March 2014 • Volume 2 • Number 1 ISSN 1929-7408 1

Using Polymers to Improve CO2 Flooding in the North Burbank UnitW. Li, D.S. Schechter texas A&M University

AbstractThe North Burbank Unit, located in Osage County, was origi-

nally discovered in 1920. It has an extensive history of activity, including primary depletion, produced gas cycling, and water and polymer flooding to the point of very high water cut at cur-rent conditions. The current oil production rate in the North Bur-bank Unit is approximately 1,400 BOPD from 360 active wells at a water cut of 99.5%. The North Burbank Unit has a cumulative production of 332 million bbl of oil out of an estimated 824 million bbl of original oil-in-place. Significant reserves are currently avail-able for post-secondary production. CO2 flooding is a good choice considering that the minimum miscibility pressure (MMP) in the North Burbank Unit is lower than the fracturing pressure and CO2 is available from a purely anthropogenic source. This paper demonstrates that a 100-year-old field is not only an excellent CO2 enhanced oil recovery (EOR) target, but is at the forefront of a new synergistic technology to couple EOR and anthropogenic CO2 that would otherwise be released to the atmosphere. It is a logical alternative to reduce CO2 emissions while increasing do-mestic production.

High heterogeneity and high permeability at the top layers are the two main challenges of the North Burbank Unit. Two methods related to polymers are studied to improve CO2 flooding in the North Burbank Unit. One is to add polymers with co-sol-vent, named CO2 viscosifier, to CO2 to increase CO2 viscosity. The other is to add polymers to water to increase water vis-cosity during the water-alternating-gas (WAG) process, named polymer-alternating-gas (PAG) flooding. To analyze the impact of CO2 flooding in the North Burbank Unit, five tracts that best represent the characteristics of the field were selected for res-ervoir modelling. Based on simulation results, the conventional WAG process increased average oil recovery in the North Bur-bank Unit by 10.89%, and gross CO2 utilization and net CO2 uti-lization are forecasted to be 11.27 Mscf/bbl and 5.40 Mscf/bbl, respectively. Using CO2 viscosifier and PAG flooding could mark-edly delay gas breakthrough, reduce gas-oil ratio and increase oil recovery. CO2 viscosifier and PAG are forecasted to increase av-erage oil recovery 7 to 8% more than conventional WAG flooding in the North Burbank Unit.

IntroductionAlthough CO2 flooding is a well-established EOR technique, its

density and viscosity nature is a challenge for CO2 projects. Low density (0.5 to 0.8 g/cm3) causes gas to rise upward in reservoirs and bypass many lower portions of the reservoir. Low viscosity (0.02 to 0.08 cP) leads to poor volumetric sweep efficiency. In het-erogeneous reservoirs with high-permeability zones and natural fractures, the condition is even worse(1).

cO2 ViscosifierCO2 viscosifiers (direct thickeners) are the most direct way

to increase the viscosity of CO2, hence improving overall sweep efficiency. A high-molecular-weight polymer and co-solvent are blended and pressurized together with CO2 so that CO2 viscosity can be greatly increased before CO2 is injected. A number of studies show that gas viscosifier chemicals can increase CO2 vis-cosity by an order of one to two and can control CO2 mobility(2-6). However, the main barriers to using viscosifiers include the fol-lowing: (1) the large volume requirement of co-solvent makes pilot-testing costs prohibitive(7); (2) co-polymers do not dissolve in CO2 unless pressure far exceeds MMP (7); and (3) the environ-mental impact is negative(8).

PAGTo overcome the issues of gas breakthrough and gravity

segregation, a new combination method is proposed. This new method, termed PAG, combines features of CO2 flooding with polymer flooding to produce chemically enhanced WAG flooding. Coupling polymers with CO2 is expected to improve the effi-ciency of the current WAG. The main feature of PAG is that the polymer is injected with water throughout the whole WAG pro-cess. Zhang et al.(1) conducted an experiment based on Saskatch-ewan crude, named polymer injection chased with gas alternative water (PGAW). They stated that coupled CO2 and polymer injec-tion gave better recovery and efficiency than WAG and polymer flooding. Majidaie et al.(9) carried out the first coupled CO2 and polymer injection simulation study for light oil based on a syn-thetic and homogeneous model. This study showed that PAG and WAG have almost the same recovery. He also mentioned that a chemical slug of polymer with surfactant and alkali would signifi-cantly increase oil recovery.

