METHODS AND SYSTEMS FOR CO2 SEQUESTRATION

Abstract

A method of sequestering carbon dioxide is provided, the method comprising injecting carbon dioxide into a saline formation below an oil reservoir. The carbon dioxide may be sequestered at a pressure above about 10 MPa. The carbon dioxide may be sequestered at a pressure below about 30 MPa. The carbon dioxide may be sequestered at a temperature above about 25° C. The carbon dioxide may be sequestered at a temperature below about 60° C. The saline formation and the oil reservoir may contact each other, thereby forming an oil-water contact (OWC) layer. The carbon dioxide to be sequestered may be injected greater than about 10 m below the OWC layer. The carbon dioxide may be a gas, a liquid, a supercritical fluid, or a mixture thereof, when the carbon dioxide is injected into the saline formation.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This patent application claims priority to U.S. Provisional Patent Application No. 61/347,297 filed May 21, 2010, the content of which is incorporated herein by reference in its entirety.

INTRODUCTION

Much scientific evidence suggests that the global temperature has increased over the last 100 years. A significant proportion of these changes may be attributed to the emission of anthropogenic CO₂ into the atmosphere. Based on this premise, it has been suggested that it is necessary to reduce current CO₂ emissions (about 7.1 billion tonnes per year of carbon) to curb the increase of global temperature. To achieve this goal, many countries have ratified the Kyoto Protocol, a multinational agreement to reduce greenhouse gas emissions, drafted by the United Nations Framework Convention on Climate Change in 1997. After considering the economical and technological aspects of multiple technologies, as well as improved efficiency, it is anticipated that geologic CO₂ sequestration may be the most beneficial and effective short-term approach to curbing global warming.

SUMMARY

A method of sequestering carbon dioxide is provided, the method comprising injecting carbon dioxide into a saline formation below an oil reservoir. The carbon dioxide may be sequestered at a pressure above about 10 MPa, such as at a pressure above about 15 MPa. The carbon dioxide also may be sequestered at a pressure below about 30 MPa, such as at a pressure below about 25 MPa. For example, the carbon dioxide may be sequestered at a pressure between about 10 MPa and about 30 MPa, such as at a pressure between about 15 and about 30 MPa, between about 10 MPa and about 25 MPa, or between about 15 MPa and about 25 MPa. The carbon dioxide may be sequestered at a temperature above about 25° C., such as at a temperature above about 35° C. The carbon dioxide also may be sequestered at a temperature below about 60° C., such as at a temperature below about 50° C. For example, the carbon dioxide may be sequestered at a temperature between about 25 and about 60° C., such as at a temperature between about 35 and about 60° C., between about 25 and about 50° C. or between about 35 and about 50° C. The saline formation and the oil reservoir may contact each other, thereby forming an oil-water contact (OWC) layer. The carbon dioxide to be sequestered may be injected greater than about 10 m below the OWC layer, such as greater than about 100 m below, or even greater than about 500 m below OWC layer. The carbon dioxide may be a gas, a liquid, a supercritical fluid, or a mixture thereof, when the carbon dioxide is injected into the saline formation.

A system for sequestering carbon dioxide also is provided, the system comprising a well coupled to a saline formation that is beneath an oil reservoir, and a pump operatively connected to the well and configured to inject carbon dioxide through the well and into the saline formation. The pump may be operatively connected to a pipeline containing CO₂. Alternatively or additionally, the pump may be operatively connected to one or more tanks of CO₂, such as a tank of compressed CO₂. For example, the pump may be removably attachable to one or more tanks of CO₂. In some embodiments, the system for sequestering carbon dioxide may be a system for sequestering carbon dioxide under a seafloor, comprising a well coupled to a saline formation beneath an oil reservoir beneath a seafloor, and a pump operatively connected to the well and configured to inject carbon dioxide into the saline formation.

The system(s) for sequestering carbon dioxide may include a monitoring system configured to monitor the amount of CO₂ in a portion of the saline formation, a portion of the oil reservoir, or both. The monitoring system may include a monitoring station, and one or more sensors coupled to the monitoring station, where each sensor may be in contact with the oil reservoir and/or the saline formation, and may be configured to take measurements that correlate to the amount of CO₂ in the environment surrounding the sensor. For example, each sensor may be configured to measure at least one of the temperature, salinity, pH, pressure, and/or CO₂ concentration of fluids in contact with the sensor. The monitoring system also may include one or more monitoring wells, where each monitoring well is coupled to either the saline formation and/or the oil reservoir, and each sensor is coupled to the monitoring system by a coupling element that extends through one of the monitoring wells. For example, a particular sensor may be physically coupled to the monitoring station by a cable coupling element, such as may be wrapped around a winch so that the sensor can be raised and lowered within the monitoring well to desired depths, and can be removed from the well for maintenance. Alternatively or additionally, a particular sensor may be electrically coupled to the monitoring station by an electrical wire coupling element that permits one- and two-way wired communication between the sensor and the monitoring station, although a sensor also may be in wireless communication with the monitoring station. Some monitoring systems may include at least a first sensor in contact with the oil reservoir and a second sensor in contact with the saline formation. The first and second sensors each may be coupled to the monitoring station by coupling elements that extend through the same or different mentoring wells.

The monitoring system may be configured to produce an alert when the amount of CO₂ in the portion of the saline formation or the portion of the oil reservoir exceeds a predetermined amount. For example, the monitoring system may be configured to produce an alert when the amount of CO₂ in fluids surrounding a particular sensor exceeds a value of about 0.001% CO₂, about 0.0025% CO₂, about 0.005% CO₂, about 0.0075% CO₂, and/or about 0.01% CO₂, among other suitable values. Likewise, the monitoring system may be configured to produce an alert when the amount of CO₂ in fluids surrounding a particular sensor exceeds a value of about 300 ppm CO₂, about 400 ppm CO₂, about 500 ppm CO₂, about 600 ppm CO₂, and/or about 700 ppm CO₂, among other suitable values. Alternatively or additionally, the monitoring station may be configured to produce an alert when the amount of CO₂ in the portion of the saline formation or the portion of the oil reservoir changes from some baseline amount (such as a preselected concentration, an amount equal to an average observed amount based on measurements of CO₂ over a selected period of time, or any other desired baseline amount) by some predetermined amount, or by some integer or non-integer factor of the baseline amount. For example, the monitoring station may be configured to produce an alert when the baseline amount changes by any desired factor, including but not limited to a factor of 2, 2.5, 5, 10, 15.5, 25.5, 50.25, 100.73, or any other desired factor.

Other aspects of the invention will become apparent by consideration of the detailed description and accompanying drawings.

