WO2011146082A2 - Methods and systems for co2 sequestration - Google Patents

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

METHODS AND SYSTEMS FOR C0₂ SEQUESTRATION

Cross-Reference to Related Applications

[0001] This patent application claims priority to U.S. Provisional Patent Application No. 61/347297 filed May 21 , 2010, the content of which is incorporated herein by reference in its entirety.

Introduction

[0002] 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 C0₂ into the atmosphere. Based on this premise, it has been suggested that it is necessary to reduce current C0₂ 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 C0₂ sequestration may be the most beneficial and effective short-term approach to curbing global warming.

Summary

[0003] 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.

[0004] 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 C0₂. Alternatively or additionally, the pump may be operatively connected to one or more tanks of C0₂, such as a tank of compressed C0₂. For example, the pump may be removably attachable to one or more tanks of C0₂. 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.

[0005] The system(s) for sequestering carbon dioxide may include a monitoring system configured to monitor the amount of C0₂ 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 C0₂ 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 C0₂ 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.

[0006] The monitoring system may be configured to produce an alert when the amount of C0₂ 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 C0₂ in fluids surrounding a particular sensor exceeds a value of about 0.001% C0₂, about 0.0025% C0₂, about 0.005% C0₂, about 0.0075% C0₂, and/or about 0.01 % C0₂, among other suitable values. Likewise, the monitoring system may be configured to produce an alert when the amount of C0₂ in fluids surrounding a particular sensor exceeds a value of about 300 ppm C0₂, about 400 ppm C0₂, about 500 ppm C0₂, about 600 ppm C0₂, and/or about 700 ppm C0₂, among other suitable values. Alternatively or additionally, the monitoring station may be configured to produce an alert when the amount of C0₂ 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 C0₂ 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.

[0007] Other aspects of the invention will become apparent by consideration of the detailed description and accompanying drawings.

Brief Descriptions of the Drawings

[0008] Fig. 1 is a series of conceptual diagrams showing a method of sequestering C0₂ beneath an oil reserve that includes injecting the C0₂ below an OWC layer, where: (a) shows Stage I, (b) shows Stage II, and (c) shows Stage III of C0₂ sequestration.

[0009] Fig. 2 is a graph comparing C0₂ solubility in crude oil to C0₂ solubility in pure water.

[0010] Fig. 3 is a graph comparing the densities of C0₂, 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. [0011] Fig. 4 is a pair of graphs comparing: (a) the densities of mixtures of C0₂ and crude oil under various conditions, and (b) the densities of mixtures of C0₂ and brine under various conditions.

[0012] Fig. 5 is a graph comparing the viscosities of C0₂, water, brine, and various crude oils at various temperatures. Viscosities are calculated at a representative pressure of 25 MPa.

[0013] Fig. 6 is a pair of graphs comparing the viscosities for: (a) mixtures of C0₂ and crude oil and (b) mixtures of C0₂ and brine. The dotted line in Fig. 6(a) indicates the projection of mixture viscosity correlated to the pressure and C0₂ mole fraction plane.

[0014] Fig. 7 is a pair of graphs showing the gravity number (Λ/) under varying temperatures and pressures for: (a) reservoir fluid consisting of brine (159,000 ppm NaCI) 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.

[0015] Fig. 8 is a series of graphs comparing the densities of C0₂ and (a) 30 °API gravity oil (876 kg/m³), (b) 40 °API gravity oil (825 kg/m³), and (c) 50 ^DAPI 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 C0₂, and the light color area on each graph illustrates the temperatures and pressures where C0₂ is more dense than the oil.

[0016] 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 NaCI 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.

[0017] Fig. 10 is a schematic illustrating the numerical model used for evaluating the CSBOR method.

[0018] Fig. 1 1 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 (Α-Α') shows the oil reservoir and the OWC layer. [0019] 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) C0₂ + brine and C0₂ + oil.

[0020] Fig. 13 is a series of drawings comparing (a-c) C0₂ sequestration using the CSBOR method of injecting C0₂ below the OWC layer, and (d-f) C0₂ injected into brine only.

[0021] Fig. 14 is a conceptual schematic showing an embodiment of a system for sequestering carbon dioxide using the CSBOR method.

Detailed Description

[0022] 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, C0₂ 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:

[0023] 1) Enhanced C0₂ solubility: C0₂ solubility in crude oil is about 30 times greater than that in pure water. Further, C0₂ is less soluble in salt water (brine) than in pure water. Thus, at least 30 times more C0₂ can be solubilized (i.e. solubility-trapped) in oil reservoirs that in brine formations.

