Types of Storage (Mechanisms) and Lessons Learned from SECARB's Citronelle Storage Site

7/28/2019 Types of Storage (Mechanisms) and Lessons Learned from SECARB's Citronelle Storage Site

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George Koperna, VP

Advanced Resources International, Inc.

Types of Storage (Mechanisms) and Lessons

Learned from SECARB's Citronelle Storage Site

RECS Friday, June 21, 2013


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This presentation is based upon work supported by the Department of EnergyNational Energy Technology Laboratory under DE-FC26-05NT42590 and wasprepared as an account of work sponsored by an agency of the United StatesGovernment. Neither the United States Government nor any agency thereof, norany of their employees, makes any warranty, express or implied, or assumes any

legal liability or responsibility for the accuracy, completeness, or usefulness of anyinformation, apparatus, product, or process disclosed, or represents that its usewould not infringe privately owned rights. Reference herein to any specificcommercial product, process, or service by trade name, trademark, manufacturer,or otherwise does not necessarily constitute or imply its endorsement,recommendation, or favoring by the United States Government or any agency

thereof. The views and opinions of authors expressed herein do not necessarilystate or reflect those of the United States Government or any agency thereof.

Acknowledgement


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1. Introductions2. What do we need to know?3. Types of traps4. Example: SECARB5. Questions, Comments, Discussion

Order of Presentation


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Porous media and natural porous formations areheterogeneous, i.e., they display spatial variability of

their geometric and hydraulic properties.

Furthermore, this variability is of irregular and

complex nature. It generally defies a precisequantitative description, either because ofinsufficiency of information or because of the lack of

interest in knowing the very minute details of the

structure and flow field.

Dagan, 1989

Introduction


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Its not impossible, however


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Data,

Data,Data,

Data, and more Data

So what do we need to know?


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Define the Project scope: Enhanced recovery vs. single/multiple point injection


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LithologySo what do we need to know?


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Geologic Trap:


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Reservoir continuity:

SPE 88720

Source: AAPG Memoir 50


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Reservoir andfluid properties:


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Okay, we have the data!(now what?) Lets calculate CO2 injectivity (Saline Aquifer):

Depth = 3,425 ft. Temperature = 95.5 F Thickness = 250 ft. Permeability = 40 md Porosity = 13% Injection pressure = 0.6 psi/ft. KEY ASSUMPTION: Unconfined Reservoir


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Okay, we have the data!(now what?)

Governing Equation:

Although a fairly rigorous treatment, it is a wholelot more complicated than this!

qsc=(2-1)kh

TPtqsc= CO2 injection rate (MMscfd)

2 = pseudo pressure (E+6psia2/cp)


k = permeability (md)

h = thickness (ft)

= constant

T = temperature (R = F + 460)

Pt = 1/2(ln tD+0.80907)

(result) 117.5

303

191

40

250

1.422x106

556

12.0

Where:


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Can we really inject 118 MMscfd?


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Is unconfined flow the correct approximation?

Size of the container is veryimportant!

Area

mi2CO2 Injection Rate

MMscfd

5 1.3

25 7.2

100 15.6

400 19.0

Infinite 117.5


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Relative permeability

SPE 134028 (Bennion and Bachu, 2010)


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Buoyancy

Vertical permeability and continuity controlbuoyancy.


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Structural/Stratigraphic Trapping Solubility (in Oil/in Water) Mineral Trapping Pore Volume Trapping Adsorption

Reservoir trapping mechanisms


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Structural/stratigraphic trapping

u Most likely a depleted/depleting oil/gas reservoir Trapped oil/gas for geologic time! Lots of data Lots of hydraulic fracs?

u Will have a spill point


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Formation waters CO2 is soluble in water and oil The amount of CO2 ultimately dissolved in a liquid is

affected by several factors:

Temperature Pressure Water salinity Reservoir heterogeneity Density inversion

CO2 solubility


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CO2 solubility

Effect of

temperatureand pressureon CO2

solubility


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CO2 solubility

Effect of salinity

on CO2solubility


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CO2 solubility

CO2 solubility in oil reservoirs is a multiple-contact (miscible) process (CO2-EOR).

CO2 will vaporize the lighter oil fractions into theinjected CO2 phase and CO2 will condense into

the reservoirs oil phase.