BRIEF DESCRIPTIONS OF THE DRAWINGS

FIG. 1 is a series of conceptual diagrams showing a method of sequestering CO₂ beneath an oil reserve that includes injecting the CO₂ below an OWC layer, where: (a) shows Stage I, (b) shows Stage II, and (c) shows Stage III of CO₂ sequestration.

FIG. 2 is a graph comparing CO₂ solubility in crude oil to CO₂ solubility in pure water.

FIG. 3 is a graph comparing the densities of CO₂, brine, and crude oil at various pressures. Densities are calculated at 54.5° C. and 159,000 ppm, which represents reservoir conditions in the SACROC Unit of western Texas.

FIG. 4 is a pair of graphs comparing: (a) the densities of mixtures of CO₂ and crude oil under various conditions, and (b) the densities of mixtures of CO₂ and brine under various conditions.

FIG. 5 is a graph comparing the viscosities of CO₂, water, brine, and various crude oils at various temperatures. Viscosities are calculated at a representative pressure of 25 MPa.

FIG. 6 is a pair of graphs comparing the viscosities for: (a) mixtures of CO₂ and crude oil and (b) mixtures of CO₂ and brine. The dotted line in FIG. 6(a) indicates the projection of mixture viscosity correlated to the pressure and CO₂ mole fraction plane.

FIG. 7 is a pair of graphs showing the gravity number (N) under varying temperatures and pressures for: (a) reservoir fluid consisting of brine (159,000 ppm NaCl) and (b) reservoir fluid consisting of oil with 40° API gravity (825 kg/m³). On each graph, N is represented by the shading that is scaled according to the legends on the right hand side of each graph.

FIG. 8 is a series of graphs comparing the densities of CO₂ and (a) 30° API gravity oil (876 kg/m³), (b) 40° API gravity oil (825 kg/m³), and (c) 50° API gravity oil (780 kg/m³) crude oil under various conditions. The grey area on each graph illustrates the temperatures and pressures where the oil is more dense than CO₂, and the light color area on each graph illustrates the temperatures and pressures where CO₂ is more dense than the oil.

FIG. 9 is a pair of graphs showing the viscosity ratio (M) under varying temperatures and pressures for: (a) reservoir fluid consisting of brine (0.2 NaCl mass fraction) and (b) reservoir fluid consisting of oil with 40° API gravity. On each graph, M is represented by the shading that is scaled according to the legends on the right hand side of each graph.

FIG. 10 is a schematic illustrating the numerical model used for evaluating the CSBOR method.

FIG. 11 is a map of the SACROC Unit at the Horseshoe Atoll in west Texas, which is the basis for the numerical model used in the Example. The cross-section (A-A′) shows the oil reservoir and the OWC layer.

FIG. 12 is a pair of graphs showing generic three-phase relative permeability curves, implemented in the numerical model of the Example, for: (a) brine and oil, and (b) CO₂+brine and CO₂+oil.

FIG. 13 is a series of drawings comparing (a-c) CO₂ sequestration using the CSBOR method of injecting CO₂ below the OWC layer, and (d-f) CO₂ injected into brine only.

FIG. 14 is a conceptual schematic showing an embodiment of a system for sequestering carbon dioxide using the CSBOR method.

DETAILED DESCRIPTION

The present disclosure provides methods and systems for sequestering carbon dioxide by injecting carbon dioxide into a saline (brine) formation below an oil reservoir (aka, CO₂ Storage Beneath Oil Reserves, or CSBOR). These methods and systems may provide at least one advantage over storage in a saline formation alone, including, but not limited to:

1) Enhanced CO₂ solubility: CO₂ solubility in crude oil is about 30 times greater than that in pure water. Further, CO₂ is less soluble in salt water (brine) than in pure water. Thus, at least 30 times more CO₂ can be solubilized (i.e. solubility-trapped) in oil reservoirs that in brine formations.

2) Reduced buoyancy-driven flow of CO₂: CO₂ is less buoyant and migrates less in oil reservoirs than in brine due to the smaller difference in density between CO₂ and crude oil as contrasted to the larger difference in density between CO₂ and brine.

3) Reduced mobility of CO₂: Oil contained in reserves is more viscous than water. This difference in viscosity causes CO₂ to be less mobile in oil than in water. Further, CO₂ mobility is reduced when three phases (CO₂+residual brine+oil) coexist compared to two phases (CO₂+brine).

4) Enhanced component partitioning: In saline formations, CO₂ is the only component that partitions between gas and liquid phases. In oil reservoirs, several different gas components can concurrently partition between the oil and gas phases. Additionally, studies suggest that CO₂ mobility in multiple component-partitioning simulation is smaller than that in single component-partitioning simulation.

5) Availability of caprock: While CO₂ is unlikely to migrate through the oil reservoir, most oil reservoirs are always covered by a caprock, whose seal integrity is already proven by the presence of oil over geologic time. Therefore, it is likely that CO₂ in oil reservoirs will not escape easily through caprock.

6) Availability of existing infrastructure: Above oil reservoirs, infrastructure such as roads, pipelines and wells (e.g., for monitoring) are already in place, and injection sites are easily accessible.

To obtain advantages in terms of CO₂ storage capacity, and to minimize buoyancy-driven migration, CO₂ may be injected below the OWC layer in oil reservoirs and into deep saline formations below oil reservoirs, i.e., a “CSBOR” method. In many oil reservoirs, a significant amount of formation volume exists below the OWC layer. Because the oil-portion of these reservoirs is so effective for trapping CO₂ and minimizing buoyancy-driven migration, CO₂ will be injected as deep as possible below the OWC layer to maximize storage capacity. Additionally, existing production wells can be utilized to monitor for CO₂ movement into the active (productive) area(s) of the reservoir.

In general, CO₂ migration and trapping after injection below the OWC layer in an oil reservoir can be discussed in three stages. The stages are shown schematically in FIG. 1. In Stage I (FIG. 1a), during the injection period, CO₂ expands from the injection location and begins to migrate vertically.

In Stage II (FIG. 1b), after stopping the injection of CO₂, the CO₂ plume gradually migrates vertically until it engages the OWC layer. As CO₂ migrates, an imbibition process occurs at the tail of the CO₂ plume where brine displaces CO₂. As a result, some mobile CO₂ is left behind and trapped as disconnected—or residual—droplets or pores at the tail of the CO₂ plume. The amount of residual-trapped CO₂ in a brine formation is maximized if the CO₂ is injected as deeply below the OWC layer as possible. Solubility trapping also occurs in brine below the OWC layer as some CO₂ dissolves into the brine. This also causes the brine to increase in density and sink relative to less dense brine. Finally, mineral trapping occurs when some of the solubilized CO₂ (which forms carbonic acid) reacts with minerals to form solid carbonate minerals, such as calcium carbonate. In sum, CO₂ is trapped by various trapping mechanisms during Stage 11, including residual, solubility, and mineral trapping into brine below the OWC layer.

