Coupled CO2 Enhanced Oil Recovery and Sequestration in China's

Article pubs.acs.org/EF

Coupled CO2 Enhanced Oil Recovery and Sequestration in China’s Demonstration Project: Case Study and Parameter Optimization Kun Su,*,† Xinwei Liao,† Xiaoliang Zhao,† and Hui Zhang‡ †

Petroleum Engineering Department, China University of Petroleum, Beijing 102249, People’s Republic of China Exploration and Development Research Institute of Jilin Oilfield, PetroChina, Songyuan 138000, People’s Republic of China

‡

ABSTRACT: Reservoir stimulation by carbon dioxide (CO2) flooding can bring extra oil production because of its unique advantages of higher displacing efficiency and lower injection pressure compared to water flooding. Also, greenhouse gas control has been the focus of worldwide attention in recent decades, and CO2 injection into reservoirs has been regarded as a favorable method of achieving sequestration. Therefore, coupled enhanced oil recovery (EOR) and sequestration becomes a cost-effective and environmentally safe method, which is feasible for developing countries, especially China. In this paper, China’s first field-scale reservoir demonstration project is introduced to evaluate its performance with respect to both oil recovery and carbon sequestration. Also, given that injected CO2 tends to immaturely break through toward production wells in reservoirs, parameters of recycled gas injection scenarios were screened and then optimized by experimentations as well as by a new optimizing method. Both of these approaches could contribute to the research and methodology required for scaling up programs in China.

1. INTRODUCTION Carbon sequestration in oil reservoirs is a proven safe and effective approach because of its natural advantages.1 Given that formations can seal hydrocarbons for millions of years, the distribution of a rock cap above is also believed to prevent carbon leakage in the long-term future, which is critical for an ideal CO2 sequestration site. Although aquifer formation is expected to be a larger potential reservoir for carbon sequestration, its less benefit than CO2 enhanced oil recovery (CO2 EOR) activities have impeded its development in present-day China. Therefore, in the oilfield sector, CO2 EOR and sequestration will draw more attention for its economic advantages. China is well-qualified in many respects to undertake CO2 EOR and storage activities. (1) With respect to carbon sources, it is widely believed that carbon emissions in China will continue to rise, even though fossil fuel consumption is predicted to be reduced in the near future2 (see Figure 1). Also, many CO2-rich

which oil reservoirs are distributed on a large scale, and thorough geological information has been obtained during the long periods of their exploitation. (3) With respect to switching opportunity, given that reservoirs by water flooding have seen high water cut,3,4 CO2 flooding technology has been regarded as a suitable method for sustainable development, just as it has been in the U.S.A. and many European countries.5,6 All of these reasons contributed to the launching of a pilot program in China. Before the wider application of switching to CO2 flooding in China, the first field-scale pilot program, H59 Block, was launched. This was funded by PetroChina and supported by the government. This pilot program includes flooding/sequestration mechanism studies, surface engineering, and laboratory research. Developments recognized during this program will facilitate the scaling-up of deployment of similar projects in other target oil fields. In this paper, the production history of this block is first overviewed to provide field experience for similar projects. Then, parameters in the recycled gas scenario, including the gas/oil ratio (GOR) constraint and gas components for re-injection are chosen and optimized to maximize oil recovery and CO2 sequestration (see Figure 2).

2. PROJECT OVERVIEW 2.1. Geological Configuration. The pilot field is located in the southern part of the Song Liao Basin, which is isolated by centripetal faults in its western and eastern parts, respectively (see Figure 3b). As a stable delta deposit, the sandstone thickness of this area is stable, with little variation. The testing block is stratified into 40 layers of porous and dense zones that are not continuous. Among them, four main layers are chosen for oil production. Around these four layers, which on average are 2 m thick, mudstones are distributed above

Figure 1. Carbon emission trends in China.

gas reservoirs can provide a source of gas (see Figure 3a), which can significantly reduce the cost of gas and its transport. (2) With respect to project sites, China is among several countries in © 2012 American Chemical Society

Received: July 12, 2012 Revised: December 17, 2012 Published: December 26, 2012 378

dx.doi.org/10.1021/ef301708u | Energy Fuels 2013, 27, 378−386

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Figure 2. Illustration of CO2 EOR and sequestration operation.7.

