CO2 EOR and Sequestration

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CO2 EOR & Sequestration

In 2010, 114 CO2-EOR projects in the U.S. were producing a total of 281,000 barrels of oil per day.

There are basically two types of processes involving CO2 injection for enhanced oil recovery: miscible and immiscible. Early interest was mostly focused on immiscible displacement, carbonated waterflooding and well stimulation. Emphasis now centers primarily on miscible displacement. Miscible CO2 flooding is best suited to light and medium gravity crude oils and the immiscible process may apply to heavy oils.

Historically, wide-scale application of CO2-EOR has been constrained by lack of nearby supplies of CO2. In recent years, however, there has been a convergence of discussions regarding CO2-EOR and Carbon Capture and Storage (CCS). Recent, novel pilot projects and laboratory studies have demonstrated that injection of industrial CO2 emissions into either oil or gas reservoirs can result in incremental recovery of these hydrocarbons with simultaneous geological storage of the CO2.

The new paradigm is that CCS needs CO2-EOR to help ensure economic viability of CCS, and CO2-EOR needs CCS to ensure adequate CO2 supplies for growth of oil production from this technology.

Properties of CO2

Depending on temperature and pressure, carbon dioxide can exist as a vapor or gas, liquid, solid, and in the supercritical state. It has a critical point of 31oC (88oF) and 6.9 MPa (1087 psig). At standard conditions it is 1 ½ times as heavy as air.

Oil and gas operators generally handle CO2 in its supercritical state, which is above the critical point. In general, supercritical fluids behave like a liquid with respect to density and a gas with respect to viscosity. For this reason the most efficient way of transporting CO2 by pipeline is at supercritical conditions in the vicinity of the critical point.
 
CO2 is sold by weight or volume, and a convenient conversion factor is that one ton of CO2 contains 17.25 Mcf at standard conditions.


Recovery Mechanisms

Oil recovery by CO2-EOR relies on a number of mechanisms related to the phase behaviour of CO2-crude oil mixtures.figure1

Strongly dependent on reservoir temperature, pressure, and crude oil composition, the dominant recovery mechanism falls into one of five regions as shown in Figure 1:

Region 1: Low Pressure applications

At reservoir pressures below 1,000 psia, the major effects of CO2injection on oil recovery are due to the solubility of CO2 in the crude oil. Besides an increase in reservoir pressure, the injection of CO2:
  • Swells the oil. CO2 is highly soluble in crude oils. Depending on the pressure, temperature and oil composition, CO2 will dissolve in oil and increase its volume from 10 to 100 percent. This swelling is important for two reasons. First, the residual oil behind the displacement front will be in the swollen state, have a higher shrinkage factor than the original oil, and consequently will be less in terms of stock-tank barrels. Second, swollen oil droplets will force water out of pore spaces creating a drainage rather than an imbibition process for water-wet systems. Drainage oil relative permeabilities are higher than their imbibition counterparts, creating a more favourable oil flow environment.
  • Reduces oil viscosity significantly. As CO2 saturates a crude oil, a large reduction in the viscosity of the oil occurs. This reduction can yield viscosities one-tenth to one-hundredth of the original oil viscosity.
  • Contributes internal solution gas drive. After termination of the injection phase of CO2-EOR, CO2 will come out of solution and continue to drive oil into the producing wellbores. This mechanism of blow down recovery is similar to solution gas drive during primary depletion. Up to 18% of the oil can be recovered by CO2 solution gas drive (Klins, 1984).
  • Increases injectivity. CO2–water mixtures are slightly acidic and react accordingly with the formation matrix. In shales, carbonic acid stabilizes clays due to a reduction in pH. In carbonates, injectivity is improved by partially dissolving the reservoir rock. Note however, that injectivity may also be reduced due to the liberation of unreacted fines that may plug the pore channels.

Region II: Intermediate Pressure, High Temperature (>122oF) applications

In this region, supplemental recovery mechanisms come into play. Instead of swelling the oil, the CO2 begins to vaporize the oil in increasing amounts with increasing pressure. This vaporization into a CO2-rich vapour phase results in a sizeable increase in oil recovery, and occurs when the density of CO2 is at least 0.25 to 0.35 gm/cm3. Hydrocarbons up to C30 may be vaporized.