In Stage III (FIG. 1c), the CO₂ has reached and begins to penetrate the OWC layer. When this occurs, the vertical movement of mobile CO₂ may be retarded due to at least one of the following reasons: (1) the smaller difference in density between oil and CO₂, as contrasted to the difference in density between brine and CO₂, reduces buoyancy-driven flow; (2) changes of fluid phase conditions from two phases (brine and CO₂) to three phases (oil, residual brine, and CO₂) reduces CO₂ mobility; and (3) changes of fluid-partitioning components from single component (CO₂) to multiple components (CO₂, N₂, C₁, C₂, C₃, et al.) also reduces CO₂ mobility. Theoretically, the oil reservoir above the OWC layer becomes a physical barrier and prevents the buoyancy-driven migration of mobile CO₂. The oil reservoir thus acts as a physical barrier in Stage III. At the same time, the upper part of the mobile CO₂ plume dissolves into, and is solubility-trapped in oil above the OWC layer, while the bottom part of the mobile CO₂ plume continues to dissolve into the brine below (FIG. 1c). Because CO₂ solubility in oil is more than 30 times greater than that in brine (see FIG. 2), solubility-trapping in oil effectively inhibits the vertical movement of mobile CO₂.

Possibly, some CO₂ is not trapped and keeps migrating, as mobile CO₂, upwardly through the oil reservoir. Although this mobile CO₂ moves vertically through the oil reservoir, it may be trapped at the bottom of the caprock.

Generally, after CO₂ is injected into a target storage formation, it will be trapped by different trapping mechanisms such as hydrodynamic, residual, solubility, and mineral trapping, depending on ambient reservoir conditions such as pressure, temperature, salinity, and composition. Solubility trapping, specifically, is defined as trapping CO₂ by dissolution in ambient reservoir fluids such as brine and oil. The amount of CO₂ stored by solubility trapping can be estimated with calibrated solubility algorithms.

FIG. 2 is a graph comparing CO₂ solubility in crude oil to CO₂ solubility in pure water. CO₂ solubility data for crude oil were taken from compilation data by previous researchers, whose data included CO₂ solubility measured for various American Petroleum Institute (API) gravity oils (11.9, 12.1, 13.5, 17.3, 18.2, 18.3, 25.8, and 33.3). FIG. 2 shows that CO₂ solubility in crude oil is about 30 times greater than that in pure water. This discrepancy will be even greater when comparing CO₂ solubility in crude oil to CO₂ solubility in brine, as it is generally known that CO₂ solubility in brine decreases with salt concentration, and CO₂ is more soluble in pure water than in brine. Overall, the potential capacity of CO₂ solubility trapping in oil reservoirs is more than 30 times greater than that for brine formations.

Buoyancy-driven migration is governed by contrasts of fluid densities. CO₂ will migrate vertically more quickly through a fluid having a greater density contrast than through a fluid having a lesser density contrast. To compare buoyancy-driven CO₂ migration in brine formations and oil reservoirs, the fluid densities of CO₂, brine, and crude oil were compared (FIG. 3). For simplicity, temperature and salinity were, respectively, fixed at 54.5° C. and 159,000 ppm, which represent reservoir conditions in the Scurry Area Canyon Reef Operations Committee (SACROC) Unit of western Texas. Densities of CO₂, crude oil, and brine (H₂O—NaCl) were, respectively, calculated from the representative equations-of-states.

CO₂ is a highly compressible fluid compared to both water and crude oil and its density radically increases from about 300 to about 800 kg/m³ at pressure ranging from about 10 to about 25 MPa (FIG. 3). Above about 25 MPa, the density of CO₂ asymptotically reaches over 900 kg/m³, but is always smaller than the corresponding brine density. Crude oil is a less compressible fluid and, in comparison to CO₂, its density does not vary as much with pressure. At pressures from about 10 to about 25 MPa, the densities of heavy oil (30° API) and light oil (50° API) are about 876 and about 780 kg/m³, respectively. Densities of crude oils vary with composition (API gravity) but do not vary as much with pressure. The density contrast between CO₂ and light oil (50° API; 780 kg/m³) is about 100 kg/m³ at 15 MPa and between CO₂ and heavy oil (30° API; 876 kg/m³) is about 200 kg/m³.

A brine density with about 159,000 ppm concentration corresponds to a density of about 1100 kg/m³. Therefore, the approximate density contrast between CO₂ and brine is about 450 kg/m³ at 15 MPa. This comparison suggests that the density contrast between CO₂ and surrounding fluids is about 2.25-4.5 times greater in brine formations than in oil reservoirs. Correspondingly, buoyancy-driven CO₂ migration tends to be 2.25-4.5 times greater in brine formations.

Density of CO₂−dissolved brine becomes greater as more CO₂ dissolves. Other researchers suggest that the density of CO₂−dissolved brine can be as much as 2-3% greater than surrounding brine. Consequently, CO₂−dissolved brine will sink and create density instability resulting in convective transport mixing after several hundred years. In oil reservoirs, dissolution of CO₂ in oil increases the density of CO₂−dissolved oil, which causes such gravitation segregation.

Because gravitational segregation occurs due to the density contrast between CO₂−dissolved fluids and surrounding fluids, the incremental density contrast as CO₂ dissolves may be evaluated. To evaluate this aspect, densities of both CO₂−dissolved brine and oil were compared (FIG. 4). The densities of CO₂−dissolved oil are plotted in FIG. 4a, showing the evolution of densities as a function of pressure, temperature, and CO₂ mole fraction. Oil density with 943.3 kg/m³ (18.5° API) measured at 15.56° C. (circle symbol) increases up to 958.3 kg/m³ (Δρ_oil=15 kg/m³) as CO₂ mole fraction increases from 0.42 to 0.99 (FIG. 4a). Similarly, oil density with 972.5 kg/m³ (14.0° API) measured at 18.33° C. (rectangle symbol) increases up to 983 kg/m³ (Δρ_oil=10.5 kg/m³) for the same increase of CO₂ mole fraction.

Several correlation algorithms are available for the density of CO₂−dissolved brine. Among these algorithms, an equation-of-state was adapted to calculate the density of CO₂−dissolved brine (FIG. 4b). Density of CO₂−dissolved brine (circle symbol) is plotted as a function of pressure at 18.33° C., 0.01 NaCl mole fraction, and 0.01 CO₂ mole fraction. As pressure increases from 2.7 to 20 MPa, the density of CO₂−dissolved brine increases from 1029 to 1037 kg/m³ (Δρ_brine=7 kg/m³). When CO₂ mole fraction only increases from 0.01 to 0.02 (circle vs. rectangle symbols), the densities of CO₂−dissolved brine systematically increase with an approximate density contrast of 6 kg/m³. Similar to the effect of CO₂ dissolution on oil density (FIG. 4a), the density of CO₂−dissolved brine also increases with CO₂ dissolution (FIG. 4b).