[0024] 2) Reduced buoyancy-driven flow of C0₂: C0₂ is less buoyant and migrates less in oil reservoirs than in brine due to the smaller difference in density between C0₂ and crude oil as contrasted to the larger difference in density between C0₂ and brine.

[0025] 3) Reduced mobility of C0₂: Oil contained in reserves is more viscous than water. This difference in viscosity causes C0₂ to be less mobile in oil than in water. Further, C0₂ mobility is reduced when three phases (C0₂ + residual brine + oil) coexist compared to two phases (C0₂ + brine).

[0026] 4) Enhanced component partitioning: In saline formations, C0₂ 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 C0₂ mobility in multiple component-partitioning simulation is smaller than that in single component-partitioning simulation.

[0027] 5) Availability of caprock: While C0₂ 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 C0₂ in oil reservoirs will not escape easily through caprock.

[0028] 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.

[0029] To obtain advantages in terms of C0₂ storage capacity, and to minimize buoyancy-driven migration, C0₂ 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 C0₂ and minimizing buoyancy- driven migration, C0₂ 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 C0₂ movement into the active (productive) area(s) of the reservoir.

[0030] In general, C0₂ 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. 1 a), during the injection period, C0₂ expands from the injection location and begins to migrate vertically.

[0031] In Stage II (Fig. 1 b), after stopping the injection of C0₂, the C0₂ plume gradually migrates vertically until it engages the OWC layer. As C0₂ migrates, an imbibition process occurs at the tail of the C0₂ plume where brine displaces C0₂. As a result, some mobile C0₂ is left behind and trapped as disconnected - or residual - droplets or pores at the tail of the C0₂ plume. The amount of residual-trapped C0₂ in a brine formation is maximized if the C0₂ is injected as deeply below the OWC layer as possible. Solubility trapping also occurs in brine below the OWC layer as some C0₂ 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 C0₂ (which forms carbonic acid) reacts with minerals to form solid carbonate minerals, such as calcium carbonate. In sum, C0₂ is trapped by various trapping mechanisms during Stage II, including residual, solubility, and mineral trapping into brine below the OWC layer.

[0032] In Stage III (Fig. 1 c), the C0₂ has reached and begins to penetrate the OWC layer. When this occurs, the vertical movement of mobile C0₂ may be retarded due to at least one of the following reasons: (1) the smaller difference in density between oil and C0₂, as contrasted to the difference in density between brine and C0₂, reduces buoyancy-driven flow; (2) changes of fluid phase conditions from two phases (brine and C0₂) to three phases (oil, residual brine, and C0₂) reduces C0₂ mobility; and (3) changes of fluid-partitioning components from single component (C0₂) to multiple components (C0₂, N₂, Ci , C₂, C₃, et al.) also reduces C0₂ mobility. Theoretically, the oil reservoir above the OWC layer becomes a physical barrier and prevents the buoyancy-driven migration of mobile C0₂. The oil reservoir thus acts as a physical barrier in Stage III. At the same time, the upper part of the mobile C0₂ plume dissolves into, and is solubility-trapped in oil above the OWC layer, while the bottom part of the mobile C0₂ plume continues to dissolve into the brine below (Fig. 1 c). Because C0₂ 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 C0₂.

[0033] Possibly, some C0₂ is not trapped and keeps migrating, as mobile C0_2p upwardly through the oil reservoir. Although this mobile C0₂ moves vertically through the oil reservoir, it may be trapped at the bottom of the caprock.

[0034] Generally, after C0₂ 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 C0₂ by dissolution in ambient reservoir fluids such as brine and oil. The amount of C0₂ stored by solubility trapping can be estimated with calibrated solubility algorithms.

[0035] Fig. 2 is a graph comparing C0₂ solubility in crude oil to C0₂ solubility in pure water. C0₂ solubility data for crude oil were taken from compilation data by previous researchers, whose data included C0₂ 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 C0₂ solubility in crude oil is about 30 times greater than that in pure water. This discrepancy will be even greater when comparing C0₂ solubility in crude oil to C0₂ solubility in brine, as it is generally known that C0₂ solubility in brine decreases with salt concentration, and C0₂ is more soluble in pure water than in brine. Overall, the potential capacity of C0₂ solubility trapping in oil reservoirs is more than 30 times greater than that for brine formations.