Region III: Intermediate Pressure, Low Temperature (<122oF) applications

In this region, rather than vaporize crude oil, the CO2 extracts the crudes lower ends forming CO2-rich liquid mixtures, causing multiple liquid phases to exist in equilibrium. In some instances, a solid phase (asphaltenes) may appear causing loss of permeability. One should thoroughly examine the possibility for asphaltenes precipitation in the laboratory prior to field implementation.

Region IV: High Pressure applications

At high reservoir pressures (>2000 to 3000 psia), CO2 may vaporize significant quantities of crude oil so rapidly that multiple contact miscibility occurs over a very short reservoir distance.

Region V: High Pressure, Low Temperature (Liquid) applications

Little work has been done on liquid CO2 applications

 

Finally, it is important to note that:

  • The lines that divide the regions are generalizations that will vary from oil to oil. Heavier oils will shift these divisions upward. Since CO2 has a critical temperature of 87oF, most reservoirs are excluded from having liquid CO2 at the sandface (Region V).

  • If CO2 injection is being implemented as a tertiary process then it is essential that the displacement be performed miscibly.

Minimum Miscibility Pressure (MMP) and Its Estimation

Below some minimum pressure, CO2 and oil will no longer be miscible. As the temperature increases (CO2 density decreases) or as the oil density increases (light hydrocarbon fraction decreases), the minimum pressure needed to attain oil/CO2 miscibility increases. 

Figure 2 & Figure 3 CO2 EOR and Sequestration

Figure 2 presents a useful procedure (Cronquist correlation) for estimating the minimum miscibility pressure as a function of temperature and molecular weight of the oil’s C5+ fraction. Mathematically, this correlation is given by:

MMP = 15.988*T (0.744206+0.0011038*MW C5+)

where T is in oF and MMP is in psi.

The molecular weight of the C5+ fraction can be estimated from Figure 3. Table 1 provides another quick method of estimating MMP.

Table 1 CO2 EOR and Sequestration

Note:

  • Although correlations are helpful as a screening tool, the best way of determining pressure needed for miscibility is by laboratory tests in which CO2 displaces reservoir crude from sand-packed tubes.
  • If the predicted MMP is less than that of the saturation pressure of the particular crude being considered for CO2 flooding, the MMP should be taken equal to the saturation pressure so that free gas saturation is avoided (Mungan, 1981).
  • Depleted low-pressured reservoirs will likely require re-pressurization by water injection prior to any CO2 flood. However old pools should not be subjected to high injection pressures that may cause casing or cement failure.

Application

Process Description

Figure 4 CO2 EOR and Sequestration

In horizontal displacement, mobility control is very important. Because the viscosity of CO2 at reservoir conditions is much lower than that of most oils, viscous instability will limit the sweep efficiency of the displacement and, therefore, oil recovery. In addition, reservoir rock is heterogeneous, exhibiting zones of high permeability in close proximity to those of low permeability.

Reservoir heterogeneity and the adverse effects of CO2 viscosity must be contended with to optimize oil recovery. Two basic strategies have been developed by the petroleum to mitigate these effects:

  • 1. Alternate injection cycles of CO2 and water (water alternating gas or WAG process). This technique forms sequential banks of fluids in the reservoir rock: oil, CO2 and water, that migrate from the injection to the production wells (see Figure 4). Reservoir management may include the following steps:
    • Ensure reservoir pressure exceeds the MMP in all areas of the field.
    • Ensure fluid injection rates balance (or exceed) fluid withdrawal rates at both pattern and field levels.
    • Start WAG process when first breakthrough of CO2 is observed.
    • Reduce CO2 injection and increase the WAG ratio as the flood matures.
    • Continually optimize the WAG process at a pattern level.

Note: In low permeability reservoirs, alternate injection of CO2 and water may seriously reduce injection rate.

2. Addition of chemical agents, such as: ethoxylated and/or unethoxylated species, fluroacrylate-styrene copolymers, lignosulfonates, etc, to CO2 to form stable foams that increase its viscosity without compromising its efficacy (Meyer, 2007).