To investigate temperature effects on the density of CO₂−dissolved brine, temperature was increased from 18.33° C. to 35° C. (rectangle vs. diamond symbols in FIG. 4b). The increase of temperature causes a systematic decrease of density of about 7 kg/m³. Finally, the density of CO₂−dissolved brine increases NaCl mass fraction from 0.01 to 0.02 (diamond vs. triangle symbols in FIG. 4b). Compared to the density of CO₂−dissolved brine with 0.01 NaCl mole fraction, the density of 0.02 NaCl mole fraction increases more than 20 kg/m³ as a function of pressure. Results of this comparison suggest that the density increments of oil and brine due to CO₂ dissolution are not significant. The density contrast between non-CO₂−bearing reservoir fluids (oil and brine) and CO₂−dissolved counterparts is about 7-15 kg/m³, which is significantly smaller than the density contrasts between supercritical-phase CO₂ and ambient reservoir fluids CO₂−oil: 100 kg/m³, CO₂−brine: 450 kg/m³. Consequently, gravitational segregation (sinking) of CO₂−dissolved fluids will be much slower than buoyancy-driven (vertical) migration of supercritical-phase CO₂.

Greater contrasts of density between CO₂ and ambient reservoir fluids enhance buoyancy-driven CO₂ migration. However, greater contrasts of viscosity between CO₂ and reservoir fluids possibly prohibit vertical CO₂ migration and may induce viscous fingering at CO₂ displacement fronts. In FIG. 5 fluid viscosities of CO₂, brine, and crude oil are compared to evaluate the potential retardation of buoyancy-driven CO₂ migration. Viscosities of CO₂, crude oil, and brine are, respectively, calculated from equations-of-states developed by previous studies for fixed pressure (25 MPa) because viscosities are generally not sensitive to pressure.

A plot of viscosities for different fluids suggests that viscosity variation of crude oil is significantly dependent on both API gravity (density) and temperature (FIG. 5). The viscosities of crude oils decrease with temperature much more than those of CO₂ and water. Among crude oils, the viscosity of heavier density crude oil exhibits the strongest variation with temperature. While temperature increases from 10 to 50° C., the viscosity of the heavier oil with 30° API (876 kg/m³) decreases from 2000 to 20 mPa s.

The overall range of pure water viscosity is from about 0.7-1 mPa s. With greater salinity (0.2 NaCl mole fraction), its viscosity increases to about 2-3 mPa s, suggesting that the effects of both salinity and temperature on water viscosity is relatively minor. The overall range of CO₂ viscosity is shown to be about 0.1 mPa s, indicating that CO₂ is the most mobile fluid and its viscosity variation with temperature is the smallest among these reservoir fluids.

In general, this comparison indicates that the contrasts of viscosities between CO₂ and crude oil are significantly greater than that between CO₂ and brine. Therefore, viscosity effects on buoyancy-driven CO₂ migration will be greater in oil reservoirs than those effects in brine formations. In addition, displacement fronts of CO₂ plumes will likely exhibit significant viscosity fingering in CO₂−crude oil systems.

Additionally, the viscosity of crude oil is significantly reduced as CO₂ dissolves in oil (FIG. 6a). For example, when CO₂ mole fraction increases from 0.46 to 0.99, the viscosity of CO₂−dissolved crude oil at 15.56° C. and 972.5 kg/m³ (diamond symbol) decreases from 5790 to 97.7 mPa s. The magnitude of viscosity reduction was about 5690 mPa s. In the case of crude oil at 18.33° C. and 943.3 kg/m³ (circle symbol), the magnitude of viscosity reduction was 208.7 mPa s. This comparison suggests that the reduction of oil viscosity due to CO₂ dissolution is significant and its magnitude, which is strongly dependent on intrinsic oil density (API gravity), ranges from about 200 to 5000 mPa s.

The viscosity of 0.02 molality NaCl brine without dissolved CO₂ at 30° C. (circle symbol) is about 0.82 mPa s and does not vary with pressure (FIG. 6b). To investigate the effect of CO₂ dissolution on brine viscosity, the viscosity of CO₂−dissolved brine was plotted with 0.02 CO₂ mole fraction and 0.02 NaCl mole fraction at 30° C. (diamond symbol). This comparison (circle vs. diamond symbols in FIG. 6b) shows that 0.02 mole fraction of CO₂ dissolution in brine increases brine viscosity from 0.82 to 0.92 mPa s (Δμ=0.10 mPa s). In addition, as temperature increases from 30 to 50° C., the viscosity of CO₂−dissolved brine decreases from 0.92 to 0.6 mPa s (diamond vs. rectangle symbols in FIG. 6b).

This comparison suggests that viscosity contrasts between CO₂−dissolved oil and straight (no CO₂) crude oil vary more than hundreds of mPa s (FIG. 6a) and that between CO₂−dissolved brine and straight (no CO₂) brine is about 0.09 mPa s (FIG. 6b). Since the viscosity of CO₂−dissolved oil is several hundreds times greater than that of CO₂−dissolved brine, gravitational segregation will potentially be retarded more in oil reservoirs.

The tendency of buoyancy-driven CO₂ migration can be quantified with the gravity number (N), which is the ratio of gravity forces to viscous forces. Typically, the influence of gravity forces will cause a CO₂ plume to reach quickly below a low permeability caprock and consequently decrease the sweep efficiency of oil during CO₂ enhanced oil recovery. In CO₂ sequestration, greater gravity forces accelerate vertical CO₂ migration and, hence, increase the probability that vertically mobile CO₂ may come into contact with faults or other leakage pathways, especially as it contacts caprock.

In this study, N of CO₂ was compared in brine formations and oil reservoirs to quantify the degree of gravity-driven CO₂ migration. N is determined from

$\frac{k_x\left({\rho }_f-{\rho }_{{\mathrm{CO}}_2}\right){\mathrm{gkr}}_{{\mathrm{CO}}_2}}{{\mu }_{{\mathrm{CO}}_2}v},$

where f represents either brine or oil, k_x is the horizontal permeability, ρ_CO2 is the density of CO₂, g is gravity, k_xKr_CO2 is the relative permeability of CO₂, μ_CO2 is the viscosity of CO₂, and v is the velocity of CO₂. For solely investigating the effect of thermodynamic properties, it was assumed that k_xkr_CO2/v is equal to 1 in this calculation. FIG. 7 shows the variation of N as functions of pressure and temperature in brine formations (FIG. 7a) and oil reservoirs (FIG. 7(b). This comparison suggests that the magnitude of N is smaller in oil reservoirs, indicating that buoyancy-driven CO₂ migration will be smaller in the oil reservoirs than in saline formations.

