perforated, slotted, or perforated at its downhole location. The perforations provide fluid communication between the target zone 14 and the wellbore 18 interior to the casing or liner. Alternately, the wellbore at the target zone can be open hole. A tubing annulus is formed between the casing or liner and any work string positioned therein. An exemplary downhole tool assembly 40 is shown in the wellbore 18 and can be one or more downhole tools, connected or disconnected, on a wireline, workstring, or other conveyance, or permanently installed in the wellbore. For example, the tool assembly 40 can include an array of sensors for data acquisition and transmission.

[0025] In some embodiments, the methods are used with respect to a target zone which has been previously hydraulically fractured, creating exemplary cracks 24. The fractures can intersect one another, creating a connected fracture network. In some cases, multiple sections of the target zone are injected, sometimes sequentially, and can be fluidly isolated from one another to allow, in conjunction with isolation or barrier devices, downhole valves, and the like, control of fluid communication with each section of the zone.

[0026] During CO2 injection operations, CO2, stored and treated in surface tanks 22 or the like, is pumped downhole by a pump 30 under pressure. The CO2 at the surface, and not under artificial pressure, is in a gaseous phase. For injection, the CO2 is placed under pressure utilizing pumps, compressors and the like, to supercritical phase. In supercritical phase, the CO2 is pumped downhole, through the vertical section of the wellbore, through the horizontal section of the wellbore and into the target zone. Although it is anticipated that the method will not require injection at above fracture pressure, causing resulting fractures in the target formation, in some embodiments injection can be above fracture pressure.

[0027] The CO2 injected in a saline aquifer at depths greater than 3,000 ft will be in a supercritical phase due to the thermodynamic nature of the subsurface formation. It is less viscous and less dense than the formation brine and thus due to gravity segregation, it navigates upwards following a permeable pathway to settle on top of the brine. For thin injection formation zones, this CO2 behavior will significantly compromise the storage efficiency, where storage efficiency is defined as the ratio between the amount of CO2 stored in an aquifer volume and the total pore space volume of the area of interest. Due to the pressure and temperature conditions of the subsurface formation, injected CO2 will remain in a supercritical phase with lower viscosity and density compared to the formation brine, which enables the upward movement of CO2 due to gravity segregation to be trapped on top of the brine and below the non-permeable containment zone. Thus, CO2 in a vertical well occupies a smaller volume per unit of aquifer pore space, compromising the total storage capacity. However, for a horizontal well, the lateral section will reach the hard-to-access areas of the formation and provide larger pore space per unit volume of the aquifer. Thus for a vertical injection well, CO2 daily injection capacity will be lower than the volume injected through a horizontal well with a long lateral section.

[0028] Saline aquifers are the porous and permeable geological formations containing saline water within pore spaces. Subsurface CO2 injection into saline formations (with TDS > 10,000 ppm) has gained attention due to their availability and ability to sequester and permanently store the CO2. There are several storage mechanisms for CO2 in saline reservoirs. Stratigraphic or structure Trapping: The injected CO2 is trapped within the targeted injection as the impermeable formation lying above the injection formation will prohibit upward migration. This is the main trapping mechanism, however, structural trapping contribution decreases with time, while other trapping mechanism increases. Residual trapping: Once injection is completed, the CO2 migrates upwards due to gravity segregation, during which the wetting phase (brine) enters the pores vacated by the less wetting phase (CO2). During this process, brine displaces CO2, leading to significant saturation of CO2 getting trapped in small clusters of pores and staying immobile. Solubility trapping: Eventually, the CO2 starts to dissolve in the saline water. The depletion of the accumulated C02 starts because of the dissolution and sequestering of CO2 over time. For example, the solubility of CO2 under typical reservoir conditions at a pore water salinity of 3% is about 49 kg m-3. Mineral trapping: Introduction of CO2 into a saline aquifer will alter the natural chemical balance as a result of precipitation or dissolution reactions. In a sandstone formation, CO2 reacts with siliciclastic rocks over time (centuries) and the feldspar group minerals may react with CO2 that has dissolved into the reservoir brine to form carbonates and clays, while in the case of other formations, dissolution of carbonate minerals will occur, but as the formation water becomes saturated with CO2 the injected CO2 remains as a separate phase.