It is interesting to note that because of high CO2 costs and lack of process control, older CO2-EOR projects injected relatively small quantities of CO2, typically 0.20-0.4 hydrocarbon pore volumes. Today, up to 1.5 pore volumes are being planned to improve sweep efficiency and mobilize more residual oil.

Figure 5 is a plot of areal sweep efficiency, EA versus mobility ration, M, for various displaceable reservoir pore volumes, VpD, injected. Some useful observations can be made here:

  • Reservoir sweep efficiency at CO2 breakthrough (lower boundary of the plot) increases as the mobility ratio decreases. This shows the importance of WAG and viscosity enhancers for mobility control.
  • For any given mobility ratio, sweep efficiency continues to improve (i.e. addition oil is recovered) after breakthrough, as more pore volumes of CO2 are injected. It is expected, therefore, that provisions must be made for recycling of produced CO2.

Dipping Reservoirs and Vertical Floods

In applications involving reservoirs with significant dip or vertical downward displacement (refer to Figure 6), gravity drainage is important. Fluids are injected sequentially: CO2 would be followed by a lighter chase gas to maximize the advantage of gravity segregation and to minimize viscous and gravity fingering.

Well Spacing

Optimal well spacing is determined from reservoir engineering and economic considerations.

In vertical floods the approach would be to use the minimum number of injection and production wells that would permit handling the necessary volumes of fluids and at the same time minimize coning and sandwich losses.

In horizontal floods, the distance from the injection to production wells is an important consideration. The greater this distance, the longer will be the mixing length between the CO2 solvent and the reservoir oil, which increases the CO2 requirements (IOCC, 1993). Note that where new wells are difficult or expensive to drill and complete, small well spacings would be hard to justify without favourable incentives.

Cyclic Injection

Figure 7 CO2 EOR and Sequestration

CO2 may also be injected in a cyclic fashion (see Figure 7). Miller et al. (1998) reported on the successful application of cyclic CO2 injection ("Huff and Puff") in the Big Sinking Field of eastern Kentucky. The reservoir is a naturally-fractured carbonate rock containing 36oAPI oil.

The process was initiated in 1986, and was used continuously until 1994, with 390 treatments on 240 wells. A total of 12,200 tons of liquid carbon dioxide resulted in additional recovery of 180,000 barrels of oil. This corresponds to an efficiency of 1.2 Mcf CO2 per barrel of incremental oil.

Cyclic CO2 injection does not require a high oil saturation to be effective and appears to be well suited to fields with high water-cuts (Getz, 2001).

Screening Criteria

The CO2 miscible process is applicable to a high percentage of reservoirs. As a first pass or initial screening, the following criteria may be considered:

  • Crude oils with gravities above 22 oAPI,
  • Pressures starting at 1,500 psig and ranging upward, with 6,000 psig being a practical upper limit.
  • Prospective reservoirs must have sufficient depth and reservoir seal that they can be operated above the pressure needed for miscible displacement without fracturing the formation.
  • Thin pay zones underlain by large aquifers, or reservoirs with a free gas cap should be avoided.
  • Low permeability reservoirs containing highly asphaltic crudes are not good candidates, as severe permeability damage may result from deposition of asphaltenes upon contact of the crude oil with CO2.

Challenges

Corrosion

Carbon dioxide in the presence of water forms carbonic acid which is highly corrosive. The carbon dioxide should be dehydrated and compressed before it is transported. Special metal alloys and coatings for facilities are needed. Where alternating injection of CO2 and water is to be implemented, dual injection systems are required: one for CO2 and the other for water. In addition to these precautions, a good corrosion inhibitor program should be carried out in the field.

Asphaltene Precipitation

Asphaltene deposition could be a serious problem if the crude oil is highly asphaltic and the reservoir permeability is low. Laboratory core displacement and permeability tests will readily show whether or not this problem will be serious.

Produced CO2 Handling

The best method for handling the produced CO2 is recycling/reinjection so as to lower the volume of the CO2 to be purchased. The produced CO2 can either be separated from the associated gases or injected without any processing.

Availability of CO2

Availability of CO2 plays an important role in the selection of CO2 EOR. Preferably, the target reservoir should be located as close as possible to the source of v to minimize gathering and transportation costs.

