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  • Simulation and Experimental Investigations of CO2 Injection in Both

    Conventional (Wellman Unit) and Unconventional Reservoirs

    Department of Petroleum Engineering

    Texas A&M University

    Dr. David Schechter

    19th Annual CO2 Flooding Conference

    Midland, TX

    December 12th, 2013

  • CO2 Oil Recovery

    Observations

    CO2 EOR recovers oil very effectively Its limited by the availability of CO2 The laboratory and simulation research technology is aimed at

    improving the utilization of CO2 (areal and vertical sweep efficiency) through mobility control)

    Research into gravity stable floods (Wellman Unit) The research technology is improving prediction of processing

    rates (net utilization and gross utilization - Mscf CO2/bbl EOR) with dimensionless curves for H2O and CO2

    The big prize is utilizing CO2 in the ROZ & countless boom wells in unconventional liquid reservoirs (ULR)

  • Mobility Control with Viscosifier Sweep Efficiency after 0.5 PV Injected

    Pure CO2

    Dodecamethylpentasiloxane Viscosified CO2 Flood

    Fracture

    Shuzong Cai, 2011

  • Bottom Water Drive

    Original Reservoir Conditions

    Sec. Gas

    Cap

    Prod Prod

    Bottom Water Drive

    Before Waterflooding (1979)

    Prod Prod

    WIW WIW

    Bottom Water Drive

    Waterflooding (Before CO 2 Flood),1983

    CO2 ICO2 I

    WIWWIW

    Prod Prod

    Waterflood and CO2 Injection (1995)

    Bottom Water Drive

    Bottom Water Drive

    Original Reservoir Conditions

    Bottom Water Drive

    Original Reservoir Conditions

    Sec. Gas

    Cap

    Prod Prod

    Bottom Water Drive

    Before Waterflooding (1979)

    Prod Prod

    WIW WIW

    Bottom Water Drive

    Waterflooding (Before CO 2 Flood),1983

    CO2 ICO2 I

    WIWWIW

    Prod Prod

    Waterflood and CO2 Injection (1995)

    Bottom Water Drive

    CO2 ICO2 I

    WIWWIW

    Prod Prod

    Waterflood and CO2 Injection (1995)

    Bottom Water Drive

    WIWWIW

    Prod Prod

    Waterflood and CO2 Injection (1995)

    Bottom Water Drive

    Bottom Water Drive

    Original Reservoir Conditions

    Bottom Water Drive

    Original Reservoir Conditions

    Sec. Gas

    Cap

    Prod Prod

    Bottom Water Drive

    Before Waterflooding (1979)

    Prod Prod

    WIW WIW

    Bottom Water Drive

    Waterflooding (Before CO 2 Flood),1983

    CO2 ICO2 I

    WIWWIW

    Prod Prod

    Waterflood and CO2 Injection (1995)

    Bottom Water Drive

    CO2 ICO2 I

    WIWWIW

    Prod Prod

    Waterflood and CO2 Injection (1995)

    Bottom Water Drive

    WIWWIW

    Prod Prod

    Waterflood and CO2 Injection (1995)

    Bottom Water Drive

    Bottom Water Drive

    Original Reservoir Conditions

    Bottom Water Drive

    Original Reservoir Conditions

    Sec. Gas

    Cap

    Prod Prod

    Bottom Water Drive

    Before Waterflooding (1979)

    Prod Prod

    WIW WIW

    Bottom Water Drive

    Waterflooding (Before CO 2 Flood),1983

    CO2 ICO2 I

    WIWWIW

    Prod Prod

    Waterflood and CO2 Injection (1995)

    Bottom Water Drive

    WIWWIW

    Prod Prod

    Waterflood and CO2 Injection (1995)

    Bottom Water Drive

    CO2 ICO2 I

    WIWWIW

    Prod Prod

    Waterflood and CO2 Injection (1995)

    Bottom Water Drive

    WIWWIW

    Prod Prod

    Waterflood and CO2 Injection (1995)

    Bottom Water Drive

    Chronological Stages of Depletion

  • Simulation Model

    H2O Inj

    CO2 Inj

    OWOC

    H2O Inj

    CO2 Inj

    OWOC

    H2O Inj

    CO2 Inj

    OWOC

    Grid System

    Use of flexible grids: corner point, non - orthogonal geometry.