Result is lower viscosity, mobility and interfacialtension.


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There are two main types of CO2-EOR processes: Miscible CO2-EOR is a multiple contact process involving

interactions between the injected CO2 and the reservoirs oil,which leads to two reservoir fluids that become miscible (mixing inall parts), with favorable properties of low viscosity, enhanced

mobility, and low interfacial tension. The objective is to remobilizeand reduce the residual oil saturation in the reservoirs pore spaceafter water flooding. Miscible CO2-EOR is by far the mostdominant form of CO2-EOR.

Immiscible CO2-EOR occurs when insufficient reservoir pressureis available or the reservoirs oil composition is less favorable(heavier). The main mechanisms involved are: (1) oil phaseswelling, as the oil becomes saturated with CO2 ; (2) viscosityreduction of the swollen oil and CO2 mixture; (3) extraction oflighter hydrocarbon into the CO2 phase; and, (4) fluid drive pluspressure.

What is CO2-EOR?


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JAF01981.CDR

Zone ofEfficient Sweep

Purchased CO2Anthropogenic and/or

Natural Sources

InjectedCO2

Immobile Oil

Immobile Oil

RecycledCO2from

Production Well

COStoredin PoreSpace

2CO Dissolved (Sequestered)in the Immobile

Oil and Gas Phases

2

DriverWater

WaterMiscibleZone

OilBank

AdditionalOil

RecoveryCO2 CO2

What is CO2-EOR?

Advanced Resources InternationalSource: Advanced Resources International


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Profiles for CO2 Injection and OilProduction in CO

2

-EOR

Oil Production (Barrels)

CO2 Injection (Tonnes)

Start of CO2Injection

Start CO2EOROil Production

Point of Economical

Production Shut-down

Time from CO2 Injectionto Oil Production

Time

Time

Source: Bellona, 2005

Purchased CO2

Recycled CO2

JAF028275.PPT


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CO2 solubility

Oil swelling is also an important storagemechanism.

Laboratory work on the Bradford Field (Pennsylvania)oil reservoir showed that the injection of CO2, at 800psig, increased the volume of the reservoirs oil by

50%.

Similar laboratory work on Mannville D Pool(Canada) reservoir oil showed that the injection of 872scf of CO2 per barrel of oil (at 1,450 psig) increasedthe oil volume by 28%, for crude oil already saturated

with methane.


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CO2 solubility


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CO2 solubility (density inversion)


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Mineral trapping is the permanent sequestration of CO2through chemical reactions with dissolved species and matrixminerals.

Through field studies and numerical modeling it has beendetermined that CO2 is primarily trapped through precipitation

of: calcite (CaCO3), siderite (FeCO3), dolomite (CaMg(CO3)2),

dawsonite (NaAlCO3(OH)2) (Xu et al. 2001, 2002, 2003).

In order for mineral trapping through carbonate precipitation tooccur, primary minerals rich in Mg, Fe, Na and Ca, such asfeldspars and clays, must be present.

Immature sands having an abundance of fresh rock fragments(unweathered igneous and metamorphic minerals and claysrich in Mg, Fe and Ca) are most effective (Bachu et al. 1994,Pruess et al. 2001, Xu et al. 2001, 2002, 2003).

Mineral trapping


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There are two mechanisms which may naturally trapthe CO2 within reservoir pores:

gas saturation below the critical gas saturation of thereservoir (non-permanent), and

depletion-imbibition hysteresis (permanent).

Pore volume trapping


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u Critical gas saturation determines the minimum saturation of gas that is requiredto initiate flow of the gas through the reservoir pore space.


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u Sequestration through relative permeability hysteresis isprimarily a post-injection phenomenon due to the differencesbetween drainage (production) and imbibition (injection) gasrelative permeability.

Think CO2-EOR WAG processes!u Injectivity losses range from 40 to 80% of pre-CO2 water

injection rates in W. TX.

strong hysteresis of the non-wetting phase!



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Adsorption


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Desorption of Methane and Adsorption of

CO2 in Shales and Coals is Similar

Methane adsorbed on kerogen and clay mineral surfaces Organic-rich gas shales preferentially adsorb CO2, replacing

methane Free (non-adsorbed) gas in fracture porosity, intergranular

microporosity, micro-pores in kerogen


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Storage reservoirs will: Rise and dip; Thin and thicken; Come and go; and Have variable reservoir parameters.

