immiscible co2 flooding for increased oil recovery and reduced emissions

8/11/2019 Immiscible CO2 Flooding for Increased Oil Recovery and Reduced Emissions

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Copyright 2000, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 2000 SPE/DOE Improved Oil RecoverySymposium held in Tulsa, Oklahoma, 35 April 2000.

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractCarbon dioxide is both the most-recognized greenhouse gas aswell as the second most-used injectant in oil fields, after water. This coincidence creates the possibility of injecting

previously-vented CO 2 to both reduce greenhouse gasemissions and increase oil recovery. Such a project has beenevaluated for the Avile reservoir of the Puesto Hernandezfield, located in the Neuquen Basin in west-central Argentina.This oil field produces associated gas containingapproximately 60 percent CO 2, which has previously beenvented. The project described below assessed the feasibilityof extracting and injecting the CO 2 into the field to recover additional oil using an immiscible displacement process.Following an evaluation including core floods, compositionalsimulation, and facilities evaluation, the process was found

both to have technical and economic promise in terms of improved oil recovery, and to result in reduction of both CO 2and methane emissions, the latter being an especially potentgreenhouse gas. The success of this type of project wouldcreate a unique common ground for those concerned withreducing global warming and those concerned with supplyingsocietys energy needs.

IntroductionThis project evaluated the application of a seldom-used

process (immiscible CO 2 flooding) in the Avile reservoir of the Puesto Hernandez field, located in the Neuquen Basin inwest-central Argentina (see Figure 1), a region with no prior history of CO 2 injection. Therefore, all aspects of a gasinjection project had to be investigated to arrive at a bestestimate of whether the project made technical and economicsense. Described below are the properties of the Avile

Reservoir, Puesto Hernandez Field, Argentina; results of thelaboratory fluid characterizations and core floods; pilot areacompositional simulations and the resulting incremental oilrate projections; the analysis of facility requirements; theimpact of this project on greenhouse gas emissions; and theestimated economic viability of the project. Significanttertiary oil recovery potential exists based on laboratorystudies of fluids and core materials from the reservoir combined with compositional simulation of the laboratoryexperiments and a field pilot model. Using a conservativeinterpretation of the available laboratory core flood dataresulted in favorable project economics under baseassumptions, with a low likelihood of negative economicreturns. The project was estimated to incrementally recover approximately 4.0 percent of the original oil in place,corresponding to 220,000 Sm 3 for the pilot area and 670,000Sm3 for the combined pilot and full project expansion. The

potential greenhouse gas emission reductions range fromapproximately 185,000 carbon equivalent metric tons for the

pilot to 714,000 carbon equivalent metric tons for thecombined pilot and full project expansion.

DiscussionReservoir Characteristics. Comprised dominantly of aeoliansand dune deposits, the Avile Reservoir in the PuestoHernandez Field can be characterized as a monotonous,massive sandstone. Vertical variations in porosity are oftensubtle and may have limited lateral continuity (see Figure 2).For the purpose of this study, the Avile was sub-divided into atotal of eight layers. These eight flow units reflected the

maximum number of vertical divisions that have reasonablelateral correlation. Each layer top was picked at the top of arelatively high porosity bed with the shallower reduced

porosity thickness assigned to the layer above. The lower portion of the Avile (layers 5-8 in this study) had moreconsistent thickness, while the upper Avile (layers 1-4 in thisstudy) was more variable.

Figure 3 illustrates the location of the pilot area, whileFigure 4 is a stratigraphic cross-section (flattened on the baseof the Avile) illustrating thickness variation of the eight layersin the pilot area. The cross-section traverses the pilot areawhere the Avile reaches maximum thickness in wells PH-0044, PH-0048, and PH-1108. Net thickness, porosity, and

SPE 59328

Immiscible CO2 Flooding for Increased Oil Recovery and Reduced EmissionsRandal M. Brush/William M. Cobb & Assoc., H. James Davitt/William M. Cobb & Assoc., Oscar B. Aimar/Perez CompancS.A., Jorge Arguello/Perez Companc S.A., Jack M. Whiteside/Barnes and Click, Inc.