    K, direction subdivided in 23 layers based on porosity correlations (geological description)

    27 x 27 gridblocks I,J direction

    Full field, 3-D black oil simulation Imex CMG

    Total 16,767 gridblocks

  • Permeability

    Use previous estimations from correlations between open logs and core measurements

    K = 10^(0.167 * Core porosity 0.537)

    Relationship may not be representative due to fractures and vugular porosity

    Water Saturation

    Simulation Model Input Data

    Swc, aprox 20% for = 8.5%Swc, aprox 20% for = 8.5%

  • Use of isopach maps resulted from geological and petrophysical study in 1994

    Geological and stratigraphic correlation (Core vs Log data) Quantify major rock properties Lateral and areal continuity

    Isopach Maps

    60 geological contoured maps from gross thickness, porosity and NTGR were digitized Interpolation between contour allows model to be populated

    Gross Thickness Porosity Net to Gross Ratio

    Simulation Model Input Data

  • Simulation Model 3D Structure Development

  • Measured BHPs for History Matching

    Production data

    Over 45 years of monthly cumulative oil, gas and water production from 47 wells was converted into daily rate schedules for simulation

    Model initially constrained by oil rates and water/CO2 injection rates

    Pressure data

    Pressure measurements reveal good communication within the reservoir Use of BHP corrected and averaged to a common mid-perforation Static BHP seemed to be representative of the average reservoir pressure

    0

    500

    1,000

    1,500

    2,000

    2,500

    3,000

    3,500

    4,000

    4,500

    A-49 M-53 J-57 A-61 S-65 O-69 D-73 J-78 F-82 M-86 M-90 J-94

    Time, years

    Bo

    tto

    m H

    ole

    Pre

    ssu

    re

    (BH

    P),

    P

    si

    Unit 1-1 Unit 2-1 Unit 2-3 Unit 3-3 Unit 4-1 Unit 4-2

    Unit 4-3 Unit 4-4 Unit 4-5 Un it 4-6 Unit 4-7 Unit 5-1

    Unit 5-2 Unit 5-3 Unit 5-4 Unit 5-5 Unit 6-1 Unit 6-2

    Unit 7-1 Unit 7-2 Unit 8-3 Unit 8-5 Unit 8-6 Unit 8-7A

    Individual Static Bottom Hole Pressure

  • a)

    b)

    c)

    1979

    1983

    1995

    Chronological Oil Saturation Distribution

    a) Primary depletion

    b) Waterflooding

    c) CO2 miscible flooding Oil saturation considered overestimated due to the excess of oil production

  • CO2 Recovery Mechanism Gravity Drainage

    To examine the performance of recovery at or near the MMP with CO2 in:

    standard slim tube

    vertically-oriented, bead-packed large diameter tubes

    vertically-oriented reservoir cores at reservoir conditions

    To examine possibility that residual oil exists below the original water-oil contact that could be mobilized by continuation of CO2 injection