WorkflowIn this study, we discuss CO2 viscosifier and PAG flooding

in light oils based on the field model, TR48, of the North Bur-bank Unit. The commercial software E100 was used, which is a simulator that can model both the solvent process and polymer flooding. The main steps in the simulation study are as follows:

1. Describe geological background, production history and reservoir characteristics in the North Burbank Unit.

2. CO2 resource.3. Build pressure-volume-temperature (PVT) model.4. Build reservoir model. 5. Validate the reservoir model by matching primary and sec-

ondary production data. 6. Evaluate the performance of CO2 viscosifier. 7. Evaluate the performance of PAG.

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Development History of the North Burbank Unit

The North Burbank Pool, located in Kay and Osage Coun-ties, Oklahoma, was discovered by Marland Oil Company in May 1920. The discovery well (named No. 1 Tribal) was located in the southeast/northeast Section 36, T27N, R5E on the small Hay Creek anticline. In September of that year, Carter Oil Company drilled two wells on another small anticline 2 miles to the south-east in Section 9, T26N, R6E(11).

Development drilling proceeded rapidly, and by 1924, 75% of the wells in the main part of the field had been drilled. The initial po-tential of wells in the Burbank sandstone varied from 10 to 12,000 BOPD. As shown in Figure 2, peak production was reached in July 1923, when the average daily production was 122,000 BOPD.

Geological BackgroundAs mentioned by Johnson(10), the North Burbank Unit is lo-

cated on the northeastern Oklahoma Cherokee platform (Figure 1). Burbank sandstone is the main reservoir of the field. Burbank sandstone is the local informal name for the Red Fork sandstone. It is part of the Desmoinesian Cherokee Group, a sequence of sandstones, shales and thin limestones. As shown in Table 1, the Cherokee sandstones include, in ascending order, the Bartles-ville, Red Fork, Sonner and Prue. Burbank sandstone has pro-duced more than 90% of the oil and minor gas from depths of 2,800 to 3,200 ft. Minor amounts of oil and gas have been pro-duced from younger Pennsylvanian sandstones, Mississippian “Chat,” and Ordovician sandstones. Johnson(10) also described that Burbank sandstones were fluvial-deltaic and a stratigraphic trap.

FIGURE 1: Geologic map of the North Burbank Unit: a) Location of the North Burbank Unit(15); b) Highlighted tracts in the North Burbank Unit.

TablE 1: General stratigraphic column of the cherokee group and burbank sandstone.

Sources: Overpressuring and Seal Structure of Pennsylvanian Red Fork Formation in the anadarko basin, Oklahoma (edited from Virginie 1995)

Eon System Series Group Subsurface Name

Paleozoic

Pennsylvanian

Desm

oinesian

Marmaton Big Lime

Oswego Limestone

Cherokee

Cab

aniss

Prue Sandstone

Verdigris Limestone

Upper Sonner Sandstone

Henryetta Coal

Middle Sonner Sandstone

Lower Sonner Sandstone

Pink Limestone

Kreb

s

Red Fork Sandstone(Burbank Sandstone)

Inola Limestone

Bartlesville Sandstone

Brown Limestone

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Production declined rapidly as a result of the wide-open opera-tion, and the practice of pulling vacuum on wells, which began in 1924 in an effort to increase production. Produced gas injection began in 1926 by various operators in the field. The injection of purchased gas from external sources began in 1935.

Approximately 150 million bbl had been produced under pri-mary and gas injection by 1951, when, what was then one of the world’s largest waterflooding projects, began operation. Between 40,000 and 50,000 bbl of water from the nearby Arkansas River was pumped to the field for injection(12). Approximately 182 mil-lion bbl have been produced in this secondary recovery phase.

Most of the current production now comes from waterflooding with a high water cut of 99.5%.

Reservoir PropertiesThe gross oil pay thickness of the North Burbank Unit varies

from 30 to 100 feet, with an average of 47 to 50 feet (10, 11). The subsea is about 2,850 to 3,100 feet, with a reservoir temperature of 118° F. The initial reservoir pressure is 1,600 psi, which is be-lieved to be above the initial saturation pressure for oil. The initial solution gas-oil ratio was estimated to be 380 ft3/bbl. Table 2 sum-marizes the basic reservoir and field characteristics(10).