Both plots show that an increase in pressure causes a decrease in N, which indicates that density contrasts between CO₂ and fluids (i.e., brine and oil) decrease as pressure increases. In addition, these plots also indicate that N increases as temperature increases. This analysis suggests that CO₂ injection into targeted formations and reservoirs with high pressure and low temperature conditions will help minimize buoyancy-driven CO₂ migration, and suggests that CO₂ injection into high temperature systems will possibly cause significant buoyancy-driven migration.

Finally, examination of this data reveals that a near-perfect seal condition exists in oil reservoirs where the CO₂ plume is not buoyant because the CO₂ density is greater than the density of surrounding oils. In FIG. 7b, the zone where N is less than zero (white color) indicates that the density of CO₂ is greater than that of crude oil. In this zone, no buoyancy-driven CO₂ migration occurs and, therefore, sequestered CO₂ will migrate downward because the CO₂ density is greater than surrounding fluids. This zone also appears in FIG. 3, showing CO₂ density values for different API gravity oils as a function of pressure. In particular, at 54.5° C., CO₂ density becomes greater than oil density for 50° API gravity (780 kg/m³) over 21 MPa (FIG. 3). As oil becomes heavier (smaller API gravity), the transition pressure at 54.5° C., where CO₂ density becomes greater than oil density, increases.

Because FIG. 3 is plotted for a fixed temperature, zones were identified where CO₂ density is greater than oil density as a function of both pressure and temperature (FIG. 8). In FIG. 8, the grey area illustrates the temperatures and pressures where oil is more dense than CO₂, whereas the lighter areas illustrate the temperatures and pressures where CO₂ is more dense than oil. Reservoirs with lighter oil (FIG. 8c) have a greater range of temperatures and pressures where CO₂ is more dense, and as such, reservoirs with lighter oil are more capable than reservoirs with heavier oil at reducing buoyancy-driven CO₂ migration.

It may be advantageous to sequester CO₂ as a supercritical fluid. CO₂ exists as a supercritical fluid when it is at or above its critical temperature (about 31.1° C.) and pressure (about 7.39 MPa). Supercritical CO₂ has somewhat uncommon properties that are midway between those of a gas and a liquid. More specifically, it expands to fill a space like a gas, but has a density like that of a liquid. As shown and discussed above, supercritical carbon dioxide may be ideally suited for CSBOR. When CO₂ is injected into a saline formation as a supercritical fluid, lighter oil reservoirs may provide an opportunity to effectively serve as a seal that prevents buoyancy-driven CO₂ migration, much like a caprock would. As such, the methods disclosed herein may include sequestering CO₂ at pressures above about 10 MPa, such as at pressures above about 15 MPa. In view of conditions that may be observed in the field, the CO₂ may be sequestered at pressures below about 30 MPa, such as at pressures below about 25 MPa. For example, the carbon dioxide may be sequestered at pressures between about 10 MPa and about 30 MPa, such as at pressures between about 15 and about 30 MPa, between about 10 MPa and about 25 MPa, or between about 15 MPa and about 25 MPa. The methods disclosed herein also may include sequestering CO₂ at temperatures above about 25° C., such as at temperatures above about 35° C. The carbon dioxide also may be sequestered at temperatures below about 60° C., such as at a temperature below about 50° C. For example, the carbon dioxide may be sequestered at temperatures between about 25 and about 60° C., such as at temperatures between about 35 and about 60° C., between about 25 and about 50° C. or between about 35 and about 50° C.

The tendency of buoyancy-driven CO₂ migration can be quantified with N. In a similar manner, the tendency of CO₂ mobility, where fluids compete with each other, can be estimated with viscosity ratio (M), which is determined from

$\frac{{\mathrm{kr}}_{{\mathrm{CO}}_2}{\mu }_f}{{\mathrm{kr}}_f{\mu }_{{\mathrm{CO}}_2}}.$

Here, f represents either brine or oil, k_r is relative permeability, and μ is the viscosity of fluid. For solely investigating the effect of thermodynamic properties, it was assumed that kr_CO2/kr_f is equal to 1. FIG. 9 compares the variation of M as functions of pressure and temperature in a brine formation (FIG. 9a) and an oil reservoir (FIG. 9b). The variation of M is smaller in the brine formation (FIG. 9a) than in the oil reservoir (FIG. 9b), suggesting that smaller resistance to CO₂ mobility will exist in brine formation. Since buoyancy is a major driving force on CO₂ migration in these conditions, CO₂ plumes in brine formations will migrate farther vertically than CO₂ plumes in oil reservoirs.

For CO₂ injection in brine formations, FIG. 9a shows that viscous forces dominate in low pressure and high temperature conditions. In oil reservoirs (FIG. 9b), viscous forces and reduced CO₂ mobility occur in lower temperature areas (20-30° C.). Thus, overall CO₂ migration in the oil reservoir will be inhibited more than CO₂ in brine formations without oil present.

Systems for sequestering carbon dioxide beneath the OWC layer are also disclosed. In some embodiments, the system may allow for the sequestration of carbon dioxide under land, and thus may include one or more well heads that are onshore. In some embodiments, the system may allow for the sequestration of carbon dioxide under the seafloor, and thus may include a well head that is underwater, such as at the bottom of the ocean. Systems may comprise a well extending from the well head to a saline formation beneath an oil reservoir, and a pump, operatively connected to the well and capable of injecting carbon dioxide into the saline formation beneath the oil reservoir. The pump may be operatively connected to a pipeline containing CO₂. Alternatively or additionally, the pump may be operatively connected to one or more tanks of CO₂, such as a tank of compressed CO₂. For example, the pump may be removably attachable to one or more tanks of CO₂. The CO₂ may be a gas, a liquid, a supercritical fluid, or a mixture thereof, when the carbon dioxide is injected into the saline formation.

Pumps, wells, pipes, wellheads, and compression stations suitable for use in the presently disclosed systems are known to those of skill in the art of enhanced oil recovery. However, the presently disclosed system for sequestering CO₂ differs from those used for enhanced oil recovery in that the CO₂ is injected at a depth below the oil-water contact layer, such as at least about 10 m, and more typically at least about 100 m, and more typically at least about 500 m below the OWC layer. Moreover, the CO₂ is injected as a supercritical fluid, such as at a pressure between about 10 and about 30 MPa, and more typically between about 15 and about 25 MPa, and at a temperature between about 25 and about 60° C. and more preferably between about 35 and about 50° C.