  • Wellman Unit Oil Characteristics

    Separator oil taken at 61 oF and 126 psig

    Average molecular weight: 147 g/mol

    GOR: 150 scf/bbl

    Density: 0.8329 g/cm3 @ 100 oF and 1000 psig

    Viscosity: 2.956 cp

  • Recovery vs. Pressure for Different GORs in Slim Tube

    60

    70

    80

    90

    100

    1300 1400 1500 1600 1700 1800 1900Ultim

    ate

    R

    ec

    ove

    ry, %

    OO

    IP

    Pressure, psig

    GOR=150

    GOR=400

    GOR=600

    MMP=1600~1625 psig

  • Recovery Curves for Each Large Diameter Tube Test

    0

    20

    40

    60

    80

    100

    120

    0 20 40 60 80 100 120 140 160 180

    % O

    OIP

    P

    ro

    du

    ce

    d O

    il

    % OOIP of CO2 Injected

    Run A: 1700 psig / gravity stable

    Run B: 1550 psig / gravity stable

    Run C: 1400 psig / gravity stable

    Run D: 1700 psig / gravity stable

    Run E: 1400 psig / gravity unstable

    Run F: 1400 psig / horizontal

  • Cores From Wellman 5-10

    30 whole core from 9400 to 9430

    26 samples for standard core analysis

    3 section for gravity stable CO2 tests

    Helium porosities: 2.4% ~ 12.6%

    Average porosity: 5.8% for 26 samples

    Average water saturation: 42%

  • Schematic Diagram of the Core Holder and ROZ Procedure (Wellman Unit)

    CO2 @ 1650 psig

    BPR

    Oil

    3500 psig

    Confining

    (4) (3) (2) (1)

    Tem

    per

    atu

    re =

    15

    0 o

    F

    Oil @ 1650 psig

    Brine @ 2000 psig Brine @ 1650 psig

    Vugular C

    arbonate C

    ore

    Brine

    BPR

    BPR BPR

  • Oil Recovery From the Wellman Unit Whole Core During CO2-assisted Gravity Drainage at a Pressure of 1650 psig

    1300 1400 1500 1600 1700 1800 1900

    Pressure, psig

    0

    10

    20

    30

    40

    50

    60

    70

    80

    90

    100

    Oil R

    ec

    ove

    ry, %

    OO

    IP

    Slim Tube - 1.2 PV

    Large Diameter

    Tube - 1.2 OOIP

    Whole Core - 1.2 PV

    Whole Core - 2 PV

    Whole Core - 7 PV

    1500 1700

  • Sor From the Wellman Unit Whole Core During CO2-assisted Gravity Drainage at Three Pressures Above and

    Below the MMP

    0

    10

    20

    30

    40

    1400 1500 1600 1700 1800

    Pressure, Psig

    So

    r, %

    Slim Tube Test, GOR=150

    Large Diameter Tube

    Whole Core

  • CO2 Recovery Factors in Whole Core Wellman Unit Gravity Drainage

    Experiment No. 1 2 3

    Core porosity 0.0676 0.066 0.066

    Core permeability, md 15.4 12.7 12.7

    Initial oil saturation 0.47 0.102 0.191

    Oil type Reservoir Oil Separator Oil Separator Oil

    Temperature, oF 150 150 150

    Pressure, psig 1,650 1,543 1,320

    CO2 injection rate, cc/hr 20 10 2

    Oil recovery after 1.2 PV CO2 inj. 0.76 0.51 0.115

    Oil recovery after 2 PV CO2 inj. 0.78 0.57 0.148

    Residual oil saturation 0.09 0.03 0.10

  • Conclusions

    The MMP of W.U. oil is 1600 +/- 50 psig over a range of GORs 150 to 600 scf/bbl;

    Reservoir performance, slim tube, large diameter tube and gravity stable core floods in W.U. whole core at reservoir conditions demonstrate excellent displacement efficiency with Sor after CO2 < 10% for a range of pressures;

  • Conclusions

    Gravity stable core flooding results from transition zone core taken from the W.U. demonstrates that oil not mobilized by water influx in the transition zone can be effectively mobilized with CO2 over a range of injection pressures;

  • Conclusions

    Reducing pressure from above the MMP to near the MMP does not reduce efficiency in laboratory. BHP in the W.U. could be reduced to near the MMP with no reduction in displacement efficiency. The reduction in CO2 purchases would be a positive benefit. The reduction in reservoir pressure is constrained by voidage replacement issues;

  • Conclusions

    CO2 flooding in the W.U. has performed exceptionally well due to gravity stable displacement above MMP. This results in excellent sweep and displacement efficiency. Over 42 bcf of CO2 has been injected and recovered 7.2 MMbbls of tertiary oil. The resulting utilization is 5.83 Mcf CO2 injected per barrel of incremental oil as of the late 90s

  • Enhanced Oil Recovery in ULR CO2 Injection

  • CO2 Oil Recovery

    Objective

    To observe the effect of CO2 into ULR core and the effect that it may have on oil productivity.