Based on core data, two typical reservoir characteristics of the North Burbank Unit were found (Figures 3 and 4): high permea-bility exists in the top layers, and the Dykstra-Parsons coefficient of permeability variation (VDP) varies from 0.50 to 0.98.

CO2 ResourceIn 2011, the operator signed a long-term carbon dioxide (CO2)

purchase and sale agreement for the capture of CO2 from a ni-trogen fertilizer plant located in Coffeyville, Kansas. Almost all of the fertilizer plant’s CO2 emissions will be captured. A CO2 gath-ering and compression facility was constructed at the plant site and 68 miles of pipeline was installed in order to deliver the CO2 to the North Burbank Unit in Osage County, Oklahoma.

FIGURE 2: The North Burbank Unit production history. Three phases: primary development (1922–1926); recycled gas injection (1926–1950s); and waterflooding (1950s–2010s).

TablE 2: Summary of reservoir and field characteristics. Formation Red Fork sandstone Age Pennsylvanian, Desmoinesian Depth to Top of Reservoir 2,900 ft Gross Thickness 2,850 to 3,100 ft Net Thickness, Average 50 ft Reservoir

Net Thickness, Maximum 100 ft Lithology Fining upward, very fine- to medium-grained sandstone with some

carbonate silica and clay cement Porosity Type Intergranular and moldic due to dissolution of framework grains Average Porosity 0.20 Permeability Variable: 0 to 1,200 mD; average permeability: 50 to 80 mD

Well Spacing 10 wells/acre Primary Recovery 150 million bblField Secondary Recovery 182 million bbl Total Reserves in Place 824 million bbl

0 200 400 600 800 1,000 1,200

3,064 3,060 3,057 3,043 3,039 3,035 3,030 3,027 3,023 3,019 3,015 3,011 3,007 3,003 2,999 2,995 2,991 2,987 2,983 2,979

Permeability (Md)

Dep

th (f

t)

FIGURE 3: Permeability vs. depth at well NBU48-28 (Core data 2006).

1

10

100

1,000

10,000

2 5 10 15 20 30 40 50 60 70 80 85 90 95 98

Perm

eabi

lity

(md)

Percent

Dykstra-Parsons Coefficient of Permeability Variation

FIGURE 4: VDP at well NBU48-28 (Core data 2006).

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Reservoir ModelBuilding a full-field 3D geologic model of the North Burbank

Unit presented several unique challenges, including having per-meability/porosity logs and secondary production/injection data for only a few wells. To address the problem of limited data, five tracts of the North Burbank Unit were selected from the 146 total tracts. These five sections represent typical geological character-istics and well patterns and also have boundary production data. All five tracts (ST48, ST59, ST78, ST88 and ST92) are simulated in this project, and ST48 was selected as an example to show how to improve CO2 flooding in the North Burbank Unit.

For the purpose of modelling, the ST48 is characterized by a gridded network with permeability and porosity parameters spec-ified for each block. For this model, the 0.5 × 0.5 mile reservoir section is divided into 60 grid blocks in the x-direction, 60 grid blocks in the y-direction, and 10 grid blocks in the z-direction. In the x- and y-directions, the grid blocks are 44 feet in length. The grid blocks in the z-direction vary from 4 to 24 feet thick, which results in a pay zone of 91 feet. Figure 8 shows thickness and x-horizontal permeability (kh) in the model. The vertical per-meability (kv) is 0.01 times the x-horizontal permeability, while y-horizontal permeability is 3 times the x-horizontal permeability. Table 3 presents the input reservoir rock and fluid properties used for the simulation.

History MatchingUsing the reservoir model described above, simulation runs

were made to history match the reservoir’s pre-CO2 flood oil and water production during primary depletion and secondary

Fluid ModelThe Peng-Robinson equation of state (EOS) was used in this

study for fluid modelling of the North Burbank Unit. After com-bining 40 components into 11 pseudo-components, molecular weight, critical pressure, critical temperature, binary interaction coefficients, and Pedersen viscosity coefficients were regressed to match experimental data with simulated data.