Populated Areas

Carbon dioxide has a density greater than that of air. As such, fugitive emissions from CO2-EOR projects in low lying areas surrounded by mountains, could potentially build to levels harmful to humans. Such an event would be lethal if the CO2 contained any H2S at all.

Economic Considerations

At minimum, one barrel of CO2 is needed to replace one barrel oil, both at reservoir conditions. Injection requirement above this minimum can be expected because of CO2 dissolving in the injected water and reservoir oil, and possibly to non-productive zones.

Table 2 shows the volume of CO2 at standard conditions needed to fill one barrel of reservoir pore volume at 100oF and 160oF and for different pressures.

Table 2 CO2 EOR and Sequestration

For the first 10 years of field operation, CO2 purchases are the largest expense in CO2 floods, representing as much as 68% of total costs (Meyer, 2007). The cost of CO2 includes its base price, plus transportation and compression to the desired pressure. In most cases transportation costs are the largest.

Project incremental recoveries for field-scale miscible CO2-EOR floods range from 7 to 23% of the original oil in place (OOIP), and the net purchased amount of CO2 required is estimated to be between 2.5 to 11 MCF/STB of incremental recovery, with an average value of 6 - 7 MCF/STB.

Actual incremental recovery for immiscible floods has been between 9 to 19% of the OOIP, with net CO2 requirements of 5 - 12 MCF/STB (Meyer, 2007).

CO2 and Flue Gas Sequestration Opportunities

Geological sequestration of CO2 / Flue gas through enhanced oil and gas recovery can be a profitable opportunity to achieve significant greenhouse gas emission reductions:
  • Oil and gas reservoirs are potentially good storage sites since they are known to have geologically retained hydrocarbons for millions of years.
  • The technology and operational practices used by the oil and gas industry in handling, transporting, and injecting CO2(especially in the area of corrosion protection) is a valuable resource in planning CCS projects.
  • Injection of industrial CO2 emissions into either oil or gas reservoirs can result in incremental recovery of these hydrocarbons.

The main challenges would be:

  • Cost of capture, transportation and injection.
  • Unfavourable reservoir architecture and well configuration causing poor CO2 storage capacity and hydrocarbon sweep efficiency due to early CO2 breakthrough.

Reservoir situations offering high sequestration potential and incremental recovery would include:

  • Thick formations that allow gravity-stable injection, e.g. the pinnacle reefs in Alberta: gravity naturally works to retain the CO2 in the reservoir.
  • Injection into depleted gas reservoirs for enhanced gas recovery: no mobility or override related issues.
  • Injection into SAGD wells during the wind-down operational phase:
    • the formations are at least 15 m thick,
    • vertical permeability is high, and
    • the horizontal wells are situated at the base of the base of the pay.

References

Advanced Resources International (ARI), Basin Oriented Strategies for CO2 Enhanced Oil Recovery, Report prepared for the U.S. DOE, (February 2006).

Getz, B.S., “Application of Cyclic CO2 Methods in an Over-Mature Miscible CO2 Pilot Project – West Mallalieu Field, Lincoln County, MS”, Final Technical Report, Prepared for the U.S. DOE, J.P. Oil Company Inc., September, 2001.

Herbeck, E.F., Heintz, R.C. and Hastings, J.R.: “Fundamentals of Tertiary Oil Recovery – Carbon Dioxide Miscible Process”, Petroleum Engineer, (May 1976), pp. 114-120.

Interstate Oil Compact Commission (IOCC), Improved Oil recovery, Oklahoma City, OK, (1993).

Klins, M.A., Carbon Dioxide Flooding – Basic Mechanisms and Project Design, IHRDC, Boston, (1984).

Meyer, J.P., “Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well Technology”, Report Prepared for the American Petroleum Institute, Contek Solutions, (2007).

Miller, B.J., Bretagne G.P., Hamilton-Smith, T.: “Field Case: Cyclic Gas Recovery for Light Oil-Using Carbon Dioxide/Nitrogen/Natural Gas”, SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 27-30, 1998.

Mungan, N.: “Carbon Dioxide Flooding – Fundamentals”, Jour. of Can. Pet. Tech. (1981), Vol. 20, No. 1, pp. 87 – 92.

National Petroleum Council (NPC), Enhanced Oil Recovery, Washington, D.C. (Dec. 1976).