[0036] Buoyancy-driven migration is governed by contrasts of fluid densities. C0₂ 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 C0₂ migration in brine formations and oil reservoirs, the fluid densities of C0₂, 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 C0_2l crude oil, and brine (H₂0-NaCI) were, respectively, calculated from the representative equations-of-states.

[0037] C0₂ 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 C0₂ 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 C0_2l 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 C0₂ and light oil (50 "API; 780 kg/m³) is about 100 kg/m³ at 15 MPa and between C0₂ and heavy oil (30 °API; 876 kg/m³) is about 200 kg/m³.

[0038] A brine density with about 159,000 ppm concentration corresponds to a density of about 1100 kg/m³. Therefore, the approximate density contrast between C0₂ and brine is about 450 kg/m³ at 15 MPa. This comparison suggests that the density contrast between C0₂ and surrounding fluids is about 2.25-4.5 times greater in brine formations than in oil reservoirs. Correspondingly, buoyancy-driven C0₂ migration tends to be 2.25-4.5 times greater in brine formations.

[0039] Density of C0₂-dissolved brine becomes greater as more C0₂ dissolves. Other researchers suggest that the density of C0₂-dissolved brine can be as much as 2-3% greater than surrounding brine. Consequently, C0₂-dissolved brine will sink and create density instability resulting in convective transport mixing after several hundred years. In oil reservoirs, dissolution of C0₂ in oil increases the density of C0₂-dissolved oil, which causes such gravitation segregation.

[0040] Because gravitational segregation occurs due to the density contrast between C0₂-dissolved fluids and surrounding fluids, the incremental density contrast as C0₂ dissolves may be evaluated. To evaluate this aspect, densities of both C0₂-dissolved brine and oil were compared (Fig. 4). The densities of C0₂-dissolved oil are plotted in Fig. 4a, showing the evolution of densities as a function of pressure, temperature, and C0₂ 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_οΜ = 15 kg/m³) as C0₂ 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_οΗ = 10.5 kg/m³) for the same increase of C0₂ mole fraction.

[0041] Several correlation algorithms are available for the density of C0₂-dissolved brine. Among these algorithms, an equation-of-state was adapted to calculate the density of C0₂-dissolved brine (Fig. 4b). Density of C0₂-dissolved brine (circle symbol) is plotted as a function of pressure at 18.33 °C, 0.01 NaCI mole fraction, and 0.01 C0₂ mole fraction. As pressure increases from 2.7 to 20 MPa, the density of C0₂-dissolved brine increases from 1029 to 1037 kg/m³ (Ap _rilie = 7 kg/m³). When C0₂ mole fraction only increases from 0.01 to 0.02 (circle vs. rectangle symbols), the densities of C0₂-dissolved brine systematically increase with an approximate density contrast of 6 kg/m³. Similar to the effect of C0₂ dissolution on oil density (Fig. 4a), the density of C0₂-dissolved brine also increases with C0₂ dissolution (Fig. 4b).

[0042] To investigate temperature effects on the density of COr-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 C0₂-dissolved brine increases NaCI mass fraction from 0.01 to 0.02 (diamond vs. triangle symbols in Fig. 4b). Compared to the density of C0₂-dissolved brine with 0.01 NaCI mole fraction, the density of 0.02 NaCI 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 C0₂ dissolution are not significant. The density contrast between non-C0₂-bearing reservoir fluids (oil and brine) and C0₂-dissolved counterparts is about 7-15 kg/m³, which is significantly smaller than the density contrasts between supercritical-phase C0₂ and ambient reservoir fluids C0₂-oil: 100 kg/m³, C0₂-brine: 450 kg/m³. Consequently, gravitational segregation (sinking) of C0₂-dissolved fluids will be much slower than buoyancy-driven (vertical) migration of supercritical-phase C0₂.

[0043] Greater contrasts of density between C0₂ and ambient reservoir fluids enhance buoyancy-driven C0₂ migration. However, greater contrasts of viscosity between C0₂ and reservoir fluids possibly prohibit vertical C0₂ migration and may induce viscous fingering at C0₂ displacement fronts. In Fig. 5 fluid viscosities of C0₂, brine, and crude oil are compared to evaluate the potential retardation of buoyancy-driven C0₂ migration. Viscosities of C0₂, 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. [0044] 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 C0₂ 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.