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2 R. M. BRUSH, H. J. DAVITT, O. B. AIMAR, J. ARGUELLO, J. M. WHITESIDE SPE 59328

water saturation (Sw) were calculated in each well in the pilotarea (plus one pattern larger) for all eight layers. A total of 58wells were evaluated, of which 47 contained essentiallycomplete log data.

The proposed pilot area of the Avile Reservoir appears to be an excellent location to apply an immiscible CO 2 injection process: high permeability reservoir rock (median permeability of approximately 100 millidarcies, resulting inreasonable injection and production rates); low apparentreservoir heterogeneity (Dykstra-Parsons permeabilityvariation coefficient, V, is approximately 0.65, whichindicates a low level of permeability stratification, resulting in

potentially a high vertical sweep efficiency and a lowtendency of solvent to bypass oil in the reservoir); and fewapparent faults in the pilot area, which, if present, could

prevent solvent from contacting portions of the reservoir. Thisgeologic suitability is supported by the production

performance of the pilot area over the last 27 years. Theongoing waterflood has resulted in a substantial increase in

both the production rate and ultimate recovery of oil. Figure 5shows the smoothly increasing production rate of water duringthis period, supporting the interpreted lack of major reservoir heterogeneities that might act as conduits to flow, both for theinjected water and for injected CO 2.

Fluid Characterization. Three laboratory studies of reservoir fluids taken from the Avile Reservoir were available for review and for development of a multi-component equation-of-state (EoS) to match phase behavior and carbon dioxide(CO 2) interactions with the oil. These studies included a 1980PVT study, a 1994 PVT study including CO 2solubility/swelling experiments and minimum miscibility

pressure experiments, and a 1998 study including CO 2solubility/swelling experiments and minimum miscibility

pressure experiments. The 1998 results indicate an MMP of 246 Kg/cm 2 with 90 percent CO 2 in the injection gas, muchhigher than the 90 Kg/cm 2 expected reservoir pressure.Therefore, CO 2 will be immiscible with the in-situ oil.

Equation of State (EoS) Development. In order to forecastand monitor the CO 2 gas displacement process proposed for the Avile Reservoir, a description of the reservoir fluids wasnecessary which captures the wide changes in compositions

and physical properties expected in an immiscible CO 2injection process. While the approximation of a fully misciblesystem by a four component system (oil, water, hydrocarbongas, and CO 2) with a mixing factor formulation for simulationcan be reasonable at times, the varying pressures experienced

by the injected and in-situ fluids during the immiscible process, coupled with the strong pressure dependency of thefluid behavior relationships describing the system, required afully compositional approach. An EoS was developed basedon the Peng-Robinson formulation. The EoS parameters wereadjusted by regression of the 1998 data and the 1980 data.The 1994 data were not included because the resulting EoSwas a poorer match of all the laboratory data. Different EoS

parameters were also developed to describe flashing of

reservoir fluids to oil and gas at surface separator conditions because one set of EoS parameters does not adequatelydescribe the process over a wide temperature range. A five-component (CO 2, CH4, C2-C6, C7-C12, C13+) EoS wasdeveloped to match the fluid behavior. Five was the smallestnumber of components that could be used and still reasonablymimic the phase behavior. The EoS description is detailed inTable 1.

The EoS was matched to the laboratory swelling andviscosity data. The oil can swell in volume as much as 35

percent and that the oil viscosity can be reduced by a factor of four, key mechanisms responsible for increasing oil recoveryin an immiscible system. Figure 6 shows the simulation of theoriginal 1980 PVT fluid study including a good match of theoil formation volume factor, solution gas, and oil viscosity asa function of reservoir pressure.

Core Floods. In a miscible system oil recovery is increased because residual oil saturations are reduced to very low values(a commonly quoted value is 12 percent) in rock swept withthe injectant. An immiscible flood is more complex becauseone needs to know how the residual oil saturation to gasflooding changes with pressures below MMP. A series of unsteady-state core flood experiments were performed todetermine residual oil saturations to waterflooding (S orw), andto CO 2 gas flooding (S org) as a function of pressure. Theresulting relationship between pressure and residual oilsaturation after gas flooding is shown in Figure 7. In addition,one steady-state water-oil relative permeability curve wasdeveloped followed by one unsteady-state gas-water displacement cycle to determine trapped gas saturation.