Such as porosity, permeability and fluid saturations. These changes in the reservoir may impact:

Pressure; Temperature; Relative permeability;

Etc.

The only way to truly approximate subsurface flow with anydegree of accuracy is with numerical computer models.

Heterogeneity


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Injection without recovery Type curves Empirical formulations (Darcys Law) Detailed reservoir models

Enhanced recovery modeling Streamtube models (CO2-EOR) Coalbed models (ECBM) Black oil models (Depleted oil/gas, w/o mixing) Compositional models (CO2-EOR)

Next generation models?

Well, what can we do?


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SECARB Example: Storage Overview

The CO2 capture unit at Alabama Powers(Southern Co.) Plant Barry becameoperational in 3Q 2011.

A newly built 12 mile CO2 pipeline from Plant

Barry to the Citronelle Dome completed in 4Q2011.

A characterization well was drilled in 1Q 2011to confirmed geology.

Injection wells were drilled in 4Q 2011.

100k 300k metric tons of CO2 will be injectedinto a saline formation beginning 3Q 2012.

3 years of post-injection monitoring.

Project Schedule and Milestones


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Assuring Safe Injection:Start with a Good Storage Site

Proven four-way closure atCitronelle Dome.

Injection site located withinCitronelle oilfield where existing welllogs are available

Deep injection interval (PaluxyFormation at 9,400 feet) Numerous confining units Base of USDWs ~1,400 feet Existing wells cemented through

primary confining unit

No evidence of faulting or fracturing,based on oilfield experience, newgeologic mapping and interpretationof existing 2D seismic lines.


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Collected new geologic data on the Paluxy reservoir andconfining unit with the drilling of the projects three new wells:

Characterization Well (D-9-8#2) 98 feet of whole core (two intervals) plus45 sidewall cores.

Injection Well #1 (D-9-7#2) 68 feet of whole core plus 32 sidewall cores Injection Well #2 (D-9-9#2) 44 feet of whole core Full set of open hole logs on all three wells (quad combo, MRI, spectralgamma, mineralogical evaluation, waveform sonic, cement quality, pulsed

neutron capture)

Baseline vertical seismic profiles and crosswell seismic collected in Feb2012

Results of characterization effort confirm that the test sitegeology is adequate Safe injection site unfaulted, structural trap, thick confining unitAttractive for injection porosity, permeability, reservoir extent

Geological Characterization


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The Paluxy Formation is a Good Injection Target


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Construction of Geological Model

260+ net feet of clean sand Average porosity of 18% Average permeability of 200 md Normal pressure and

temperature gradients

Based on detailed characterizationof the Paluxy sand/shale interval,20 sandstone units may be targetsfor CO2 injection:

CO2 Injector(Well D9-7#2)


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Reservoir Simulation to Guide Injection Design

CO2 plume extent10 years after end of injection Inject into 10 thickest sands (170 ft

thick)

Inject at maximum injection rateduring for three years (500 tonnesper day).

Plume area in topmost sand is0.35mi2 (225 acres)

Most of the CO2 enters the upperPaluxy sands due to higherpermeability and injection gradient

Model results used to determineUIC Area of Review

These results are used to designinjection (well design, completionprogram, monitoring program)


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Integration - Communication is key!


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AL Department of Environmental Management (ADEM) Air Permit Capture unit operation

Army Corps of Engineers permit Wetlands Impacts Covers wetland impacts due to pipeline and injection site construction Pipeline crosses 15 acres of wetlands

Horizontal drilling under wetlands is preferred over open-cutting andmitigation Wetland impacts during well pad construction operations (fill) mitigated after

well drilling completed

U.S. Fish and Wildlife permit Threatened and EndangeredSpecies Potential impacts to threatened species (gopher tortoises) Over 30 gopher tortoise burrows encountered long pipeline easement Directional drilling under tortoise burrows/colonies is preferred over temporary

relocation

SHPO (State Cultural/Archaeological Assets)

Permitting = time & $


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ADEM Underground Injection Control (UIC)Permit Protect Underground Sources of

Drinking Water (USDWs)

A Class V Experimental Well permit has been sought forthe following reasons Short duration of injection (3 years) Modest volumes of CO2 (less than 2% of Plant Barrys annual

CO2 output)