[0029] The geological criteria to consider for a potential saline aquifer for CO2 injection are storage capacity, injectivity, storage confinement, no leakage pathways, storage integrity, and vulnerability. The common formation properties that contribute to both, storage capacity and injectivity are formation permeability, porosity, and thickness. For a reservoir, altering the formation properties at a distance far from the wellbore is not possible. However, an adjustment in the injection methods to the disclosed method can maximize storage capacity while maintaining injectivity.

[0030] As an example, St. Peter sandstone formation in southeastern Nebraska has formation properties that make it a decent candidate for CO2 injection. However, the formation thickness of the targeted injection formation is only about 100 feet, which is low. The zone is, however, laterally extensive. If the lateral extent of the St. Peter sandstone is optimally utilized, it offers good storage capacity with decent injectivity. To utilize the lateral extent of the relatively thin target zone, the disclosed methods use a horizontal wellbore. The drainage radius will be limited due to the cap in the maximum injection pressure and thus, for a vertical injection well, CO2 storage capacity will be lower compared to a horizontal well with a long lateral section.

[0031] Formation conductivity is the result of multiplying the formation permeability and the formation thickness (KH). For the formation with lower conductivity (KH), the well life can be relatively shorter in a vertical well as the formation pressure elevated faster compared to a horizontal well. An explanation of the mechanism that enables horizontal wells to accommodate a larger volume of CO2 is seen at FIGS. 2A-B.

[0032] FIGS. 2A-B are comparative schematics showing exemplary CO2 plumes in a vertical injection well and a horizontal injection well. FIG. 2A shows a plume 50 for a vertical well 52. FIG. 2B shows a plume 60 for a horizontal well 62. The wells are shown schematically having a casing 54, liner 56, and workstring 58 extending into the target zone 14 below a containment zone 21. Outside the plumes is seen areas of the zone containing brine 64. Movement of CO2 is indicated by the arrows. The shape of the CO2 plume around the wellbore depends on the interplay of viscosity, gravity, and capillary forces between the formation fluid and CO2. Generally, the plume will take on an inverted cone shape as it spreads into the aquifer and beneath a sealing cap rock. Further, the FIGS. 2A-B show how a horizontal well offers greater storage capacity compared to a vertical well.

[0033] The disclosed methods of injection of CO2 into saline aquifers for long term sequestration were subjected to analysis for feasibility. An analytical simulation was performed to determine the viability and advantages of the disclosed methods over the use of vertical wellbores.

[0034] Depleted reservoirs in the Fall city basin and Dawson basin were studied along with the St. Peter sandstone formation in southeast Nebraska The storage capacity of the depleted reservoir was low and could not handle the daily CO2 volume requirement. St. Peter sandstone formation on the other hand is a thin formation but is laterally extensive and extends to the neighboring states. Utilizing the lateral extent of the zone increases the formation capacity of St. Peter four-fold. To consider St. Peter sandstone formation for CO2 sequestration, the injection schematic and the wellbore design were revised to expose a larger formation area to the wellbore. Since the wellbore reaches far-field zones of the formations, the well drainage area will expand and maximize the formation capacity. The formation storage capacity and the corresponding number of wells required were studied using analytical and numerical approaches.

[0035] Two scenarios were considered to study the St. Peter’s formation storage capacity using vertical wells and horizontal wells. The number of wells required to inject 5,000 tons of CO2 per day for 25 years is calculated using the diffusivity equation for the radial flow of compressible fluid in porous media. The injection pressure is assumed below the formation fracture pressure to avoid formation fracture. The depth and thickness of the St Peter sandstone is the average value collected from several well files obtained from the Nebraska Oil and Gas Conservation Commission (NOGCC) as shown in Table 2 below.