Additionally, because the CO₂ is intended to be stored for geologically-meaningful time periods, it may be necessary to monitor the oil layer, the saline layer, and the area surrounding the injection site for system changes due to the sequestered CO₂. For example, it would be desirable to know whether a large amount of CO₂ were to cross the oil-water contact layer, or escape the caprock. As such, the presently disclosed systems for sequestering CO₂ also may include a monitoring system configured to monitor the amount of CO₂ in a portion of the saline formation, a portion of the oil reservoir, or both. The monitoring system may include a monitoring station, and one or more sensors coupled to the monitoring station, where each sensor may be in contact with the oil reservoir and/or the saline formation, and may be configured to take measurements that correlate to the amount of CO₂ in the environment surrounding the sensor. For example, each sensor may be configured to measure at least one of the temperature, salinity, pH, pressure, and/or CO₂ concentration of fluids in contact with the sensor. The monitoring system also may include one or more monitoring wells, where each monitoring well is coupled to either the saline formation and/or the oil reservoir, and each sensor is coupled to the monitoring system by a coupling element that extends through one of the monitoring wells. For example, a particular sensor may be physically coupled to the monitoring station by a cable coupling element, such as may be wrapped around a winch so that the sensor can be raised and lowered within the monitoring well to desired depths, and can be removed from the well for maintenance. Alternatively or additionally, a particular sensor may be electrically coupled to the monitoring station by an electrical wire coupling element that permits one- and two-way wired communication between the sensor and the monitoring station, although a sensor also may be in wireless communication with the monitoring station. Some monitoring systems may include at least a first sensor in contact with the oil reservoir and a second sensor in contact with the saline formation. The first and second sensors each may be coupled to the monitoring station by coupling elements that extend through the same or different mentoring wells.

The monitoring system may be configured to produce an alert when the amount of CO₂ in the portion of the saline formation or the portion of the oil reservoir exceeds a predetermined amount. For example, the monitoring system may be configured to produce an alert when the amount of CO₂ in fluids surrounding a particular sensor exceeds a value of about 0.001% CO₂, about 0.0025% CO₂, about 0.005% CO₂, about 0.0075% CO₂, and/or about 0.01% CO₂, among other suitable values. Likewise, the monitoring system may be configured to produce an alert when the amount of CO₂ in fluids surrounding a particular sensor exceeds a value of about 300 ppm CO₂, about 400 ppm CO₂, about 500 ppm CO₂, about 600 ppm CO₂, and/or about 700 ppm CO₂, among other suitable values. Alternatively or additionally, the monitoring station may be configured to produce an alert when the amount of CO₂ in the portion of the saline formation or the portion of the oil reservoir changes from some baseline amount (such as a preselected concentration, an amount equal to an average observed amount based on measurements of CO₂ over a selected period of time, or any other desired baseline amount) by some predetermined amount, or by some integer or non-integer factor of the baseline amount. For example, the monitoring station may be configured to produce an alert when the baseline amount changes by any desired factor, including but not limited to a factor of 2, 2.5, 5, 10, 15.5, 25.5, 50.25, 100.73, or any other desired factor.

It is to be understood that the invention is not limited in its application to the details of construction and the arrangement of components set forth in the present description. The invention is capable of other embodiments and of being practiced or of being carried out in various ways. Also it is to be understood that the phraseology and terminology used herein is for the purpose of description only, and should not be regarded as limiting. Ordinal indicators, such as first, second, and third, as used in the description and the claims to refer to various structures, are not meant to be construed to indicate any specific structures, or any particular order or configuration to such structures. All methods described herein can be performed in any suitable order unless otherwise indicated herein or otherwise clearly contradicted by context. The use of any and all examples, or exemplary language (e.g., “such as”) provided herein, is intended merely to better illuminate the invention and does not pose a limitation on the scope of the invention unless otherwise claimed. No language in the specification, and no structures shown in the drawings, should be construed as indicating that any non-claimed element is essential to the practice of the invention.

Recitation of ranges of values herein are merely intended to serve as a shorthand method of referring individually to each separate value falling within the range, unless otherwise indicated herein, and each separate value is incorporated into the specification as if it were individually recited herein. For example, if a concentration range is stated as 1% to 50%, it is intended that values such as 2% to 40%, 10% to 30%, or 1% to 3%, etc., are expressly enumerated in this specification. These are only examples of what is specifically intended, and all possible combinations of numerical values between and including the lowest value and the highest value enumerated are to be considered to be expressly stated in this application.

Further, no admission is made that any reference, including any non-patent or patent document cited in this specification, constitutes prior art. In particular, it will be understood that, unless otherwise stated, reference to any document herein does not constitute an admission that any of these documents forms part of the common general knowledge in the art in the United States or in any other country. Any discussion of the references states what their authors assert, and the applicant reserves the right to challenge the accuracy and pertinency of any of the documents cited herein.

EXAMPLES

Example 1

Comparison of Simulated CO₂ Sequestration in a Saline Formation And Simulated CO₂ Sequestration in an Oil Reserve Below a Saline Formation

FIG. 10 is a schematic showing a two-dimensional model for evaluating the CSBOR method. The parameters for the simulation model were taken from an oil reservoir in the SACROC Unit in western Texas. As shown in FIG. 11, the SACROC Unit is located in the southeastern segment of the Horseshoe Atoll within the Midland basin. Within the SACROC Unit, the Cisco and Canyon regions are the major oil reservoirs, which are covered by low permeability units, including the Wolfcamp shale Formation. The OWC layer is located in the middle of the lower Canyon region. The simulation was performed with the GEM simulator, a multi-dimensional, finite-difference, isothermal compositional simulator, developed and owned by CMG Ltd.

The model shown in FIG. 10, and the parameters shown in Table 1 below, were used to simulate what likely would occur after injecting CO₂ below the OWC layer in the SACROC Unit. The size of the simulated model was 37.5 m wide and 25 m thick. Homogenous and isotropic rock properties (permeability: 10⁻¹³ m² and porosity: 0.2) were assigned for simplicity. The initial pressure and temperature conditions were estimated from SACROC Unit conditions. The initial oil saturation above the OWC layer was estimated to be 72%, with 28% brine. Brine saturation below the OWC layer was estimated to be 99%. Oil was estimated to be a mixture of eleven different components. Finally, a low permeability caprock (10⁻¹⁸ m²) was assigned below the top boundary. The densities of brine, oil, and CO₂ were estimated to be 1101, 801, and 650 kg/m³, respectively. In addition, the viscosities of brine, oil, and CO₂ were estimated to be 0.895, 2.466, and 0.0594 mPa s, respectively. The CO₂ solubility in oil (0.6 mole fraction) was estimated to be about 38 times greater than in brine (0.016 mole fraction). To compare the effects of buoyant and viscous forces on CO₂ migration between brine and oil, gravity numbers (N) and viscosity ratios (M) were calculated and are summarized in Table 1. Comparison of N and M values show that the buoyant force in oil is about seven times smaller than that in brine and the viscous force in oil is about seven times greater than that in brine. Therefore, once the CO₂ plume reaches the bottom of the oil reservoir, its migration is expected to slow.