Nitrogen was used in the last test because it is essentiallyunreactive with the fluid system.

The core flood experiments were simulated using the 5-component EoS fluid description. The simulation was one-dimensional using 180 grid blocks to describe the one-footcomposite core. A summary of oil recoveries calculated fromthe laboratory experiments and simulation results is shown inTable 2. Laboratory waterflood oil recoveries averaged 51

percent. Simulation waterflood recoveries were slightlylower, averaging 47 percent, because a constant S orw was usedin all cases. Laboratory waterflood oil recoveries were

probably accurate to within two to three percent. Oil

recoveries attributed to CO 2 injection ranged from 17 percentat 55 bars to more than 40 percent at 290 bars by laboratoryanalysis. Notice that the gas flood oil recoveries by simulationare within one percent of the reported laboratory data.Pressure matches were quite good except for Test #1 at 290

bars which was far away from any expected field operating pressure. Test #1 was done to determine the minimum likelyresidual oil saturation for comparison with the other tests. Anexample plot of oil rates and volumes (on a reservoir basis) isshown in Figure 8. Gas-oil ratios (on a surface basis) exhibitgas break through coincident with the laboratory data.

Figure 9 shows the computed oil saturations along thecore after waterflood and at the end of the gas flood. At the

end of the waterflood there was an oil saturation gradient


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SPE 59328 IMMISCIBLE CO2 FLOODING FOR INCREASED OIL RECOVERY AND REDUCED EMISSIONS 3

across the core because only 1.5 to 2.0 pore volumes of water were injected. Many more pore volumes would be required toachieve a constant value as required by frontal advancetheories such as Buckley-Leverett. Residual oil saturations atthe end of the gas flood also show a gradient across the corefor the same reason as for the waterflood. Final oilsaturations ranged from zero at the front end of the core inTest #1 at 290 bars to values approaching 40 percentdepending upon pressure. There was typically a sharpincrease in saturation midway through the core at sub-miscible

pressure conditions indicating a progressive stripping anddisplacement of hydrocarbon components.

Pilot Simulation. The pilot area reservoir simulation modelintegrated available log, core, fluid, and production dataspanning 30 years. The modeled area covered 835 hectarescontained 84 wells which included the proposed pilot projectencompassing 112 hectares and 22 wells. The geologic modelincluded eight flow units to ensure that the proposed tertiaryrecovery process would be adequately described. The modelwas validated using a black oil formulation (for speed of simulation) to match 30 years of primary depletion andwaterflood recovery. It was then converted to a compositionalformulation in order to model the more complex CO 2 / oilmass transfer process.

Two gas injection performance forecasts were reported based on reservoir pressure at which the process was operated.A reservoir pressure of 80 bars was used as the base case, and100 bars were used as the reservoir pressure for the upsidecase. The end-point oil saturation to gas displacement was 25

percent at 80 bars and 22 percent at 100 bars, consistent withlaboratory results. The reported incremental oil productionwas calculated as the difference between continued waterfloodto a watercut limit of 98.5 percent and the six-year gasinjection project followed by waterflood to the same watercutlimit.

M odel Descripti on. The reservoir top of structure valuesand each sub-interval thickness as determined by log analysiswas imported into the reservoir simulation mapping packageto develop the structural description. Average porosities werecalculated for each layer in each well from log analysis andcontoured. Air permeabilities were calculated from grid block

porosities using a core-based permeability-porosity

correlation. These air permeabilities were then converted toliquid permeabilities, which reduced effective permeabilitiesmore in the low quality (porosity) rock than in the higher quality (porosity) rock. During the history match processmodel permeability values were modified. All permeabilitieswere increased by a factor of 2 to get the wells to produce atrequired rates; a high permeability streak was created betweenWell 2 and Well 40 along the mapped fault to get water toWell 40 on time; permeabilities were reduced in a perchedwater region (northwest corner of the model) by a factor of 0.1to increase initial water saturations via the J-Functionapproach (discussed below); and preferential north/south flowwas created with K N-S = 2 K E-W . Faults were modeled as

transmissibility barriers, with most faults included as sealing

The oil-water contact was set at 425m subsea and the gas-oil contact at 295m subsea. Initial water saturations wereestablished using a J-Function approach to calculate initialwater saturations as a function of height above the oil water contact and rock quality (porosity and permeability). The J-Function was calculated from log analysis for each modellayer of those wells logged before water injection had begun.