Figure 3. Location of the H59 Block and well groups. ⎧ VE = S /K̅ ⎪ n ⎪ ∑i = 1 (K i − K̅ )2 ⎪ ⎪S = ⎨ (n − 1) ⎪ n ⎪ ∑ (hiK i) K̅ = i = 1n ⎪ ⎪ ∑i = 1 hi ⎩

and below, guaranteeing the safety of simultaneous CO2 sequestration. Inside of them, isolated interbeds are developed so that the reservoir properties are poor in porosity by 13% and permeability by 3 mD. These characteristics lead to much higher water injection pressures being required with associated poor benefits, which will be discussed later. The H59 Block (see Figure 3a) covers 3.1 km2, and the oil-bearing layers are 2267−2490 m deep and 2−4 m thick. The reservoir oil is 47° in American Petroleum Institute (API) gravity and 3.97 cP in viscosity under reservoir conditions. The dissolved GOR is 36 m3/m3 (under standard conditions), and the bubbling pressure of the crude oil is 7.31 MPa. Most of the 40 layers coexist as oil and water; thus, their initial oil saturation is lower than 50% (45% on average), which is classified as relatively low. Poor layers with relatively lower oil saturation in them are frequently present. To improve the efficiency of injected solvents, these layers are beyond the perforation range, especially for CO2 injection wells. Among all layers vertically, the four main layers (indexed as 7, 12, 14, and 15) chosen in the target developing area contribute to 78% of the original oil in place (OOIP) in this area (see Figure 4b). As interpreted by well logging, the cap rocks above are stable-distributed mudstone averaging 1.5 m thick (see Figure 5), which guarantees the safety of CO2 stored in each layer. The interbeds inside each layer commonly exist as discontinuous fine sands with a thickness of less than 1 m. Also, areal coefficients of variation (VE) for permeability are defined as

(1)

where S is the permeability standard deviation of the core sample pool, K̅ is the average value of core permeability, Ki is the permeability of the core sample, and hi is the net thickness. For the H59 Block, the VE values for the four key layers are 0.49 (7), 0.55 (12), 0.43 (14), and 0.56 (15), which represent medium uniformity for each layer. 2.2. Development Situation during Pure CO2 Flooding. From the end of 2003 until October 2007, 44 wells, including 34 for production and 10 for water injection, were drilled. Among them, 37 wells (29 for production and 8 for injection) were drilled in the pattern of an inverted seven point (well spacing, 440 m; well array, 140 m), which was believed to retard water channeling along the developed natural microfractures. During the first scenario of water flooding, 40 m3 was allocated as the daily water injection rate for each well and the monthly injection/production ratio in cumulative volume reached 0.6. As with most reservoirs in China, water injection in this area has seen lower than expected oil increments. It brought 5.8 tons of oil 379


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Figure 4. Strata information of the H59 Block. in 6 well groups in the northern part of the block from May 2008. The CO2 resource is transported by pipeline to the target area from a nearby CO2-rich gas reservoir. This unique advantage has made the H59 Block an ideal target for pilot CO2 flooding. As shown in Figure 3c, an inverted seven-spot pattern was used for CO2 flooding to minimize early gas breakthrough. The testing area contains 6 complete gas-injection well groups as well as 2 incomplete water-injection groups near the boundary. The gas injection rate was set at an average of 35 tons per day for each well. As shown in

(of 9.5 tons of liquid) production on average per well initially, which subsequently reduced to an unacceptable 2 tons. During that period, total oil production of the block was 3.87% of OOIP, which was lower than expected (see Figure 7). Another unfavorable characteristic was the exceptionally high water cut at 40% from the beginning. In fact, the above reasons made it necessary for development mode updating. Because of the limitations of water flooding in this block and the advantages of an accessible CO2 source from a nearby gas reservoir, a switch to CO2 flooding was made in this block as an updated scenario 380


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Figure 5. Thickness of mudstone distributed near the main layers (T, top; B, bottom). Figure 7. Oil production verses gas injection.