Based on the PVT model we obtained, we calculated swelling factor, fluid viscosity and MMP. The swelling factor for light oil in-creases to 1.58 (Figure 5) when the CO2 fraction increases from 0.0 to 0.75 with a constant temperature of 122° F. As the CO2 mole fraction increases from 0.0 to 0.75, fluid viscosity declines from 3 to 1 cP (Figure 6). Calculated MMP for the North Burbank Unit oil is about 1,680 psi (Figure 7). Considering that the initial res-ervoir pressure is about 1,600 psi and the highest injection pres-sure is about 2,100 psi, CO2 miscible flooding is possible for this light oil.

80

84

88

92

96

100

1,200 1,400 1,600 1,800 2,000 2,200 2,400 2,600

Oil

Rec

over

y Fa

ctor

(%)

Pressure (Psia)

FIGURE 7: Calculated MMP from software.

0

0.5

1

1.5

2

2.5

3

3.5

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

Flui

d Vi

scos

ity (c

p)

CO2 mole fraction

FIGURE 6: Correlation of fluid viscosity vs. CO2 mole fraction.

1

1.1

1.2

1.3

1.4

1.5

1.6

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Swel

ling

Fact

or

CO2 Mole Fraction

FIGURE 5: Correlation of swelling factor vs. CO2 mole fraction.

0 100 200 300 400 500 600 700 800 900

1

2

3

4

5

6

7

8

9

10

X-horizontal Pzermeability (md)

Laye

r

FIGURE 8: Thickness (left) and x-horizontal permeability (right) of each layer.

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Canadian EnErgy tEChnology & innovation

development. The liquid production rate was used as the primary constraint. A good match of oil rate and water cut was reached (Figure 9), which validates the reservoir model.

cO2 Viscosifier Flooding Versus WAGTo illustrate the possible CO2 viscosifier effects, we plot a

series of curves, as shown in Figure 10, to represent the new

viscosity-pressure relationship. Viscosity increases of 5-, 10- and 20-fold are used in this study according to the literature.

The reservoir performance during CO2 viscosifier flooding was compared with WAG. As shown in Figure 11, oil recovery is doubled compared with WAG when viscosity is increased 20-fold. Figure 11 also shows that oil recovery from the CO2 viscosifier in-creases as CO2 viscosity increases.

We forecasted the oil production rate for the three different CO2 viscosities (Figure 12). As shown in Figure 12, (1) the more gas viscosity increases, the later oil rate responds during gas in-jection, and (2) the more gas viscosity increases, the higher the peak rate. Figure 13 shows the gas-oil ratio of these three pro-cesses. It shows that the more gas viscosity increases, the lower the gas-oil ratio. From Figures 12 and 13, we can also conclude that increasing CO2 viscosity would delay gas breakthrough.

PAG Versus Polymer Flooding and WAGTo study the PAG process, the correlations of rock adsorp-

tion and polymer viscosity with polymer concentration (shown in

TablE 3: Reservoir rock and fluid properties. Reservoir Rock Reservoir Fluid

Parameter Values Parameter Values

Size of Model (ft) 2,640 × 2,640 × 91 Water Density (lb/ft3 ) 62.97 Number of Grid 60 × 60 × 10 Water Viscosity (cp) 0.5 VDP 0.85 Oil Density (lb/ft3) 50 to 52 kv/kh 0.01 Oil Viscosity (cp) 2 to 4 Porosity 0.15 to 0.27 Initial Oil Saturation 0.61 to 0.80 Initial Pressure (psi) 1,350 Initial Water Saturation 0.20 to 0.39 Permeability (mD) 6 to 230

0.00

0.50

1.00

1.50

2.00

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000

Visc

osity

(cp)

Pressure (psi)

Neat CO2 viscosity 5-fold viscosity 10-fold viscosity 20-fold viscosity

FIGURE 10: Different viscosity curves changing with pressure (edited from Cai 2010).