[0036]

[0037] Due to the lack of accurate petrophysical data, the following assumptions were made: CO2 is injected at a constant mass flow rate; Non-Darcy flow effect was neglected; Formation temperature is assumed at a geothermal gradient; Formation pore pressure is 0.4 psi/ft; Formation fracture pressure is 0.6 psi/ft; Relative permeability of CO2 is 0.1; Formation thickness is equivalent to the average thickness obtained from the well fdes; Average permeability was considered; Vertical permeability is assumed at 10% of horizontal permeability.

[0038] In a first scenario, with injection through a vertical wellbore, the Diffusivity Equation (Equation 1) was used to calculate the maximum injection flow rate for a well using the formation properties discussed above. The results show that with a single well the maximum achievable flow rate without fracking the formation is 828 tons per day. To accommodate the available CO2 volume of 5,000 tons per day, 6 vertical wells are required.

[0039] Equation 2 is for the Total Skin Factor and is used to account for change in the formation properties in the near wellbore region, i.e., (drilling, damage, stimulation, formation dissolution). [0040] In a second scenario, injection was analyzed through a horizontal well. Like the vertical well scenario, the diffusivity equation was used to calculate the maximum achievable flow rate, however, it needed to be modified (Equations 3 and 4) for the horizontal well. FIG. 3 is a graph indicating Flowrate through the wellbore in tons per day in relation to the length, in feet, of the horizontal section of the wellbore. The results show a direct relationship between the flow rate and the lateral length of the wellbore as shown in FIG. 3. For a single horizontal well, it must have a lateral length of about 30,000 feet to accommodate the daily available CO2 volume of 5,000 tons per day. The cost of drilling the lateral section is much more than drilling the vertical section. Understanding the high cost of constructing the lateral section, several cases were run with varying lengths of the horizontal section and increasing the number of injection wells. The most economic option to accommodate the available CO2 volume was to drill two horizontal wells each with a 3,000 foot lateral length. A horizontal well in this scenario is capable of pumping approximately 2500 tons of CO2 per day.

[0041] Equations: 3.23 + 0.869S'] Equation 1

S' = S + D\q\ Equation 2 Equation 3

Equation 4

[0042] Where, m(P) = Pseudo pressure (psi²/cP)

P,_flJ = Injection Pressure (psi)

Pi = Initial Formation Pressure (psi) q = Injection Flow Rate (MSCF/D)

1 = Formation Temperature (R)

K = Formation Permeability (mD) kx = Horizontal Permeability (mD) kz = Vertical Permeability (mD)

PI = Formation Thickness (ft) t = Injection Time (hr)

0 = Formation Porosity (fraction)

/J = Average Gas Viscosity (cP) cP = Total formation compressibility

(psi-1) rw = Wellbore Radius (ft)

S' = Total Skin Factor

S = Damage Skin

D = Non-Darcy flow coefficient

(MSCF/D)- 1

[0043] Thus, for the St. Peter formation, drilling a horizontal well proves to be an acceptable option. It provides capital cost savings associated with drilling operations and reduces the surface footprint by reducing the number of injection wells to two horizontal wells compared to six vertical wells. FIG. 4 is a chart showing the number of wells needed to inject 5000 tons of CO2 per day against a vertical well and several horizontal wells of varying section length. FIG. 4 further shows the number of well requirements in a scenario where only vertical wells are used and another scenario when only horizontal wells are used for injection activity. [0044] Along with the number of wells requirement, near-wellbore pressure response was also studied for both vertical and horizontal wells to confirm that the injection activity does not over pressurize the injection formation to endanger the containment of injected CO2. For both wellbore schematics, the injection pressure stays below the fracture pressure during the entirety of the injection period as shown in FIGS. 5A-B. FIGS. 5A-B are charts showing a comparison of inj ection at the same flow rate and inj ection at the well capacity for both a vertical and a horizontal well, charting pressure against injection days. The lateral section in the horizontal well provides more CO2 storage volume per unit area of the reservoir, thus, for the same injection rate of 828 tons CO2 per day, the rise in the near-wellbore pressure for a horizontal well is lower than the vertical well as shown in FIG. 5A. The results further show that the near-wellbore pressure for a horizontal well operating at its maximum flow rate of 2,490 tons/day for a 3,000 ft lateral, is less than the vertical well at a flow rate of 828 tons/day as shown in FIG. 5B