Characterization and modeling of stacked CO2 storage CO2 Injection Under Real World Conditions Demonstration of innovative monitoring tools and methods

The Big oneUIC Class V


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After comments by EPA, most Class VI (CO2sequestration well) standards were applied

Injection Area of Review (AOR) determined by annualmodeling

Periodic AOR updates based on monitoring and modelingresults

Extensive deep, shallow and surface CO2 monitoring Monthly reporting of injection pressures, annular pressures

and injection stream composition

Injection stream monitoring Periodically updated Corrective Action Plan Open-ended permit duration (based on USDW non-

endangerment demonstration) Pressurized annulus throughout injection Emergency and remedial response plan Post-injection site care plan

UIC Class V


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Expect the Unexpected: Turtle $oup!

U.S. Fish and Wildlife permit andNEPA compliance mandate the

protection of threatened and

endangered species

Potential impacts to an threatenedspecies and its habitat (GopherTortoise)

Over 100 tortoise burrows encounteredlong pipeline easement

Directional drilling under tortoiseburrows/colonies less expensive than

temporary relocation Burrows identified at or near most wellsites

Avoid drilling/monitoring activities inproximity to burrows


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Permitting: This Stuff Takes a While

UIC Class V Experimental Well permit application submitted inDecember 2010

Short duration of injection (3 years) and modest volumes of CO2 CO2 Injection Under real world operating conditions Demonstration of experimental monitoring tools and methods

Most Class VI (CO2 sequestration well) standards were applied Injection Area of Review (AOR) determined by modeling and monitoring results;updated annually Extensive deep, shallow and surface CO2 monitoring Injection stream monitoring Periodically updated Corrective Action Plan Site closure based on USDW non-endangerment demonstration (5-yr. renewal) Pressurized annulus throughout injection (+/- 200 psig)

Class V Experimental injection permit was awarded in November2011, eleven months after initial draft application

Permission to operate request submitted in April 2012; awarded inAugust 2012


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The End Result


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Baseline

1 year

Injection

2 years

Post

3 years

MVA will continue for duration

APR 2011 to AUG 2012 SEPT 2012 to SEPT 2014 OCT 2014 to SEPT 2017


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MVA Sample Locations

One (1) Injector (D-9-7 #2) Two (2) deep Observation

wells (D-9-8 #2 & D-9-9 #2)

Two (2) in-zone & above zoneMonitoring wells (D-4-13 &D-4-14)

One (1) PNC logging well(D-9-11)

Twelve (12) soil flux monitoringstations


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Seismic: Baseline Crosswell

Survey Parameters

Source Type: Piezoelectric Receiver type: Hydrophone 10 levels Source & Receiver interval: 10 feet Sweep length: 2.6 sec (record length 3 sec)Survey Results

High resolution image between injectionwell & observation well (~10 feet verticalresolution)

No reservoir or confining unit discontinuitiesobserved

Good CO2 confinementNext Steps Full VSP ~ 25 30 feet resolution MBM VSP~ 50 feet resolution Scheduling time lapse seismic this spring

hopefully to see CO2


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Reservoir Response

D-4-13 has a potentially bad gauge that will be

re-calibrated or replaced

630,000 data points 7 month deployment

Pressure spike JAN 2012 acrossall 4 gauges

Small pressure spike observedconsistent with the MITs

Downhole pressure quicklystabilized to pre-test levels,indicating no residual effects &packer integrity.


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Reservoir Response

630,000 data points 7 month deployment

Slight pressure increase(previous slide)

Slight temperature decrease

We dont believe we are seeing CO2 Scheduling more MVA this spring Expect fluid movement, not CO2


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D-9-8#2 Downhole Pressure Gauge Data

Consistent & expected pressure increases in zone At 9,441 feet and at 9,416 feet

System remains elastic bouncing back when shut in This springs shut in should reveal more


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Pressure & Injection Rate Response

Consistent pressure inD-4-13 & 14 (above the

injection zone, 3,500 feet

away

Expected downhole pressure

response in MW D-9-8#2

consistent with CO2 injection

rate (900 feet from the D-9-7#2

injector)

We have a good capacity, injectivity,and no apparent formation damage

We have good seal We have good MVA data to confirm


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Questions Comments Concerns

Q & A What else?