0

20

40

60

80

100

0

500

1,000

1,500

2,000

2,500

3,000

Jan-00 Sep-13 May-27 Jan-41 Oct-54 Jun-68 Feb-82 Oct-95 Jul-09 Mar-23

Water C

ut (%)

Oil

Rat

e (b

bl o

f oil/

day)

Date (MM-YY)

Oil Rate-Production Data Oil Rate-Simulation Result Water-Cut-Production Data Water-Cut-Simulation Result

FIGURE 9: History matching result of oil rate and water cut.0

50

100

150

200

250

300

350

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

Oil

Rat

e (b

bl/d

ay)

Days

Neat CO2 viscosity 5-fold viscosity 10-fold viscosity 20-fold viscosity

FIGURE 12: Production rate of different CO2 viscosities.

0

4

8

12

16

Neat CO2 viscosity 5-fold viscosity 10-fold viscosity 20-fold viscosity

Oil

Rec

over

y (%

)

CO2 Viscosity

FIGURE 11: Recovery factor of different CO2 viscosities.

0

20

40

60

80

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

Gas

Oil

Rat

io (M

scf/b

bl)

Days

Neat CO2 viscosity 5-fold viscosity 10-fold viscosity 20-fold viscosity

FIGURE 13: Gas-oil ratio of different CO2 viscosities.

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Figures 14 and 15) were used for polymer flooding. We also as-sumed a residual resistance factor (RRF) value of 1.5 at 0.50 lb/stb in this study.

The reservoir performance during PAG was compared with polymer flooding and WAG. Simulation results show that oil re-covery from PAG with a polymer concentration of 0.04 lb/stb is higher than polymer flooding (with a polymer concentration of 0.10 lb/stb for 20 years) and WAG (Figure 16), which indicates that oil recovery increases with polymer injection.

We forecasted the oil production rate for the three different EOR process (Figure 17). The peak oil rate by PAG is higher than WAG and polymer flooding. We can also find that PAG has two oil rate peaks. One is due to gas injection, and the other is the result of polymer injection.

Figure 18 shows the gas-oil ratio of these three processes. Gas production occurs after 7 months of CO2 injection for WAG and PAG. CO2 breakthroughs occur after 2 years injection for the WAG process, while we do not find significant gas breakthrough in PAG process.

results of WAG, cO2 Viscosifier and PAG for Other Sections

Similar results were reached through simulation for the other four sections. Oil recovery would increase by approximately 16.20, 7.20, 10.27, 7.30 and 13.50% for the five sections, ST88, ST48, ST59, ST78, ST92, respectively (Table 4). The average oil recovery increase by CO2 flooding is 10.89%, and gross CO2 utili-zation and net CO2 utilization were forecasted to be 11.27 Mscf/bbl and 5.40 Mscf/bbl, respectively.

Oil recovery from WAG, CO2 viscosifier and PAG for each sec-tion is compared in Figure 19. As shown in the figure, oil recovery significantly increases in sections ST48, ST59, ST78 and ST88 by CO2 viscosifier and PAG, while oil recovery only increases about 3 to 4.5% in ST92 because of the low permeability (average 30

0

4

8

12

16

20

WAG Polymer Flooding PAG

Oil

Rec

over

y (%

)

Eor Methods

FIGURE 16: Recovery factor of different EOR processes.

0

10

20

30

40

0.000 0.100 0.200 0.300 0.400 0.500 0.600

Poly

mer

Vis

cosi

ty (c

p)

Polymer Concentration (lb/stb)

FIGURE 14: Correlation of polymer concentration versus polymer viscosity.

0

10

20

30

40

50

60

0.00 0.10 0.20 0.30 0.40 0.50 0.60

Roc

k Ad

sorp

tion

(ug/

g)

Polymer Concentration (lb/stb)

FIGURE 15: Correlation of polymer concentration and rock adsorption.

0.00

5.00

10.00

15.00

20.00

25.00

30.00

ST88 ST48 ST59 ST78 ST92 Average

Oil

Rec

over

y (%

)

Sections

WAG PAG 20-fold viscosity

FIGURE 19: Recovery factor of WAG and PAG in five sections.

0

50

100

150

200

250

300

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

Oil

Rat

e (b

bl/d

ay)

Days

Polymer Flooding WAG PAG

FIGURE 17: Production rate of different processes.

0

20

40

60

80

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 G

as O

il R

atio

(Msc

f/bbl

)

Days

WAG

PAG

FIGURE 18: Gas-oil ratio of different processes.