[0045] The overall range of pure water viscosity is from about 0.7-1 mPa s. With greater salinity (0.2 NaCI 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 C0₂ viscosity is shown to be about 0.1 mPa s, indicating that C0₂ is the most mobile fluid and its viscosity variation with temperature is the smallest among these reservoir fluids.

[0046] In general, this comparison indicates that the contrasts of viscosities between C0₂ and crude oil are significantly greater than that between C0₂ and brine. Therefore, viscosity effects on buoyancy-driven C0₂ migration will be greater in oil reservoirs than those effects in brine formations. In addition, displacement fronts of C0₂ plumes will likely exhibit significant viscosity fingering in C0₂-crude oil systems.

[0047] Additionally, the viscosity of crude oil is significantly reduced as C0₂ dissolves in oil (Fig. 6a). For example, when C0₂ mole fraction increases from 0.46 to 0.99, the viscosity of C0₂-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 C0₂ dissolution is significant and its magnitude, which is strongly dependent on intrinsic oil density (API gravity), ranges from about 200 to 5000 mPa s.

[0048] The viscosity of 0.02 molality NaCI brine without dissolved C0₂ at 30 °C (circle symbol) is about 0.82 mPa s and does not vary with pressure (Fig. 6b). To investigate the effect of C0₂ dissolution on brine viscosity, the viscosity of C0₂-dissolved brine was plotted with 0.02 C0₂ mole fraction and 0.02 NaCI mole fraction at 30 °C (diamond symbol). This comparison (circle vs. diamond symbols in Fig. 6b) shows that 0.02 mole fraction of C0₂ 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 C0₂-dissolved brine decreases from 0.92 to 0.6 mPa s (diamond vs. rectangle symbols in Fig. 6b). [0049] This comparison suggests that viscosity contrasts between C0₂-dissolved oil and straight (no C0₂) crude oil vary more than hundreds of mPa s (Fig. 6a) and that between C0₂-dissolved brine and straight (no C0₂) brine is about 0.09 mPa s (Fig. 6b). Since the viscosity of C0₂-dissolved oil is several hundreds times greater than that of C0₂-dissolved brine, gravitational segregation will potentially be retarded more in oil reservoirs.

[0050] The tendency of buoyancy-driven C0₂ 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 C0₂ plume to reach quickly below a low permeability caprock and consequently decrease the sweep efficiency of oil during C0₂ enhanced oil recovery. In C0₂ sequestration, greater gravity forces accelerate vertical C0₂ migration and, hence, increase the probability that vertically mobile C0₂ may come into contact with faults or other leakage pathways, especially as it contacts caprock.

[0051] In this study, N of C0₂ was compared in brine formations and oil reservoirs to quantify the degree of gravity-driven C0₂ migration. N is determined from ^∞ι" where f represents either brine or oil, k_x is the horizontal permeability, p_Co2 is the density of C0₂, g is gravity, kr_C02 is the relative permeability of C0₂, ^uco2 is the viscosity of C0₂, and v is the velocity of C0₂. For solely investigating the effect of thermodynamic properties, it was assumed that k_xkr_C02 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 C0₂ migration will be smaller in the oil reservoirs than in saline formations.

[0052] Both plots show that an increase in pressure causes a decrease in N, which indicates that density contrasts between C0₂ 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 C0₂ injection into targeted formations and reservoirs with high pressure and low temperature conditions will help minimize buoyancy-driven C0₂ migration, and suggests that C0₂ injection into high temperature systems will possibly cause significant buoyancy-driven migration.

[0053] Finally, examination of this data reveals that a near-perfect seal condition exists in oil reservoirs where the C0₂ plume is not buoyant because the C0₂ 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 C0₂ is greater than that of crude oil. In this zone, no buoyancy- driven C0₂ migration occurs and, therefore, sequestered C0₂ will migrate downward because the C0₂ density is greater than surrounding fluids. This zone also appears in Fig. 3, showing C0₂ density values for different API gravity oils as a function of pressure. In particular, at 54.5 °C, C0₂ 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 C0₂ density becomes greater than oil density, increases.

[0054] Because Fig. 3 is plotted for a fixed temperature, zones were identified where C0₂ 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 C0_2l whereas the lighter areas illustrate the temperatures and pressures where C0₂ is more dense than oil. Reservoirs with lighter oil (Fig. 8c) have a greater range of temperatures and pressures where C0₂ is more dense, and as such, reservoirs with lighter oil are more capable than reservoirs with heavier oil at reducing buoyancy-driven C0₂ migration.