[0045] A reservoir simulation study was performed to compare the storage capacity obtained using the analytical method, study the movement of CO2, and the trapping mechanism. An open-source toolkit provided by MathWorks, ‘MATLAB Reservoir Simulator Toolkit’ for the CO2 lab module was used to perform the simulation. MSRT offers a set of simulators and workflow tools that are designed to meet the challenges of usage of scarce data, large spans in spatial and temporal scales, and delicate balances between different physical flow mechanisms.

[0046] Two scenarios were considered in the simulation study, an injection through vertical wells and the number of wells requirements and an injection through horizontal wells and the number of wells required with varying horizontal lengths to inject the same amount.

[0047] The reservoir model was constructed for a domain of 10 miles x 10 miles x 100 ft. The aquifer was discretized into 50 x 50 x 5 grid blocks. For the vertical well scenario, the wells were spaced equally with 13,100 ft between each well in a two by three pattern. The distance was confirmed after running several cases with varying distances. For the horizontal well scenario, two wells are separated by 19,600 ft. The lateral length was kept between 500 ft. to 10,000 ft. to run different scenarios.

[0048] The initial condition for the saline aquifer was assumed at a hydrostatic pore pressure and geothermal gradient. A saline aquifer was assumed to be a homogenous formation with open boundaries. The simulator was run for 25 years of CO2 injection, and 1,000 years after injection to monitor the movement of CO2 and the changes in trapping mechanisms. [0049] Aquifer properties

[0050] The well logs and the geological column distribution data were collected from wells from southeast Nebraska. These well data were used to determine the formation properties of the St. Peter sandstone formation which are summarized in Table 3 below.

[0051] These properties might vary with location, as the properties used for simulation are the average values from the data collected from oil and gas wells that are scattered in the area. Also, due to the lack of data availability, the vertical permeability is assumed to be 10% of the horizontal permeability and the relative permeability of the CO2 is assumed equal to the base model.

[0052] The aquifer is sealed by a thick layer of Simpson and Kinderhook shale (Chatanooga shale). Low permeability (0.0021 - 5.45 mD) and low porosity (1 x 10-10 - 0.2), make it a perfect sealing candidate. To confirm the CO2 containment within the injection horizon, the reservoir simulation study was run using the overlaying formation properties to confirm the containment of the injected CO2 and its trapping mechanism.

[0053] The reservoir simulation was run to forecast the injection of 5,000 ton of CO2 per day for 25 years followed by 1,000 years of a shut-in. The simulation result showed a good match for a number of wells for both vertical and horizontal wells, however, for the horizontal well, the length of the lateral section obtained was 2,000 ft vs. 3,000 ft obtained in the analytical approach. The larger pressure exposure across the lateral section of the wellbore is an indication of more surface area of the reservoir in contact with the injection fluid. Thus, based on the distribution of pressure signal across the reservoir it can be estimated that almost 3 times more CO2 can be inj ected through a horizontal well compared to an individual vertical well. The access pressure created due to injection starts dissipating once injection activity is stopped, and the reservoir gets back to its initial conditions by the end of the monitoring period.

[0054] Due to the low density of CO2 relative to the formation brine, CO2 floats on top of the brine and forms a cone-like shape. A layer cake model with an infinite acting reservoir used for simulation might overestimate plume size, however, in a non-ideal case, the plume size would vary depending on the reservoir boundary constraints. The total CO2 plume at the end of the monitoring period for six vertical wells was about 45 square miles compared to about 50 square miles for two horizontal wells each with a 2000 ft lateral length. Thus, drilling horizontal wells utilizes almost equal pore space rights compared to vertical wells with smaller surface footprint.