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Office Locations

Washington, DC

4501 Fairfax Drive, Suite 910Arlington, VA 22203Phone: (703) 528-8420

Fax: (703) 528-0439

Houston, TX11931 Wickchester Ln., Suite 200Houston, TX 77043

Phone: (281) 558-9200Fax: (281) 558-9202

Knoxville, TN603 W. Main Street, Suite 906

Knoxville, TN 37902Phone: (865) 541-4690Fax: (865) 541-4688

Cincinnati, OH

1282 Secretariat CourtBatavia, OH 45103Phone: (513) 460-0360

Email: [email protected]

http://adv-res.com/

Thank you for your attention!


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Backup & Supporting Slides


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Selecting the Correct Formulation of the ContinuityEquation:

u What do we know?

Injection of carbon dioxide gas at super-criticalconditions into a liquid-filled, possibly infiniteaquifer.

u What do we want to find out? The 10-year carbon dioxide injection rate into

the aquifer.

A Means of Calculating Unconfined GasFlow Through Porous Liquid-Filled Media


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Diffusivity Equation for Single-Phase Gas Flow(in terms of real gas potential / pseudo pressure)

k tr r r

cg 1 r=

In this form, the formulation is unusable and requires assumptions about thereservoir boundaries (boundary conditions) to generate a useful form of theequation. Where pseudo-pressure may be calculated for any pressure rangeas follows:

izi

2p p=

p

0


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Pseudo-PressureEast Bend Reservoir

0.0E+00

2.0E+04

4.0E+04

6.0E+04

8.0E+04

1.0E+05

1.2E+05

1.4E+05

1.6E+05

1.8E+05

2.0E+05

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000

Pressure, psia

2p/mu-z,psia/cp

Cumulative area under this curve

to any pressure representsthe pseudo-pressure at that pressure

East Bend Reservoir

0.0E+00

2.0E-02

4.0E-02

6.0E-02

8.0E-02

1.0E-01

1.2E-01

1.4E-01

1.6E-01

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000

Pressure, psia

mu-z,cp

East Bend Reservoir

0.0E+00

2.0E+08

4.0E+08

6.0E+08

8.0E+08

1.0E+09

1.2E+09

1.4E+09

1.6E+09

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000

Pressure, psia

Pseudo-Pressure,psia

2/cp


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u Since the diffusivity is a second order partialdifferential equation with respect to radius (r), weneed 2 boundary conditions.

u It is first order in time, so one boundary conditionwith respect to time will be necessary.

u Domain of interest: An infinitely large system with one well located in the center.

u r = rw at the wellboreu r = at the reservoir boundaryu P = Pi at r = u P = Pi at t = 0 for any r

u Solution Using the above boundary conditions, we are able to solve the flow

equation in terms of dimensionless variables.

Boundary Conditions


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Boundary Condition Solution

qD

Tqsckhi=

PD 1 Ei rD2

2 4tD=

tD ktcrw2

=

rD rrw

=PD i - wf

qDi=


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Solution Calculate tD and perform Check

tD ktcrw2

=

tD (2.637E-4)(40 md)(10*365*24 hrs)

(0.13)(0.0675 cp)(7.9E-5 psia-1)(0.33 ft)2=

tD = 12.2E+9

If 1/(4tD)


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Solution Log Approximation

qD Tqsc

khi=

PD i - wf

qDi=

PD (well) = Pt = 0.5 * (ln tD + .80907)tD = 12.2E+9Thus, Pt = 12.0

Since Pt = PD:

We can substitute for qD and solve for qsc!

AND


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Final Solution

qsc=(2-1)kh

TPtqsc= CO2 injection rate (MMscfd)



k = permeability (md)

h = thickness (ft)

= constant

T = temperature (R = F + 460)

Pt = 1/2(ln tD+0.80907)*

(result) 117.5

303

191

40

250

1.422x106

555.5

12.0

Below is the resulting flow equation used to calculate the suggested CO2injection rate along with a further explanation of symbols and values used inthe unconfined reservoir scenario:

Where:

At the end of 10 years the total volume of injected CO2 will be about 430 Bcfand the radius of investigation will be approximately 600 mi2.