  • CO2 Oil Recovery Motivation

    Shale sidewall cores with

    negligible permeability

    Conventional CO2 flooding

    was not possible

    Oil couldnt be recovered

    A totally different approach was required

  • CO2 Oil Recovery

    Shale cores were soaked in CO2

    (2 in)

    Aluminum Core holder Confining Fluid

    Sleeve

    Roll cover Shale core 2

    Glass beads Shale core 1

    Sandstone top

    Core holder was placed horizontally

    Experimental Procedure

    A high permeability media was provided to store CO2 in contact with the shale cores

    Schematic of cores packing

  • CO2 Oil Recovery Experimental Procedure

    Aluminum Core holder

    Glass beads

    Sandstone top

    Roll cover

    Shale core 2

    CO2 injection through the core is not intended

  • CO2 Oil Recovery

    Displacement Equipment Schematic

    Experimental Procedure

    1. Cores were packed, and a confining pressure of 250 psi was applied

    2. The core holder was placed inside a circulating water bath on the CT scanner

    3. Temperature was increased to 150 F 4. CO2 was injected into the system and a pressure of 3000 psi was reached and maintained

    5. The core was scanned regularly to track changes in CT number

    6. Oil production was collected by intervals

  • CO2 Oil Recovery Experimental Equipment

  • New CT Scanner at Texas A&M

    PE Department

  • CO2 Oil Recovery

    0.4 cm3 of oil were recovered

    Results

    First Experiment Test conditions : 3000

    psi, 150 F

    Oil Recovery

    OOIP = Core Volume (1 Swi)

    Porosity (), %

    3 6 S w

    i, %

    0 36 18

    30 51 25

    Different scenarios for recovery factor

  • CO2 Oil Recovery Results

    Core weight

    Mass of Core 1 increased by 0.07 g

    Mass of Core 2 increased by 0.06 g

    Sample 1 Sample 2

    Weight before experiment, g 50.48 45.39

    Weight after experiment, g 50.55 45.45

    Diameter, cm 2.53 2.53

    Length, cm 3.97 3.48

    Bulk volume, cm3 19.94 17.50

    First Experiment Test conditions : 3000

    psi, 150 F

  • CO2 Oil Recovery Results

    CT Number behavior

    1.82E+03

    1.83E+03

    1.84E+03

    1.85E+03

    1.86E+03

    1.87E+03

    0 1 2 3 4 5

    Av.

    CT

    nu

    mb

    er

    Time, days

    Average CT number for both cores

    An increasing trend is observed

    First Experiment Test conditions : 3000

    psi, 150 F

  • CO2 Oil Recovery Results

    CT Images Shale sidewall core 1

    Slice 20

    Slice 30

    2.5 hr 4.3 hr 30.1hr 50.7 hr 58.4 hr 72.5 hr 78.1 hr 95.1 hr 99.1 hr

    First Experiment Test conditions : 3000

    psi, 150 F

  • CO2 Oil Recovery Results

    CT Images Shale sidewall core 2

    Slice 42

    Slice 50

    2.5 hr 4.3 hr 30.1hr 50.7 hr 58.4 hr 72.5 hr 78.1 hr 95.1 hr 99.1 hr

    First Experiment Test conditions : 3000

    psi, 150 F

  • CO2 Oil Recovery

    Since CT number correlates to density

    Results

    0

    10

    20

    30

    40

    50

    60

    0 1000 2000 3000 4000 5000 6000

    Den

    sity

    , lb

    /ft3

    Pressure, psia

    Vapor CO2Supercritical CO2heptanehexanePentaneButane

    2

    T = 150 F

    1

    The experiment was repeated at 1600 psi, where a higher density difference exists