Figure 6. Dynamic character of the H59 Block. Figure 6, the reservoir pressure after gas injection returned very soon to the initial reservoir pressure, which indicates that the injection of CO2 was much easier than for water in this inferior reservoir formation, and miscibility was readily achieved in that the minimum miscible pressure (MMP) is 22.8 MPa as observed by experimentation. Until 2010, daily oil production rose from 2 to 5 tons and the average water cut dropped from 45 to 25%, which suggests a greater feasibility of CO2 as a solvent than water, and cumulative oil production reached 9.94% of OOIP cumulatively after a total of 0.19 hydrocarbon component pore volume (HCPV) of gross CO2 was injected. Until June 2011, nearly 80% of the injected CO2 has been provisionally sequestrated in nearly 3 years compared to 60% in CO2 flooding fields in the U.S.A.8 This phenomenon suggests that, before early breakthrough of gas, both enhanced oil recovery and carbon storage are fulfilled by most of the injected solvent being trapped in the pore space of the reservoir.9,10 Apparently, total oil production is linearly related to the injected CO2 volume (see Figure 7), and cumulatively, 123.1 thousand tons of CO2 has been sequestrated. Analyzed from a production history point of view, ideal equivalence between EOR and environmental protection has now been achieved. Therefore, as the first nationally funded CO2 EOR and sequestration reservoir in China, the H59 Block in the Jilin Oilfield has performed well in the past 4 years. Confidence has been gained by the company, and on the basis of developing experience, larger projects will be scheduled near this region. Until 2015, annual CO2 sequestration can be expected to be 1200 thousand tons, with 1 million tons of incremental oil in the neighboring area, which is encouraging from both CO2 EOR and sequestration perspectives.

Figure 8. Diagram of the slim tube apparatus.

3. PARAMETER OPTIMIZATION DURING RECYCLED GAS FLOODING Two different basic considerations for a CO2 EOR field are the desire to improve oil recovery11,12 or to merely achieve as much carbon retention as possible in the geological structures. There is equilibrium between these two aspects for coupled CO2 sequestration and EOR, which has recently been focused on by researchers. Ghomian et al.13 investigated various parameters based on the construction of mathematical response models and concluded that produced GOR constraints, well spacing, production and injection well types, and injection plan as well as key reservoir characters were among the principal parameters requiring optimization. On the basis of the previous discussion on well types and reservoir characters for the H59 Block, hydrocarbon proportions in the recycled gas and GOR constraints were screened for designing future scenarios. 3.1. Recycled Gas Components. For recycled gas injection planned in this block, the composition of injected gas should be optimized in that it affects oil production by changing the MMP between crude oil and CO2. According to the mechanism of CO2 flooding, miscible conditions can guarantee more oil production than immiscible conditions in the target reservoir.14,15 Thus, the nearer the 381


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Table 1. Normalized Components in Produced Gas after Breaking through components

methane

ethane

propane

n-butane

n-pentane

nitrogen

proportion (%)

31.695

12.654

9.828

3.317

0.860

39.435

Figure 9. Oil production under different displacing pressures and MMP determination.