[0055] The plume for a well with a 10,000 foot lateral is almost 1.5 times the plume for a well with a 2,000 foot lateral. Thus, more pore space rights must be acquired on top of the cost of drilling the longer lateral section with no economic benefits. Thus, the simulation results concluded that any increase in the lateral length of a horizontal well beyond 2,000 feet does not add additional value to the well.

[0056] A simulation case was run to confirm the containment of the injected CO2 and to understand the trapping mechanism for 1,000 years after the end of injection. Since chemical reactions were neglected, mineral trapping of CO2 was not considered. The trapping mechanism for both vertical and horizontal well scenarios is similar. Structural trapping was the main trapping mechanism, representing more than 50% of the total trapping. Due to gravity segregation, CO2 moves upwards and reduces the amount of free CO2, leaving it trapped in the residual phase. The existence of the free phase CO2 at the bottom of the injection formation depends on the vertical permeability and injection rate.

[0057] The results obtained from the analytical and reservoir simulation studies show similar results. The total number of vertical wells and horizontal wells necessary to accommodate 5,000 tons of CO2 per day is equal in both approaches. However, based on the reservoir simulation, the length of the lateral section required to store the total amount of CO2 is 2,000 ft. This difference can be related to the constants used in the analytical model. The formation properties and the fluid properties in an analytical model were assumed to be constant throughout 25 years of injection. However, the reservoir simulation involves a dynamic approach and considers the change in the formation and fluid properties.

[0058] Several simulation cases were run with varying lengths of the horizontal section to see the difference in CO2 storage capacity for a horizontal well. It was observed that the most economic option was to drill two horizontal wells with 2,000 ft lateral length compared to drilling six vertical wells. The plume size in both scenarios was similar, thus the required pore space rights were the same. However, due to the spacing between the vertical wells, the surface requirement is roughly 12 square miles, with an additional pipeline required to connect the well pads. For horizontal wells, the surface requirement is reduced by a third, which is more economic and offers lower risk due to a shorter pipeline The simulation further confirmed that adding more length to the horizontal section does not add more value to the storage capacity. However, it does help maintain the injection pressure at lower levels. Since the injection pressure with a 2,000 ft lateral length was well below the fracture gradient, it is considered an optimum length for the horizontal well for this scenario.

[0059] The injection pressure rise in a horizontal well is lower than in a vertical well mainly because the injection through the lateral section provides a larger dissipation area for the injected CO2. The rise in injection pressure observed using the analytical approach shows a quick rise during the initial days of injection. However, with an injection at a continuous mass flow rate of CO2, the injection pressure rise is stabilized for both vertical and horizontal wells. The simulation result showed a sharp injection pressure rise at the beginning of injection activity with relatively quick stabilization and a slow decline over time for both vertical and horizontal wells. This is because initially, the relative permeability of CO2 is low due to the low concentration of carbon dioxide in the formation. Over time, as the concentration of CO2 increases in the near-wellbore region, the capillary fringe was displaced away from the wellbore due to an increase in the relative permeability of CO2.

[0060] The low thickness of the injection formation does not influence the injection pressure to rise for CO2 to escape from the injection zone. The results confirmed that the injected CO2 will remain trapped within the injection formation as a free plume for more than 1,000 years after the completion of the injection activity. Thus, by implementing a horizontal well for injecting in a reservoir with low thickness, the storage capacity is increased several fold while assuring the containment of the injected CO2 while keeping the injection pressure well below the fracture gradient.

[0061] The objective of this work was to quantify the effect of wellbore schematic and well length on the formation storage capacity and viability of CO2 sequestration in thin saline formations. This is possible by utilizing the maximum area an injection formation has to offer. This is achieved either by drilling several vertical wells if the formation is laterally extensive or by drilling a horizontal well with sufficient lateral length to expose the far-to-reach areas of the reservoirs.