  • CO2 Oil Recovery

    0.4 cm3 of oil were recovered

    Results

    Oil Recovery

    OOIP = Core Volume (1 Swi)

    Porosity (), %

    3 6 S w

    i, %

    0 39 19

    30 55 28

    Different scenarios for recovery factor

    This test was prematurely terminated because of a water leak

    Second Experiment Test conditions : 1600

    psi, 150 F

  • CO2 Oil Recovery Results

    Core weight

    Mass of Core 1 increased by 0.95 g

    Mass of Core 2 increased by 0.86 g

    Sample 1 Sample 2

    Weight before experiment, g 40.09 36.04

    Weight after experiment, g 41.04 36.90

    Diameter, cm 2.53 2.52

    Length, cm 3.62 3.29

    Bulk volume, cm3 18.20 16.42

    Second Experiment Test conditions : 1600

    psi, 150 F

  • CO2 Oil Recovery

    1.50E+03

    1.51E+03

    1.51E+03

    1.52E+03

    1.52E+03

    1.53E+03

    1.53E+03

    1.54E+03

    0 20 40 60 80

    Av.

    CT

    nu

    mb

    er

    Time, hours

    Results

    CT Number behavior Average CT number for sidewall core 1

    A decreasing trend is observed

    Second Experiment Test conditions : 1600

    psi, 150 F

  • CO2 Oil Recovery Results

    CT Images Shale sidewall core 1

    Slice 20

    Slice 30

    5.1 hr 25.4 hr 34.9 hr 43.8 hr 55.4 hr 67.5 hr

    Second Experiment Test conditions : 1600

    psi, 150 F

  • CO2 Oil Recovery Results with CT Number

    Average CT number for sidewall core 2

    Different trends are observed

    Second Experiment Test conditions : 1600

    psi, 150 F

    1.36E+03

    1.40E+03

    1.44E+03

    1.48E+03

    1.52E+03

    1.56E+03

    0 20 40 60 80

    Av

    CT

    nu

    mb

    er

    Time, days

    Slice 1

    1.54E+03

    1.54E+03

    1.55E+03

    1.55E+03

    1.56E+03

    0 20 40 60 80

    Av

    CT

    nu

    mb

    er

    Time, days

    Slice 10

    1.48E+03

    1.50E+03

    1.52E+03

    1.54E+03

    1.56E+03

    0 20 40 60 80

    Av

    CT

    nu

    mb

    er

    Time, days

    Slice11

    1.36E+03

    1.40E+03

    1.44E+03

    1.48E+03

    1.52E+03

    0 20 40 60 80

    Av

    CT

    nu

    mb

    er

    Time, days

    Slice 15

  • CO2 Oil Recovery Results

    CT Images Shale sidewall core 1

    Slice 45

    Slice 50

    5.1 hr 25.4 hr 34.9 hr 43.8 hr 55.4 hr 67.5 hr

    Second Experiment Test conditions : 1600

    psi, 150 F

  • CO2 Oil Recovery What is next ?

    3rd Experiment

    Production Vs. time data Produced oil composition

    Numerical Model

    Sensitivity analysis to understand influence of parameters

  • CO2 Oil Recovery

    Oil production was accomplished by soaking shale cores with CO2 at 3000 psi and 1600 psi. Recovery in both cases is estimated to be from 18 to 55 % of OOIP. The permeability of the cores does not allow for conventional CO2 flooding.

    CT imaging was done during the course of the experiment

    revealing changes inside the sidewall cores.

    Changing the pressure of the test influenced the behavior of CT number, this could be related to the different densities of CO2 at the two experimental conditions.