components are in accordance with the analysis results of production gas samples (see Table 1). Eight different proportions of hydrocarbon components, namely, 0, 5, 10, 15, 20, 30, 40, and 50% were investigated in the experimentations. Using the 5% proportion as one example, before the experimentation began, crude oil from the H59 Block was stored in the first container. In the second container, injected gas was prepared containing 95% CO2 and 5% hydrocarbon components. First, crude oil was pumped into the slim tube until saturated conditions were reached, and 1.2 pore volumes (PV) of injected gas were injected under pressures of 13, 17, 21, 24, and 29 MPa. During the process, the amount of oil production was measured after every 0.1 PV gas was injected (see Figure 9a). Then, the maximum recovery factor under different displacing pressures can be obtained, and MMP was determined as 23 MPa from the knee point of the curve (see Figure 9b). Similarly, MMP experimentations using other hydrocarbon proportions were investigated using the above routine. As shown

conditions to complete miscibility, the more oil production can be expected. Given that CO2 is known to be mainly stored in the reservoir by occupying the place of hydrocarbons, higher oil recovery will increase the carbon sequestration amount. In this way, when reservoir conditions (including pressure and temperature) are stable, miscibility between oil and CO2 will facilitate both oil recovery and carbon sequestration.16 Meanwhile, MMP greatly depends upon components of the oil and injected gas. Therefore, during the recycled gas flooding scenario, gas for re-injection should be purified to achieve miscibility in the reservoir. The MMP can be obtained mainly from empirical correlation equations17 and experimentations. Given the character differences between oil samples18 and poor accuracy results using empirical equations, the MMP resulting from different composition percentages of the produced gas with crude oil was observed by slim tube experimentations (see Figure 8). For the hydrocarbon mixture in the diluted gas used in the experimentations, the proportions of the hydrocarbon group 382


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Figure 10. Relationship between MMP and MPH in the recycled gas.

Figure 12. Value of f under different GOR constraints.

Figure 11. Percentages of CO2 in gas samples.

in Figure 10, the MMP increases with an increase in the mole fraction of hydrocarbon (MPH) in the injected gas. In detail, when MPH is greater than 10%, the MMP between the injected gas and crude oil increases dramatically. This suggests that miscibility will be more difficult to achieve. Especially, when the hydrocarbon component fraction is greater than 30%, miscible conditions cannot be obtained because the MMP needed has already exceeded the permitted pressure (rock fracture pressure) for sequestration safety. If estimated by achieving miscibility under the current pressure, the optimum value of MPH is 7%. A higher percentage of hydrocarbons will impede the development of miscible flooding, and a lower percentage may result in more expenditure on purification, making it less economically competitive. 3.2. Produced GOR Constraints. The GOR is among the principle parameters in reservoir engineering, especially for CO2 flooding areas. For unfavorable mobility ratios between oil and CO2, gas would definitely move faster toward production wells and limit the overall invaded area, thus reducing the flooding efficiency of the injected solvent. For continental sediments in which interbeds are developed, heterogeneities could lead to faster gas breaking toward production wells. In this block until June 2011, the average block GOR was up to 250 (sm3/sm3) and CO2 was produced in high percentages (see Figure 11). If a GOR constraint is absent in the scenario design, the gas production rate will increase monotonically, bringing extra pollution and burdening the field gas disposal facilities. Otherwise, if production wells are set to shut when exceeding a reasonable upper limit of the GOR, not only use of injected CO2 will be improved by avoiding production along highpermeability channels but also the invading area may expand as a result of the changed flow regime in the reservoir. Hence, the

Figure 13. Recovery factor during each stage.

optimum value of the GOR constraint should be previously evaluated to maximize the benefits of both oil recovery and sequestration. Screening of the optimal GOR constraint should guarantee the maximization of EOR and carbon sequestration amounts. Because of the absence of financial parameters, economic evaluation is unavailable, and here, the alternative evaluation initially employed by Kovscek and Cakici19 is adapted for GOR screening. Their paper introduced an evaluation parameter f, which was defined as f = ω1

Np*

+ ω2

R VCO 2

(2) VR where ω1 (0 ≤ ω1 ≤ 1) and ω2 = 1 − ω1 are weights, Np* is the cumulative oil production, OIP is the volume of oil in place at the start of the solvent injection scheme, and VRCO2 and VR are the volumes of CO2 sequestration and pore volume of the reservoir, respectively. The value of the weighting terms ω1 and ω2 is previously set according to preferences between EOR and carbon sequestration, which together contribute to the ranking of the scenarios. Therefore, the value of f indicates the combined benefits of both oil production and carbon sequestration. If a larger weight is placed on ω1, oil production will be more crucial during scenarios screening through the value of f and vice versa. Under each condition, an increasing value of f indicates more benefits weighted by oil production and carbon sequestration, 383