TablE 4: Summary of the five sections. ST88 ST48 ST59 ST78 ST92 average

Recovery increased (%) 16.20 7.20 10.27 7.30 13.50 10.89CO2 utilization (Mscf/bbl) 6.09 16.69 10.83 17.08 6.00 11.27Net CO2 utilization (Mscf/bbl) 3.75 7.95 5.36 7.00 3.14 5.40

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Canadian EnErgy tEChnology & innovation

mD) in this section. Average oil recovery increased by PAG and CO2 viscosifier flooding is 7 to 8% higher than conventional WAG flooding.

DiscussionIn this study, simulation results show that PAG and CO2 vis-

cosifier could increase oil recovery significantly. PAG could use a similar type of polymer to that used in polymer flooding, like Hydrolyzed polyacrylamide (HPAM). However, it is very difficult to find a type of polymer (as viscosifier) that can dissolve in CO2 without co-solvent.

Right now, there is no simulator that can consider the cor-relation between polymer concentration and CO2 viscosity. We just simply increased CO2 viscosity in the model. A new study is needed to develop this type of simulator.

The other method that could model the PAG process is using the K-value in STARS (CMG). Future work may include com-parisons of PAG results between STARS and E100. Then, a core-flooding experiment would be carried out to verify the PAG performance simulated by this study. Synthetic models of WAG in different reservoirs and fluid conditions would be further discussed.

ConclusionsThe following conclusions were made for ST48 and the other

sections based on the simulation work:1. Adding viscosifier to CO2 during the WAG process could

markedly delay gas breakthrough, reduce gas-oil ratio and increase oil recovery.

2. Compared with conventional WAG, oil recovery increased about 7.27% when CO2 viscosity increased 20-fold in ST48.

3. Recovery from PAG is higher than polymer flooding and WAG in ST48.

4. Two oil rate peaks are found in the PAG process: one is due to gas injection and the other is a result of polymer injection.

5. Conventional WAG flooding increases average oil recovery by 10.89%, and gross CO2 utilization and net CO2 utilization were forecasted to be 11.27 Mscf/bbl and 5.40 Mscf/bbl, re-spectively.

6. CO2 viscosifier and PAG flooding are forecasted to increase average oil recovery 7 to 8% more than conventional WAG flooding in the North Burbank Unit.

Unit Conversion Tablebbl × 0.1589 873 = m3

ft × 0.3048 = m˚ F (˚ F -32)/1.8 = ˚ Cmi × 1.609 344 = kmlb × 0.4535 924 = kgft3 × 0.02831 685 = m3

lb/stb × 2,853.01 = ppmpsi × 0.000145 = PaBOPD × 0.1589 873 = m3/day

NOMeNcLAtUreEOR Enhanced oil recoveryEOS Equation of stateHPAM Hydrolyzed polyacrylamide

kv Vertical permeabilitykh Horizontal permeabilityMMP Minimum miscibility pressurePVT Pressure-volume-temperaturePAG Polymer-alternating-gasRRF Residual resistance factorVDP Dykstra-Parsons permeability variation coefficientWAG Water-alternating-gas

AcknowledgementsFinancial support for this study was provided by Chaparral

LLC. The authors wish to thank DeLon Flinchum and Matt Stover for their contribution of ideas and data. Thanks are also due to Steve Guillot, Scott Wehner and Mark Fischer for their sugges-tions on preparing the manuscript.

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and Polymer Injection to Maximize EOR Performance for Heavy Oils; Journal of Canadian Petroleum Technology, Vol. 49, No. 5, pp. 25-33, 2010.

2. HELLER, J.P., DANDGE, D.K., CARD, R.J. and DONARUMA, L.G., Direct Thickeners for Mobility Control of CO2 Floods; SPE Journal, Vol. 25, No. 5, pp. 679-686, 1985.

3. TERRY, R.E., ZAID, A. and WHITMAN, D.L., Polymerization in Supercritical CO2 to Improve CO2/Oil Mobility Ratios; Paper SPE 16270 presented at the SPE International Symposium on Oilfield Chemistry, San Antonio, TX, 4-6 Feb-ruary 1987.