[0055] It may be advantageous to sequester C0₂ as a supercritical fluid. C0₂ 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 C0₂ 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 C0₂ 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 C0₂ migration, much like a caprock would. As such, the methods disclosed herein may include sequestering C0₂ 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 C0₂ 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 C0₂ 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.

[0056] The tendency of buoyancy-driven C0₂ migration can be quantified with N, In a similar manner, the tendency of C0₂ mobility, where fluids compete with each other, can be estimated with viscosity ratio (M), which is determined from Haa . 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_C02/ r_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 C0₂ mobility will exist in brine formation. Since buoyancy is a major driving force on C0₂ migration in these conditions, C0₂ plumes in brine formations will migrate farther vertically than C0₂ plumes in oil reservoirs.

[0057] For C0₂ 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 C0₂ mobility occur in lower temperature areas (20-30 °C). Thus, overall C0₂ migration in the oil reservoir will be inhibited more than C0₂ in brine formations without oil present.

[0058] 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 C0₂. Alternatively or additionally, the pump may be operatively connected to one or more tanks of C0₂, such as a tank of compressed C0₂. For example, the pump may be removably attachable to one or more tanks of C0₂. The C0₂may be a gas, a liquid, a supercritical fluid, or a mixture thereof, when the carbon dioxide is injected into the saline formation.

[0059] 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 C0₂ differs from those used for enhanced oil recovery in that the C0₂ 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 C0₂ 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.

[0060] Additionally, because the C0₂ 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 C0₂. For example, it would be desirable to know whether a large amount of C0₂ were to cross the oil-water contact layer, or escape the caprock. As such, the presently disclosed systems for sequestering C0₂ also may include a monitoring system configured to monitor the amount of C0₂ 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 C0₂ 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 C0₂ 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. [0061] The monitoring system may be configured to produce an alert when the amount of C0₂ 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 C0₂ in fluids surrounding a particular sensor exceeds a value of about 0.001% C0₂, about 0.0025% C0₂, about 0.005% C0_2l about 0.0075% C0₂, and/or about 0.01 % C0₂, among other suitable values. Likewise, the monitoring system may be configured to produce an alert when the amount of C0₂ in fluids surrounding a particular sensor exceeds a value of about 300 ppm C0₂, about 400 ppm C0₂, about 500 ppm C0₂, about 600 ppm C0₂, and/or about 700 ppm C0₂, among other suitable values. Alternatively or additionally, the monitoring station may be configured to produce an alert when the amount of C0₂ 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 C0₂ 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.

[0062] 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.

[0063] 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.

[0064] 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

[0065] Example 1 - Comparison of Simulated C0₂ Sequestration in a Saline Formation and Simulated C0₂ Sequestration in an Oil Reserve Below a Saline Formation.

[0066] 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.

[0067] The model shown in Fig. 10, and the parameters shown in Table 1 below, were used to simulate what likely would occur after injecting C0₂ 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 C0₂ were estimated to be 1 101 , 801 , and 650 kg/m³, respectively. In addition, the viscosities of brine, oil, and C0₂ were estimated to be 0.895, 2.466, and 0.0594 mPa s, respectively. The C0₂ 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 C0₂ migration between brine and oil, gravity numbers (N) and viscosity ratios ( ) 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 C0₂ plume reaches the bottom of the oil reservoir, its migration is expected to slow.

Table 1. Model arameters of numerical model describin CSBOR scheme in Fi . 10.

[0068] Fig. 12 shows generic three-phase relative permeability curves, implemented in the numerical model of Fig. 10, for (a) brine and oil, and (b) C0₂ + brine and C0₂ + 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 C0₂ 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 C0₂ saturation and irreducible C0₂ saturation are assumed to be 0.1. For the sake of simplicity, and to isolate the fundamental behavior of C0₂ migration in a two-fluids zone, hysteresis was not accounted for. Because of the non- hysteretic condition, C0₂ residual trapping occurs in this model only when C0₂ saturation is smaller than the residual C0₂ 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 C0₂ migration.

[0069] The simulation is built to investigate buoyancy-driven migration of injected C0₂ several decades after C0₂ injection has ceased. At this time, the effect of injection-induced pressure will disappear and the main cause of C0₂ vertical migration will be due to the density contrast between C0₂ and surrounding fluids. To investigate buoyancy-driven C0₂ migration only, 99% of initial C0₂ 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.