OIP


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the CO2 EOR process. In this section, the exploitation results are predicted through use of the numerical simulation model, which is illustrated in detail in the Appendix. As shown in Figure 12, lower GOR constraints result in higher values of f. The value of f corresponding to a constraint of 800 GOR slowly ascends until the reservoir pressure reaches an upper limit. Hence, although the oil increment differs among cases, carbon sequestration places greater weight on integral evaluation. As shown in Figure 12, from 2015, the 1200 GOR constraint is preferred for its highest value of f compared to other conditions. In conclusion, in the recycled gas injection scenario, 6 wells will be scheduled for gas re-injection (MPH = 7%) at a rate of 35 tons per day, while the oil wells are set to produce under a constant bottom hole pressure of 8 MPa to avoid gas dissolution in the reservoir. The GOR constraint used will be 1200 (sm3/sm3). Then, the developing performance can be predicted through use of the simulation model, and comparisons can be made between CO2 EOR and storage.

Figure 14. Carbon sequestration during each stage.

Table 2. Performance Comparisons among Different Stages recovery factor (%) water flooding CO2 flooding recycled gas flooding

5.0 18.4 6.5

gross CO2 requirement per increment of oil (Mcf/STB) 6.2 7.8

annual oil CO2 production sequestration (% OOIP) (103 tons) 1.23 2.63 0.63

4. EVALUATION OF RESULTS AT DIFFERENT STAGES When the volume of injected solvent is less than 0.3 HCPV (the middle section in Figure 13), the growth rate of the recovery factor is obviously higher than for subsequent scenarios. As shown in Figure 14, during the first 7 years of pure gas flooding, 58% of the total carbon dioxide sequestration is achieved during the pure CO2 flooding stage, which is 75% of the injected CO2. During recycled gas flooding, the oil production rate becomes slowest among all periods (see Table 2). That is mainly because, after a long period of gas flooding, oil wells tend to shut because of overwhelming gas production, which sharply reduces oil production. In contrast, subsequent scenarios are expected to be inferior to the previous stage on the CO2 EOR aspect. Therefore, in recycled gas development, it functions much better for carbon sequestration than for oil recovery. Figure 15 shows the carbon dioxide distribution in one production layer at three different stages. From Figure 15a, the conclusion can be made that, during the production history, the displacing area is finite and the invaded space is confined by well groups. After 5 years of continuous CO2 flooding (see Figure 15b), the invading area of CO2 is predicted to be obviously

340 240

which is meaningful for scenario screening. Here, equal emphasis (ω1 = ω2 = 0.5) is placed on both aspects. Considering the pore volume variance as a pressure change during exploitation, VRCO2 and VR in eq 2 should be updated rather than being treated as a constant. Because the volumes of CO2 injected and produced are observed from surface conditions, VRCO2 should be treated as its converse under reservoir conditions. Therefore, VR is updated as below

V R = V0R e−Cp(p − p0 )

(3)

VR0

where is the pore volume under the initial reservoir pressure, Cp is the rock compressibility coefficient, and p is the updated reservoir pressure at each step. With adjustment by the combination of eqs 2 and 3, such a parameter is considered to allow for more accurate evaluation of the use of the pore volume rather than its potentials. This should be more significant during

Figure 15. CO2 distribution at different stages (layer 7). 384


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Figure 16. Properties of the H59 Block model.