TABLE 1
Model parameters of numerical model
describing CSBOR scheme in FIG. 10.
Number of elements               x-Direction: 150, z-direction: 100
Size of each element (m)         Δx = 0.25, Δy = 10, Δz = 0.25
Initial pressure condition (MPa) Hydrostatic gradient from bottom
                                 (16.68) to top (16.45)
Initial temperature condition (° C.) Uniform temperature (56.78)
Saturation in oil reservoir      Brine: 0.28, oil: 0.72
Boundary conditions (top and     Constant pressure
bottom)
Porosity                         Uniform porosity (0.2)
Reservoir permeability (m2)      Uniform permeability 10−13
Caprock permeability (m2)        Uniform permeability 10−18
Salinity of brine (molality)     1.0
Oil composition                  CO2, N2, C1, C2, C3, I-C4, N-C4,
                                 I-C5, N-C5, FC6, C7+
Predicted fluid density (kg/m3)  Brine: 1101, oil: 801, and CO2: 650
Predicted fluid viscosity (mPa s) Brine: 0.895, oil: 2.466, and
                                 CO2: 0.0594
Predicted CO2 solubility (mole   Brine: 0.016, oil: 0.6
fraction)
Estimated gravity number (M)     CO2-brine: 1.1-2.1;
                                 CO2-oil: 0.003-0.3
Estimated end-point mobility ratio CO2-brine: 1-4; CO2-oil: 1-30
(N)
Simulation period                2 years

FIG. 12 shows generic three-phase relative permeability curves, implemented in the numerical model of FIG. 10, for (a) brine and oil, and (b) CO₂+brine and CO₂+oil. The relative permeabilities of both brine and oil in FIG. 12a have identical residual saturation (0.2) and irreducible saturation (0.1). For the relative permeability of both liquids (oil and brine) and CO₂ in FIG. 12b, the irreducible liquid (oil and brine) saturation is 0.2, which is simply the sum of irreducible oil (0.1) and irreducible brine (0.1) saturation. Similarly, the residual liquid saturation is 0.3, which is the sum of residual oil saturation (0.2) and irreducible brine saturation (0.1). Finally, both residual CO₂ saturation and irreducible CO₂ saturation are assumed to be 0.1. For the sake of simplicity, and to isolate the fundamental behavior of CO₂ migration in a two-fluids zone, hysteresis was not accounted for. Because of the non-hysteretic condition, CO₂ residual trapping occurs in this model only when CO₂ saturation is smaller than the residual CO₂ saturation (0.1). In addition, capillary forces are excluded in this model because it would be difficult to distinguish capillary force effect from viscous force effect on CO₂ migration.

The simulation is built to investigate buoyancy-driven migration of injected CO₂ several decades after CO₂ injection has ceased. At this time, the effect of injection-induced pressure will disappear and the main cause of CO₂ vertical migration will be due to the density contrast between CO₂ and surrounding fluids. To investigate buoyancy-driven CO₂ migration only, 99% of initial CO₂ saturation is placed at the bottom of the model (See FIG. 10). The simulation predicts brine-solubility, residual, and oil-solubility trapping mechanisms and evaluates these trapping mechanisms at different times. Chemical reactions describing mineralization are disregarded because the 2 years of simulation period is too short for significant mineral precipitation and dissolution to occur.

FIGS. 13a-c simulate what likely would happen after injecting CO₂ below the OWC layer at 120, 230 and 635 days, respectively. FIG. 13a shows that, during the first 120 days, the CO₂ plume would migrate about 10 m due to the density contrast between CO₂ and brine. The OWC layer would be slightly distorted by the pressure of the approaching CO₂ plume. At this stage, much of the CO₂ would still be mobile. FIG. 13b shows that, after 230 days, the CO₂ plume would have reached the OWC layer. The CO₂ plume would spread out widely directly below the OWC layer, and its saturation would be increased. The accumulation of CO₂ directly below the OWC layer suggests that the oil reservoir would act as a physical barrier. At the same time, the saturation of the CO₂ plume where it immediately contacts the oil reservoir would be significantly decreased, indicating that CO₂ in the upper part of plume would be dissolving into the oil reservoir. Some CO₂ would be trapped as solubilized CO₂ as the plume migrates through the brine formation. In addition, both mobile and residual CO₂ would continuously dissolve into brine below the OWC layer. In sum, residual, brine-solubility, and oil-solubility trappings concurrently would occur in this stage. FIG. 13c shows that, after 635 days, CO₂ would be trapped as both residual and dissolved CO₂ in the brine below the OWC layer. The rest of the CO₂ would be trapped in the oil reservoir. Notably, none of the CO₂ would reach the caprock.

FIGS. 13d-f simulate what likely would happen after injecting CO₂ into a brine-only formation at 120, 230 and 635 days, respectively. This model was achieved by removing oil from the previous model. FIG. 13d shows that, at 120 days, the migration patterns of CO₂ in brine only is identical to the migration pattern shown in FIG. 13a. However, FIG. 13e shows that, after 230 days, CO₂ in the brine formation already would reach the caprock. This suggests that brines formation have greater buoyancy, smaller viscous force conditions, and less solubility than formations with oil. FIG. 13f shows that, after 635 days, some CO₂ is trapped as residual CO₂, but most of it migrates vertically through the brine formation.

The comparisons shown in FIG. 13 indicate that CSBOR significantly reduces the amount of mobile CO₂ and buoyancy-driven CO₂ migration as compared to CO₂ injection into non-oil-bearing saline formations.

Example 2

Systems for Sequestering Carbon Dioxide

Oil-bearing formations comprising a saline aquifer beneath an oil reservoir, similar to the formation shown in FIG. 14, may be utilized for sequestering CO₂. Formation previously used for crude oil production may be ideal for such purposes. A pre-existing production well may be deepened so that the well reaches the saline aquifer beneath the oil reservoir, as shown schematically in FIG. 14. For example, the well may include a 4.5″ O.D. steel pipe that is nested inside a 7.5″ O.D. steel pipe. The well may have perforations at the end distal from the injection well head to allow the CO₂ to be injected into the aquifer. For example, the 7.5″ O.D. steel pipe may include perforations, and the 4.5″ pipe may be sealed to the 7.5″ pipe near the perforations so that CO₂ can be injected into the aquifer without allowing water to pass to the surface. The perforations may be at or around a position that is greater than 10 m below the OWC layer, such as greater than 100 m, or even greater than 500 m. In some embodiments, optimal perforations may be at or around a position that is about 120 m below the OWC layer. The well may be fitted with an injection well head (e.g., a well head made by Cameron Corporation, Houston, Tex.) capable of receiving compressed gas from a pump (e.g., a booster pump as made by Fabrication Technologies, Casper, Wyo.) capable of pushing compressed CO₂ into the well head, through the well, and ultimately into the saline aquifer. The pump may be connected via a pipeline (e.g., a 12″ pipe) to a compression station (e.g. as may be made by Siemens AG, Erlangen, Germany) where the CO₂ will be compressed as it passes through a regional pipeline carrying compressed CO₂. For example, the CO₂ may be injected into the saline formation at a pressure greater than about 10 MPa, such as about 20 MPa.