[0070] Figs. 13a-c simulate what likely would happen after injecting C0₂ below the OWC layer at 120, 230 and 635 days, respectively. Fig. 13a shows that, during the first 120 days, the C0₂ plume would migrate about 10 m due to the density contrast between C0₂ and brine. The OWC layer would be slightly distorted by the pressure of the approaching C0₂ plume. At this stage, much of the C0₂ would still be mobile. Fig. 13b shows that, after 230 days, the C0₂ plume would have reached the OWC layer. The C0₂ plume would spread out widely directly below the OWC layer, and its saturation would be increased. The accumulation of C0₂ directly below the OWC layer suggests that the oil reservoir would act as a physical barrier. At the same time, the saturation of the C0₂ plume where it immediately contacts the oil reservoir would be significantly decreased, indicating that C0₂ in the upper part of plume would be dissolving into the oil reservoir. Some C0₂ would be trapped as solubilized C0₂ as the plume migrates through the brine formation. In addition, both mobile and residual C0₂ 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, C0₂ would be trapped as both residual and dissolved C0₂ in the brine below the OWC layer. The rest of the C0₂ would be trapped in the oil reservoir. Notably, none of the C0₂ would reach the caprock.

[0071] Figs. 13d— f simulate what likely would happen after injecting C0₂ 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 C0₂ in brine only is identical to the migration pattern shown in Fig. 13a. However, Fig. 13e shows that, after 230 days, C0₂ 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 C0₂ is trapped as residual C0₂, but most of it migrates vertically through the brine formation.

[0072] The comparisons shown in Fig. 13 indicate that CSBOR significantly reduces the amount of mobile C0₂ and buoyancy-driven C0₂ migration as compared to C0₂ injection into non-oil-bearing saline formations.

[0073] Example 2 - Systems for sequestering carbon dioxide

[0074] Oil-bearing formations comprising a saline aquifer beneath an oil reservoir, similar to the formation shown in Fig. 14, may be utilized for sequestering C0₂. 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 C0₂ 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 C0₂ 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 10m below the OWC layer, such as greater than 100m, 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, TX) capable of receiving compressed gas from a pump (e.g., a booster pump as made by Fabrication Technologies, Casper, WY) capable of pushing compressed C0₂ 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 C0₂ will be compressed as it passes through a regional pipeline carrying compressed C0₂. For example, the C0₂ may be injected into the saline formation at a pressure greater than about 10 MPa, such as about 20 MPa.

[0075] In order to verify that the C0₂ is being delivered to the aquifer, and in order to monitor whether the C0₂ is staying sequestered, the system for sequestering C0₂ may include a monitoring system configured to monitor the amount of C0₂ in a portion of the saline formation, a portion of the oil reservoir, or both, such as is illustrated in Fig. 1 . 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 C0₂ in the environment surrounding the sensor. For example, each sensor may be configured to measure at least one of the temperature, salinity, H, pressure, and/or C0₂ 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.

[0076] The monitoring system may be configured to produce an alert when the amount of C0₂ 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 C0₂ in fluids surrounding a particular sensor exceeds a value of about 0.001% C0₂, about 0.0025% C0₂, about 0.005% C0₂, about 0.0075% C0₂, and/or about 0.01 % C0₂, among other suitable values. Likewise, the monitoring system may be configured to produce an alert when the amount of C0₂ in fluids surrounding a particular sensor exceeds a value of about 300 ppm C0₂, about 400 ppm C0₂, about 500 ppm C0₂, about 600 ppm C0₂, and/or about 700 ppm C0_2l among other suitable values. Alternatively or additionally, the monitoring station may be configured to produce an alert when the amount of C0₂ 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 C0₂ 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 any of claims 1-3, 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 any of claims 1-5, 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 any of claims 1-8, 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 1 1 , further comprising a pipeline containing the C0₂, wherein the pump is in fluid communication with the pipeline to draw the C0₂ from the pipeline.

13. The system of claim 1 1 , further comprising a tank containing C0₂, wherein the pump is in fluid communication with the tank to draw the C0₂ from the tank

14. The system of any of claims 1 1-13, further comprising a monitoring system configured to monitor the amount of C0₂ 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 C0₂ in the portion of the saline formation or the portion of the oil reservoir exceeds a predetermined amount.

16. The system of any of claims 14 or 15, 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 C0₂ 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 C0₂ concentration of fluids in contact with the sensor.

18. The system of any of claims 16 or 17, 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 any of claims 16-18, 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 C0₂ 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.