Table 3. Fluid Parameters after Regression components

MW (g/mol)

Ωa

Ωb

Tc (K)

Pc (bar)

Vc (m3 kg−1 mol−1)

Zc

AF

CO2 CH4 + N2 C2H6 C3+ C4+ C5+ C7+ C11+ C29+

44.01 17.82 30.07 44.10 58.12 77.01 114.15 237.14 532.76

0.46 0.73 0.56 0.63 0.50 0.50 0.76 0.65 0.66

0.08 0.13 0.05 0.05 0.08 0.08 0.10 0.09 0.09

304.70 190.45 404.57 555.38 419.04 483.74 526.10 610.11 745.85

73.87 44.25 48.84 42.46 40.14 34.59 24.52 21.35 8.98

0.09 0.10 0.15 0.20 0.26 0.33 0.46 0.87 1.93

0.274 0.271 0.215 0.184 0.297 0.281 0.258 0.365 0.280

0.257 0.019 0.113 0.174 0.223 0.305 0.472 0.707 0.720

Figure 17. Relative permeability curves by core experimentations.

sequestration, both of which would currently be beneficial for China. (2) CO2 EOR and sequestration saw encouraging benefits in the H59 Block during 3 years of demonstration activity. With respect to oil recovery, the daily production rate of oil increased to 5 tons with a decreasing water cut to 25% compared to 2 tons of oil production and 45% water cut during water flooding. In addition, the carbon sequestration percentage was nearly 80% during the 3 years. Scaling-up deployment could be launched in target reservoirs based on the pilot scheme to abate anthropogenic carbon emissions. (3) During recycled gas injection, the gas component for re-injection and GOR constraints should be optimized. Through slim tube experimentations on different MPH, a trend of MMP values was obtained and optimized as 7%. An updated screening method

enlarged, even though it is still constrained by the group pattern. When it comes to the third stage (see Figure 15c), injected CO2 will break through toward the oil wells and the invading area will expand toward the boundary. Because the GOR constraint is active, extra regions excluded by the well groups see carbon distribution by transcending through shut wells, which brings extra carbon sequestration as well as oil production.

5. CONCLUSION (1) Carbon sequestration during CO2 flooding is a practical method and of great potential in China. For water-flooding oilfields characterized as high water cut and low permeability, the scenario switching to CO2 flooding can be expected to be a sustainable method for oil production and simultaneous carbon 385


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(3) Hu, W. R. Necessity and feasibility of PetroChina mature field redevelopment. Pet. Explor. Dev. 2008, 35 (1), 1−5. (4) Hook, M.; Xu, T. Development journey and outlook of Chinese giant oilfields. Pet. Explor. Dev. 2010, 37 (2), 237−249. (5) Babadagli, T. Mature field developedA review. Proceedings of the SPE Europec/EAGE Annual Conference; Madrid, Spain, June 13−16, 2005. (6) Davis, D. W. Project design of a CO2 miscible flood in a waterflooded sandstone reservoir. Proceedings of the SPE/DOE Improved Oil Recovery Symposium; Tulsa, OK, April 17−20, 1994. (7) International Petroleum Industry Environmental Conservation Association and American Petroleum Institute. Part II: Carbon Capture and Geological Storage Emission Reduction Family; June 2007; http:// www.ipieca.org/system/files/publications/CCS-FINAL_merged.pdf (accessed Oct 19, 2012). (8) Hadlow, R. E. Update of industry experience with CO2 injection. Proceedings of the SPE Annual Technical Conference and Exhibition; Washington, D.C., Oct 4−7, 1992. (9) Claridge, E. L. Prediction of recovery in unstable miscible flooding. SPE J. 1972, 12 (2), 143−155. (10) Gorecki, C. D.; Hamling, J. A. Integrating CO2 EOR and CO2 storage in the Bell Creek oil field. Proceedings of the Carbon Management Technology Conference; Orlando, FL, Feb 7−9, 2012. (11) Smith, R. L. SACROC initiates landmark CO2 injection project. Pet. Eng. 1971, 43 (13), 43−47. (12) Graue, D. J.; Blevins, T. R. SACROC tertiary CO2 pilot project. Proceedings of the SPE Symposium on Improved Methods of Oil Recovery; Tulsa, OK, April 16−17, 1978. (13) Ghomian, Y.; Sepehrnoori, K.; Pope, G. A. Efficient investigation of uncertainties in flood design parameters for coupled CO2 sequestration and enhanced oil recovery. Proceedings of the SPE International Conference on CO2 Capture, Storage, and Utilization; New Orleans, LA, Nov 10−12, 2010. (14) Miscible Displacement; Stalkup, F. I., Ed.; Society of Petroleum Engineers (SPE): Richardson, TX, 1984; Monograph Series, Vol. 8. (15) Practical Aspect of CO2 Flooding; Jarrell, P. M., Ed.; Society of Petroleum Engineers (SPE): Richardson, TX, 2002; Monograph Series, Vol. 22. (16) Malik, Q. M.; Islam, M. R. CO2 injection in the Weyburn Field of Canada: Optimization of enhanced oil recovery and greenhouse gas storage with horizontal wells. Proceedings of the SPE/DOE Improved Oil Recovery Symposium; Tulsa, OK, April 3−5, 2000. (17) Robl, F. W.; Emanuel, A. S.; Van Meter, O. E., Jr. The 1984 National Petroleum Council estimate of potential EOR for miscible processes. J. Pet. Technol. 1986, 38 (8), 875−882. (18) Ping, G.; Miao, L. A study on the miscible conditions of CO2 injection in low-permeability sandstone reservoirs. Oil Gas Geol. 2007, 28 (5), 687−692. (19) Kovscek, A. R.; Cakici, M. D. Geologic storage of carbon dioxide and enhanced oil recovery. II. Co-optimization of storage and recovery. Energy Convers. Manage. 2005, 46 (11−12), 1941−1956.