One normalized relative permeability curve was input intothe model and used throughout the entire model area. Thiscurve shape was modified to match history. The residual oilsaturation to waterflood endpoint was set to S orw = 0.25 basedon a review of available laboratory special core analysis data.To improve the history match the end point water relative

permeability was reduced to reduce water flow. The end pointgas relative permeability was increased to help match field

pressures.An orthogonal grid was developed oriented parallel to the

major pattern design and fluid flow direction. The grid was 39 by 31 cells as shown in Figure 10. The smallest grid block size, which was approximately 0.38 hectares, extended 2 grid

blocks outside of the proposed 6-pattern carbon dioxide (CO 2) pilot area. The size of the smallest blocks was set to provide 6grid blocks between wells in the pilot area. The largest grid

blocks were twice the dimensions of the smallest grid blocks.The total grid area was approximately 835 hectares, with the

pilot pattern area containing approximately 112 hectares.Reservoir H istory M atch. Simulating 30 years (January

1968 to June 1998) of reservoir primary production andwaterflood performance was done using a black oil simulator.Simulations using the compositional simulator was not

practical because of the factor of four difference incomputational speed. Well rates were controlled by totalliquid rates which permitted relative fluid mobilities (oil,water and gas) to determine producing rates of eachcomponent. Reservoir pressures, oil rates, and watercut werethe major history match parameters. The pressure matcheswere reasonable until 1996 when simulated pressures jumpeddramatically to more than 100 bars. The most reasonableexplanation for the erroneously high pressures is that reportedwater injection rates into the reservoir are too high either

because of meter error or out-of-zone injection. To controlreservoir pressures to more reasonable levels, a pressuremaintenance option in the simulator was invoked to control

water injection to achieve a target reservoir pressure. Thetarget pressure was 90 bars because the carbon dioxideinjection cases were to be simulated at 80 and 100 bars.

The black oil model was then converted into the finalcompositional model. The only model change was tosubstitute a 5-component compositional fluid description for the black oil fluid description. There were no changes madeto the reservoir description, relative permeabilities or wellrates. The resultant compositional history match of the

proposed pilot pattern area is shown in Table 3. The Avilewaterflood has been very efficient. More than 80 percent of the mobile oil to waterflood was estimated to have beendisplaced from the pilot pattern area. A large fraction of that

displaced oil has already been captured by wells or can


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reasonably be expected to be captured in the future. Oilsaturations are estimated now to be approximately 33 percentwith residual saturations to waterflooding of 25 percent.

Production Forecasts . A waterflood forecast wasrequired to establish a baseline for comparison to carbondioxide injection scenarios. Incremental oil productionattributable to carbon dioxide could then be calculated. Theresults of the waterflood simulation cases for both the black oil and compositional simulations were in good agreement asshown in Table 3. An additional 0.77 0.78 Msm3recoverable reserves were estimated to remain as of June1998.

Carbon dioxide injection forecasts were developed withinjection beginning in January 2001. Injection rates werelimited to 100,000 sm3/day of 85 percent CO 2 purity gas.Two scenarios were examined, Case 1 with reservoir pressureof 80 bars and Case 2 with reservoir pressure of 100 bars. Thevalue of S org used was 25 percent at 80 bars and 22 percent at100 bars. Reservoir pressure was controlled automatically tothe target pressure via water injection. CO 2 injection wasalternated with water injection on six-month intervals over asix-year period to achieve maximum gas/oil contact and avoidexcessive gas production at producers. Approximately 87

percent of the estimated pattern hydrocarbon pore volume(hcpv) of gas was injected in Case 1 using a water alternatinggas (WAG) ratio of 1.0 reservoir volumes of water per reservoir volume of gas. For Case 2 at a pressure of 100 bars,approximately 61 percent of the hcpv was injected at anaverage 1.4 WAG ratio.