In order to verify that the CO₂ is being delivered to the aquifer, and in order to monitor whether the CO₂ is staying sequestered, the system for sequestering CO₂ may include a monitoring system configured to monitor the amount of CO₂ in a portion of the saline formation, a portion of the oil reservoir, or both, such as is illustrated in FIG. 14. The monitoring system may include a monitoring station, and one or more sensors coupled to the monitoring station, where each sensor may be in contact with the oil reservoir and/or the saline formation, and may be configured to take measurements that correlate to the amount of CO₂ in the environment surrounding the sensor. For example, each sensor may be configured to measure at least one of the temperature, salinity, pH, pressure, and/or CO₂ concentration of fluids in contact with the sensor. The monitoring system also may include one or more monitoring wells, where each monitoring well is coupled to either the saline formation and/or the oil reservoir, and each sensor is coupled to the monitoring system by a coupling element that extends through one of the monitoring wells. For example, a particular sensor may be physically coupled to the monitoring station by a cable coupling element, such as may be wrapped around a winch so that the sensor can be raised and lowered within the monitoring well to desired depths, and can be removed from the well for maintenance. Alternatively or additionally, a particular sensor may be electrically coupled to the monitoring station by an electrical wire coupling element that permits one- and two-way wired communication between the sensor and the monitoring station, although a sensor also may be in wireless communication with the monitoring station. Some monitoring systems may include at least a first sensor in contact with the oil reservoir and a second sensor in contact with the saline formation. The first and second sensors each may be coupled to the monitoring station by coupling elements that extend through the same or different mentoring wells.

The monitoring system may be configured to produce an alert when the amount of CO₂ in the portion of the saline formation or the portion of the oil reservoir exceeds a predetermined amount. For example, the monitoring system may be configured to produce an alert when the amount of CO₂ in fluids surrounding a particular sensor exceeds a value of about 0.001% CO₂, about 0.0025% CO₂, about 0.005% CO₂, about 0.0075% CO₂, and/or about 0.01% CO₂, among other suitable values. Likewise, the monitoring system may be configured to produce an alert when the amount of CO₂ in fluids surrounding a particular sensor exceeds a value of about 300 ppm CO₂, about 400 ppm CO₂, about 500 ppm CO₂, about 600 ppm CO₂, and/or about 700 ppm CO₂, among other suitable values. Alternatively or additionally, the monitoring station may be configured to produce an alert when the amount of CO₂ in the portion of the saline formation or the portion of the oil reservoir changes from some baseline amount (such as a preselected concentration, an amount equal to an average observed amount based on measurements of CO₂ over a selected period of time, or any other desired baseline amount) by some predetermined amount, or by some integer or non-integer factor of the baseline amount. For example, the monitoring station may be configured to produce an alert when the baseline amount changes by any desired factor, including but not limited to a factor of about 2, about 2.5, about 5 about 10, about 15.5, about 25.5, about 50.25, about 100.73, or any other desired factor.

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Claims

1. A method of sequestering carbon dioxide comprising injecting carbon dioxide into a saline formation below an oil reservoir.

2. The method of claim 1, wherein the carbon dioxide is injected into the saline formation at a pressure between about 5 and about 30 MPa.

3. The method of claim 2, wherein the carbon dioxide is injected into the saline formation at a pressure between about 15 and about 25 MPa.

4. The method of claim 1, wherein the carbon dioxide is injected into the saline formation at a temperature of about 25 to about 90° C.

5. The method of claim 4, wherein the carbon dioxide is injected into the saline formation at a temperature of about 35 to about 50° C.

6. The method of claim 1, wherein the saline formation and the oil reservoir contact to form an oil-water contact (OWC) layer, and the carbon dioxide is injected into the saline formation at a depth greater than about 10 m below the OWC layer.

7. The method of claim 6, wherein the carbon dioxide is injected into the saline formation at a depth greater than about 100 m below the OWC layer.

8. The method of claim 6, wherein the carbon dioxide is injected into the saline formation at a depth greater than about 500 m below the OWC layer.

9. The method of claim 1, wherein the carbon dioxide is a gas, a liquid, a supercritical fluid, or a mixture thereof, when the carbon dioxide is injected into the saline formation.

10. The method of claim 9, wherein the carbon dioxide is a supercritical fluid when the carbon dioxide is injected into the saline formation.

11. A system for sequestering carbon dioxide, the system comprising:

a well in fluid communication with a saline formation beneath an oil reservoir; and

a pump operatively connected to the well and configured to inject carbon dioxide through the well and into the saline formation beneath the oil reservoir.

12. The system of claim 11, further comprising a pipeline containing the CO2, wherein the pump is in fluid communication with the pipeline to draw the CO2 from the pipeline.

13. The system of claim 11, further comprising a tank containing CO2, wherein the pump is in fluid communication with the tank to draw the CO2 from the tank

14. The system of claim 11, further comprising a monitoring system configured to monitor the amount of CO2 in a portion of the saline formation, a portion of the oil reservoir, or both.

15. The system of claim 14, wherein the monitoring system is configured to produce an alert when the amount of CO2 in the portion of the saline formation or the portion of the oil reservoir exceeds a predetermined amount.

16. The system of claim 14, wherein the monitoring system includes a monitoring station and a sensor in communication with the monitoring station and positioned in the saline formation or the oil reservoir, wherein the sensor is configured to take measurements that correlate to the amount of CO2 in the environment surrounding the sensor.

17. The system of claim 16, wherein the sensor is configured to measure at least one of the temperature, salinity, pH, pressure, and CO2 concentration of fluids in contact with the sensor.

18. The system of claim 16, further comprising a monitoring well in fluid communication with either the saline formation or the oil reservoir, and a coupling element that extends through the monitoring well and is coupled to the sensor.

19. The system of claim 16, wherein the sensor is a first sensor in contact with the oil reservoir, and wherein the system further includes a second sensor in communication with the monitoring station and in contact with the saline formation, wherein the second sensor is configured to take measurements that correlate to the amount of CO2 in the environment surrounding the second sensor.

20. The system of claim 19, further comprising a second monitoring well in fluid communication with the saline formation, and a second coupling element that extends through the second monitoring well and is coupled to the second sensor.