    More work is required to better understand the mechanisms causing oil production during these tests.

    Conclusions

  • CO2 Oil Recovery New Equipment - Chevron Imaging Lab and Chaparral CO2 EOR Lab

    Frac fluid

    Oil

    Shale Surface

    https://www.dropbox.com/sh/ahddhda60q6gwhr/WzepyENh0G/20131009_175848.jpghttps://www.dropbox.com/sh/ahddhda60q6gwhr/RX6OW0h-ll/20131010_112037.jpghttps://www.dropbox.com/sh/ahddhda60q6gwhr/pevDM1GJb8/20131007_100648 (2).jpghttps://www.dropbox.com/sh/512qk02b95zu2kp/yA-Sw42DK1/20131010_173230.jpghttps://www.dropbox.com/sh/512qk02b95zu2kp/LBC2TJ_SZ0/20131010_173407.jpg

  • CO2 and Enhanced Oil Recovery in Unconventional Liquid Reservoirs

    Department of Petroleum Engineering

    Texas A&M University

    Dr. David Schechter

    Please Join Our Newly

    Established JIP

  • Dimensionless Curves Improving Prediction of CO2 Injection in Conventional Reservoirs

  • Cumulative dimensionless WF

    calculated for each pattern

    Methodology Evaluation of Water-Flood Recovery

    Primary Production DCA Sample: Pattern J-1 (8.5%/yr)

    Primary Production DCA Sample: Pattern J-7 (9%/yr)

    WF recovery = incremental production (over primary)

    Anino Adokpaye 2013

  • Methodology Dimensionless Recovery Curves WF & CO2 Comparisons

    While a pattern is under the initial pure CO2 slug (prior to WAG), DTI = DCI

  • Results & Observations Strong WF & CO2 Correlations

    Initial overlay (perfect correlation) of WF & CO2 recovery - diverge at 10% dim injection. Short-lived waterflood (only 36% DWI-WF) - although, enough to trend for comparison

    PATTERN E-4

    Multiple (3) injector pattern

  • Results & Observations Strong WF & CO2 Correlations

    PATTERN J-5

    WF & CO2 recovery curves remain parallel through 200% dimensionless injection!

    Curves tend to diverge at 20% DEOR

  • CO2 Oil Recovery

    Conclusions

    Results from dimensionless analysis of well-established vintage water and CO2 injection patterns show the usefulness of dimensionless water-flood curves as a basis for prediction of performance under CO2 injection

  • Surfactant Studies in ULR CO2 Injection in Conventional and Unconventional Liquid Reservoirs

    Department of Petroleum Engineering

    Texas A&M University

    Dr. David Schechter

  • Barnett Shale The penetration of anionic surfactant in this particular siliceous shale core is shown in this sequence of fluid in seven cross sectional views of the core before flooding, 0 hours, 30 minutes, 1 hour, 2 hours, 4 hours and 20 hours after flooding. This slice is one of the 18 slices used to create the horizontal view in the previous slice

    Fracture

  • Changing Contact Angles

    Frac Water w/o surfactant: 110

    Frac Water with surfactant: 35

    Frac fluid

    Oil

    Shale Surface

    Oil

    Shale Surface

    Frac fluid

  • Barnett Shale

    Anionic surfactant

    Superior penetration magnitude

    Better matrix penetration spontaneous imbibition

    Best oil recovery

    Low contact angle with oil-saturated shale surface

  • Barnett Shale

    59

    Grey - clay Blue - carbonate Yellow - silica

    8700

  • Contact Angle & IFT Measuring Capabilities

    Static and dynamic contact angles

    Surface and interfacial tension

    Surface free energy of solids and their components

    Temperature control unit to maintain reservoir temperature

    Dataphysics OCA 15 Pro

  • Experiment Design- Contact Angle

    Shale sample

    Capillary Needle

    Captive bubble method