Incremental oil to CO 2 displacement up to July 2026 wascalculated to range from 0.22 Msm3 at 80 bars reservoir

pressure to 0.28 Msm3 at 100 bars as shown in Table 4. The production rate forecasts are shown in Figure 11. Theincremental oil volumes represent approximately 4.0 percentof the pattern original oil-in-place. A useful measure of CO 2efficiency is the volume of injected gas per volume of incremental oil production, known as the gas utilizationfactor. A gas utilization factor less than 10,000 scf/stb (1,780sm3/sm3) is considered good. The values calculated rangefrom approximately 5,000 (upside case) to 6,000 (base case)scf/stb.

The immiscible CO 2 process works by swelling oil andreducing its viscosity and saturation. The effect of oil

swelling can be seen in Figure 12 which shows the change in pilot pattern oil saturation versus time for both continuedwaterflooding and the two gas injection cases. Beginning in2001 (when CO 2 injection would start) the oil saturationincreased as a result of swelling before it was displaced.

Figure 13 shows the predicted incremental oil productionrate for the pilot production wells, along with the expansioncase forecast. The rate forecast for the expansion of theinjection project to the remainder of the Avile Reservoir was

based on the pilot study simulation results. A production rate prediction tool was used to forecast the impact of projectexpansion. This tool scaled the pilot production curve to thevolume of reservoir and injection gas available. The volume

of CO 2 available in the Puesto Hernandez Field appears to be

sufficient to flood approximately three times the volume of reservoir flooded by the pilot, resulting in a total (pilot plusexpansion) oil recovery of approximately 670,000 m 3 of oil.

Note that the incremental production rate for the expansionwas still at a high level at the assumed end of field life. Thisresulted from the limited volume of CO 2 available for the

project. In addition to not having sufficient CO 2 to flood theexpansion areas to completion, approximately 50 percent of the Avile Reservoir otherwise suitable for flooding would not

be flooded because of the limited volume of CO 2 available atPuesto Hernandez. The presence of CO 2 in produced gas fromother fields in the region indicates the potential for additional

beneficial use of what otherwise would be one of the waste products resulting from oil production.

Facility Requirements. The facilities required to execute the pilot project, including gas compressors, injection flowlines,and additional production flowlines, were studied in detail.The pilot facilities would take the available CO 2 from theexisting and currently-planned membrane separators,compress and dry the gas, and transport the gas to the existinginjection wells. In addition, production flowlines would beadded to handle the increased volume of gas expected fromthe production wells.

The facilities required to execute the project expansioninclude adding injection and production flowlines as needed,and potentially fitting larger first-stage cylinders to the pilot

projects compressors. The fields gas production rate isexpected to be low during this period. Therefore, additionalgas separation facilities would not be required.

Greenhouse Gas Reduction. The gas injected into the pilotarea would otherwise be vented as an unwanted byproduct of the fuel separation process. The pilot project would result in anet injection of 107,000,000 m 3 of CO 2 and 19,000,000 m 3 of methane. This volume accounts for the gas injected less thegas produced over the life of the field, and therefore assumesno ongoing injection following conclusion of the pilot. Thecorresponding reduction in emissions using carbon-equivalentmass (CO 2 basis)would be approximately 185,000 metric tons.The additional net gas injection for the expansion case would

be 307,000,000 m 3 of CO 2 and 54,000,000 m 3 of methane,corresponding to a reduction in carbon-equivalent (CO 2 basis)

emissions of approximately 529,000 metric tons. For the pilot plus expansion projects, the total net gas injection volumeswould be 414,000,000 m 3 of CO 2 and 73,000,000 m 3 of methane, equal to a reduction in carbon-equivalent (CO 2 basis)emissions of approximately 714,000 metric tons.