4. MCCLAIN, J.B., BETTS, D.E., CANELAS, D.A., SAMULSKI, E.T., DESIMONE, J.M., LANDONA, J.D. and WIGNALL, G.D., Characterization of Polymers and Amphiphiles in Supercritical CO2 using Small Angle Neutron Scattering and Viscometry; Proceedings of the 1996 Spring Meeting of the ACS, Division of Polymeric Materials, New Orleans, LA, Science and Engineering, Vol. 74, pp. 234-235, 1996.

5. BAE, J.H. and IRANI, C.A., A Laboratory Investigation of Viscosified CO2 Pro-cess; SPE Advanced Technology Series, Vol. 1, No. 1, pp. 166-171, 1993.

6. LANE, R.H., ALI, H.A. AL-ALI and SCHECHTER, D.S., Application of Polymer Gels as Conformance Control Agents for Carbon Dioxide EOR WAG Floods; Paper SPE 164096 presented at the SPE International Symposium on Oilfield Chemistry, The Woodlands, TX, 8-10 April 2013.

7. ENICK, R.M., OLSEN, D.K., AMMER, J.R. and SCHULLER, W., Mobility and Conformance Control for CO2 EOR via Thickeners, Foams, and Gels—A Lit-erature Review of 40 Years of Research and Pilot Tests; Paper SPE 154122 presented at the SPE Improved Oil Recovery Symposium, Tulsa, OK, 14-18 April 2012.

8. KULKARNI, M.M. and RAO, D.N., Experimental Investigation of Miscible and Immiscible Water-Alternating-Gas (WAG) Process Performance; Journal of Petroleum Science and Engineering; Vol. 48, Nos. 1-2, pp. 1-20, 2005.

9. MAJIDAIE, S., KHANIFAR, A., ONUR, M. and TAN, I.M., A Simulation Study of Chemically Enhanced Water Alternating Gas (CWAG) Injection; Paper SPE 154152 presented at the SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 16-18 April 2012.

10. JOHNSON, C.L., Burbank Field—U.S.A. Anadarko Basin, Oklahoma; AAPG Special Volumes, in TR: Stratigraphic Traps III, pp. 333-345, 1992.

11. HUNTER, Z.Z., North Burbank Unit Water Flood - Progress Report, January 1, 1956; API Drilling and Production Practices, pp. 262-273, 1956.

12. RIGGS, C.H., Burbank floods promise 180 million barrels of oil; Oil and Gas Journal, November 1, pp. 88-92, 1954.

13. Core Data, Calumet Oil Company, 2006 14. TCHUISSEU DIEUTCHOU, V., Overpressuring and Seal Structure of Penn-

sylvanian Red Fork Formation in the Anadarko Basin: Oklahoma; Oklahoma State University, OK, 1995.

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CETI-13-033. Anthropogenic CO2 for EOR in the North Burbank Unit. CETI April 2014 2(1): xx-xx. Submitted 05 November 2013; Revised 13 March 2014; Accepted xx April 2014.

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Canadian EnErgy tEChnology & innovation

Weirong Li is currently a Ph.D student in the Petroleum Engineering Department at Texas A&M University. Li worked for Petrochina as a reservoir engineer from 2007 to 2010. Li holds an M.S. degree in petroleum en-gineering from the Research Institute of Petroleum Exploration and Development, China, and a B.S. degree in petroleum engineering from Northeast Petroleum University, China. Li has focused his research in areas in-volving numerical simulation of chemical flooding and gas flooding.

Dr. David S. Schechter received his B.S. degree in chemical engineering from the University of Texas at Austin (1984) and his Ph.D. in physical chemistry from Bristol University, England (1988). He was a postdoc-toral research associate and Acting Assistant Professor at Stanford University from 1989 – 1993. Dr. Schechter was a Senior Scientist at the Petroleum Recovery Research Center at New Mexico Tech from 1993 – 2000. During that time, he was an adjunct professor in chemical engineering. He is currently Associate Professor of Petroleum Engineering at Texas A&M University. Dr. Schechter is author and Principal Investigator for a De-partment of Energy/National Petroleum Technology Office Class III Field Demonstration CO2 project in the naturally fractured Spraberry Trend Area, although his interests extend to all facets of characterization, reser-voir engineering and enhanced oil recovery and/or sequestration by CO2 injection. Dr. Schechter has 23 years of direct experience with CO2, including everything from basic laboratory studies to development of full field CO2 floods.

Authors’ Biographies