[0062] Horizontal well technology is a unique technique to inject CO2 into thin injection strata to minimize the number of vertical wells needed to manage large volumes of CO2.

[0063] Utilizing the horizontal wellbore schematic for CO2 injection in the St. Peter sandstone formation, the number of wells requirement is reduced to two horizontal wells compared to six vertical wells.

[0064] The CO2 plume size of two horizontal wells with a 2,000 ft lateral section is similar to the plume size generated by six vertical wells. Thus, the pore space requirement for the CO2 migration is similar. However, due to a smaller number of wells, the surface area for the horizontal well is significantly less which will significantly reduce the capital cost.

[0065] An additional 78,600 ft of pipeline construction is required to connect the well pads of six vertical wells, due to a 13,100 ft distance between each well. However, in the case of a horizontal well, this distance is reduced to 19,600 ft. Reduced distance provides capital cost savings.

[0066] Based on the input parameters used in the current study, the optimum horizontal section length ranges between 2,000 and 3,000 ft. Drilling a longer horizontal well lateral adds capital cost with no obvious benefit to injection operations.

[0067] Several thin saline aquifers are present in the United States that are not, under traditional analysis, considered potential CO2 storage options due to their limited thickness. Such formations are avoided due to low storage capacity. However, by utilizing the methods presented herein, the total capacity of the formation can be maximized by accessing the far-to-reach areas of the reservoir.

[0068] While the foregoing written description of the disclosure enables one of ordinary skill to make and use the embodiments discussed, those of ordinary skill will understand and appreciate the existence of variations, combinations, and equivalents of the specific embodiments, methods, and examples herein. The disclosure should therefore not be limited by the above described embodiments, methods, and examples. While this disclosure has been described with reference to illustrative embodiments, this description is not intended to be construed in a limiting sense. Various modifications and combinations of the illustrative embodiments as well as other embodiments of the disclosure will be apparent to persons skilled in the art upon reference to the description. It is, therefore, intended that the appended claims encompass any such modifications or embodiments.

[0069] The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope of the present disclosure. The various elements or steps according to the disclosed elements or steps can be combined advantageously or practiced together in various combinations or sub-combinations of elements or sequences of steps to increase the efficiency and benefits that can be obtained from the disclosure. It will be appreciated that one or more of the above embodiments may be combined with one or more of the other embodiments, unless explicitly stated otherwise. Furthermore, no limitations are intended to the details of construction, composition, design, or steps herein shown, other than as described in the claims.

Claims

Tt is claimed:

1. A method of operating a storage well system having a subterranean wellbore, the wellbore having a vertical section extending from the surface to a horizontal section, the horizontal section extending through a target formation zone, the method comprising: pressurizing carbon dioxide (CO2) from a gaseous phase to a supercritical phase at the surface; pumping the pressurized CO2 through the vertical section of the wellbore, past a plurality of subterranean zones including a containment zone; pumping the pressurized CO2 through the horizontal section of the wellbore in the target formation zone; pumping the pressurized CO2 into the target formation zone; and sequestering the CO2 in the target formation zone below the containment zone.

2. The method of claim 1, wherein the target formation zone comprises a saline aquifer.

3. The method of claim 1, further comprising pumping the pressurized CO2 at above a fracture pressure of the target formation zone.

4. The method of claim 1, wherein the target zone is a relatively thin formation zone of an average of between 30 and 120 feet in thickness.

5. The method of claim 1, wherein the horizontal section of the wellbore is approximately 2000 to 3000 feet long.

6. The method of claim 1, wherein the horizontal section of the wellbore is open hole.

7. The method of claim 1, wherein the horizontal section of the wellbore is lined with a slotted or perforated liner or casing.

8. The method of claim 1, further comprising pumping into the target formation zone approximately 2500 tons or more of CO2 per day.