Project Economics. By their nature, pilot economicevaluations contain significant uncertainty. This pilot willevaluate an uncommon oil recovery process in a producingregion not previously subject to enhanced oil recovery throughCO2 injection. Nonetheless, such uncertainty can be dealtwith. Sensitivity analysis was conducted around the two

principle sources of uncertainty for the economics of the pilot:

the volume oil produced by the pilot and the price of oil


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received for that production. Oil production was reduced andincreased by 50 percent from the base pilot forecast, and oil

prices were varied by $4.00 per barrel from the baseassumption of $16.00 per barrel West Texas Intermediate(WTI) benchmark. Using the base oil production forecast andthe $16 per barrel price forecast, the pilot project wasestimated to have approximately a 9 percent after tax rate of return. This rate of return varied from -3 percent to 19 percentover the range of oil recoveries and prices examined. Table 4

provides the economic sensitivity analysis results.As Table 4 also shows, the economics of the expansion

case were more favorable than those of the pilot. This was because of the small additional capital required by theexpansion. The compressors were assumed already purchasedfor the pilot, with only the salvage value to be paid. Theinstallation of injection and production lines were the other major capital expenses. The expansion project would have anafter tax rate of return of approximately 20 percent assuming$16 per barrel WTI. Again, sensitivity analyses were run for oil production volumes and oil prices, resulting in a range for the after tax rate of return of -1 percent to 33 percent.

ConclusionsThe application of immiscible CO 2 injection into the AvileReservoir, Puesto Hernandez Field, Argentina, has been foundto be both technically and economically promising. Inaddition, it offers the opportunity to turn what has been awaste stream of increasingly ill repute into a money-making

product.

AcknowledgementsThe authors would like to thank the International FinanceCorporation of the World Bank and Perez Companc S.A. for their financial support of this project, and for their willingnessto publish these results.

Figure 1: Field Location

Figure 3: Field Map in Pilot Area

Figure 2: Avile Type Log: PH-1108


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Figure 6

F i g u r e 4 : N W t o S E C r o s s - S e c t i o n

0

5

1 0

1 5

2 0

2 5

3 0

3 5

4 0

P H - 0 0 5 7 P H - 0 0 5 6 P H - 1 1 6 4 P H - 0 0 5 1 P H - 0 0 4 8 P H - 1 1 0 8 P H - 0 0 4 4 P H - 0 0 4 3 P H - 0 0 3 9 P H - 0 0 3 8 P H - 0 0 3 5

W e l l N a m e

F i g u r e 5 : Av i l e C O 2 P i lo t A r e a P r o d u c t i o n D a t a

0. 1

1

1 0

1 0 0

1 0 0 0

1 0 0 0 0

1 9 7 0 1 9 7 5 1 9 8 0 1 9 8 5 1 9 9 0 1 9 9 5 2 0 0 0

m 3 / D a y ,

m 3 / m 3

W O RG O R

InjectionOi l + Wa t e r O il


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F i g u r e

7 : S o r g v s .

P r e s s u r e

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F l o o

d

F i g u r e

9 : C o r e

O i l S a t u r a

t i o n

P r o f

i l e

F i g u r e

1 0 :

M o d e l

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d


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F i g u r e

1 2 :

C h a n g e s

i n P i l o t O i l S a t u r a

t i o n

F i g u r e

1 3 :

O i l R a t e s

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i c A n a l y s

i s


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Table 1


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T a b

l e 2


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T a b

l e 3


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After Tax Present Value at 10%50% 100% 150% 50% 100% 150%

$12/Bbl WTI -$3.0 -$1.6 -$0.2 -$0.9 $0.4 $1.7$16/Bbl WTI -$2.4 -$0.3 $1.7 -$0.3 $1.6 $3.5$20/Bbl WTI -$1.7 $0.9 $3.6 $0.3 $2.8 $5.3

After Tax Rate of Return50% 100% 150% 50% 100% 150%

$12/Bbl WTI -3% 4% 9% -1% 13% 20%$16/Bbl WTI 1% 9% 15% 7% 20% 27%$20/Bbl WTI 4% 13% 19% 12% 25% 33%

Oil Rate Risk Factor



Ex ansion EconomicsPilot Economics

Table 4: Pro ect Economic Results


immiscible co2 flooding for increased oil recovery and reduced emissions

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