for the GOR constraint showed a preferred value of 1200 (sm3/sm3). Under such parameters, recycled gas flooding is predicted to lower the oil production rate for well shutting. However, with respect to carbon sequestration, it still functions well and contributes to 42% of the total carbon dioxide sequestration.

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APPENDIX The reservoir model is built based on integrated information during exploration, including well log, seismic analysis, laboratory experimentations as core analysis, etc. The upscaling model is dimensioned as 57 × 113 × 14, and two geological property models are shown in Figure 16. In the model, 4−8 components (pseudo-components) are used to define the reservoir fluid. Each component has a string of parameters that must be specified in the fluid characterization process. These parameters for pure components are usually considered fixed, but for pseudo-components, they are obtained by regression with experimentation results. Finally, regression results are shown in Table 3. In addition, relative permeability curves applied in the model were obtained through core experimentations (see Figure 17). Then, history matching was performed to update the reservoir model, and hence, the prediction can be achieved via software.

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AUTHOR INFORMATION

Corresponding Author

*Telephone: 0086-18618127941. Fax: +86-01089733223. E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors thank the PetroChina Jilin Oilfield Corporation for providing the geological model of the pilot block as well as its specific information of development. This work was supported by the National Basic Research Program of China (973 Program, Grant 2011CB707302-01) and the Chinese National Major Science and Technology (Projects 2011ZX05016-006 and 2011ZX05009-004-001). We are also grateful to the journal associate editor and reviewers.

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NOMENCLATURE MW = molecular weight Ωa and Ωb = non-dimensional constants in the equation of state Tc = critical temperature (K) Pc = critical pressure (bar) Vc = critical volume (m3 kg−1 mol−1) Zc = critical Z factor AF = acentric factor HCPV = hydrocarbon component pore volume (rm3) OOIP = original oil in place (rm3)

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REFERENCES

(1) Grigg, R. B. Long-Term CO2 Storage Using Petroleum Industry Experience; New Mexico Petroleum Recovery Research Center: Socorro, NM, 2002. (2) Carbon Monitoring for Action (CARMA). 5 Highest CO2 Emitting Power Sectors by Country; http://carma.org/region (accessed Oct 19, 2012). 386


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