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Comparison to Confined (Simulated) Cases

uIn addition to calculating the 10-year carbon dioxide injection rate for anunconfined reservoir, sophisticated simulations using COMET3 were alsoperformed to explore the 10-year injection behavior in the following confinedareas:

Area

mi2

CO2 Injection Rate

MMscfd

5 1.3

25 7.2

100 15.6

400 19.0

Infinite* 117.5

*Simulation with an

infinite aquiferachieved about 40MMscfd due tochanges relativepermeability effectsand other reservoir

properties that changewith time.


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Discussion of MVA programHow do we measure trapping?


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Elements of the MVA Program

Shallow MVA Groundwater sampling (USDW Monitoring) Soil Flux PFT Surveys

Deep MVA Reservoir Fluid sampling Crosswell Seismic Mechanical Integrity Test (MIT) CO2 Volume, Pressure, and Composition analysis Injection, Temperature, and Spinner logs Pulse Neutron Capture logs Vertical Seismic Profile

MVA Experimental tools


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MVA Sample Locations

One (1) Injector (D-9-7 #2) Two (2) deep Observation

wells (D-9-8 #2 & D-9-9 #2)

Two (2) in-zone & above zoneMonitoring wells (D-4-13 &D-4-14)

One (1) PNC logging well(D-9-11)

Twelve (12) soil flux monitoringstations


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Baseline

1 year

Injection

2 years

Post

3 years

MVA Frequency

APR 2011 to AUG 2012 SEPT 2012 to SEPT 2014 OCT 2014 to SEPT 2017

MVA Tests


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MVA Testsand Their Frequencies (1)

MeasurementTechnique

MeasurementParameters

Application UIC RequiredFrequency

Status

Reservoir andabove-zonepressure

downhole pressuregauges

Key measurement forassessing the injectionpressure field and for

regulatory compliance.Above-zone monitoring to

detect leakage through theconfining unit

Constant duringinjection operations,annually post-

injection

(2) Panex gauges runD-9-8#2 with MBM inMarch 2012; MRO

gauges run in D-9-13and D-4-14 in June

2012

Cased-holepulsed neutronlogging

Neutron capture as afunction of CO2saturation buildup

CO2 saturation buildup nearnew and existing wellbores.Demonstrates CO2 plume

migration and monitor forabove-zone leakage

One baselinedeployment, annuallyduring injection, bi-

annually post-injection

Baseline logs run onD-4-13, D-4-14,D-9-7#2, D-9-8#2 and

D-9-9#2.

Time-lapseseismic(crosswell and/or

vertical seismicprofiling)

CO2 induced changefrom baseline sonicvelocity and amplitude

Distribution of CO2 plumevertically and horizontally

One baselinedeployment, oncepost-injection

Baseline VSPacquired in Feb 2012;baseline crosswell

acquired in Jan 2012

Reservoir fluidsampling

Pressurized fluidsamples taken from theinjection zone. Analyze

for pH, and selectedcations and anions

Geochemical changes toinjection zone that occur asa result of CO2 injection

Semi-annually duringinjection phase,annually post-

injection

D-9-8#2 Baselinesamples taken via U-Tube on June 12

2012; Kuster samplestaken in March and

June 2012

MVA Tests


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MeasurementTechnique MeasurementParameters Application UIC RequiredFrequency Status

Drinking wateraquifer (USDW)monitoring

Alkalinity, DIC,DOC, selectedcations and anions

Monitoring of USDWs forgeochemical changesrelated to shallow CO2

leakage.

Quarterly duringand post-injection

Baseline USDW samplesacquired and analyzed inFeb, March and July

2012

Injection well annularand tubing pressure

Pressure gaugeslocated on thewellhead to monitor

casing annular andtubing pressure

Annular pressure is anindication of wellboreintegrity. Tubing pressure

assures regulatorycompliance with maximum

injection pressure

Constant duringinjection operationsand post-injection

Gauges installed, to betied into Denburys dataacquisition system

Soil CO2 Flux Mass of CO2emitted from thesoil per unit time

and area

Monitor for anomalousincreases in the amount ofCO2 that is emitted from the

soil surface as an indicationof CO2 leakage

Quarterly duringand post-injection

(12) soil flux stations inplace. Monitoring beganin Dec 2011. Eleven field

deployments to date

Perfluorocarbon

tracers (PFTs)introduced in the CO2

stream

Measure tracer

levels near theground surface

around new andpre-existing oilfield

wells

Monitor for the presence of

tracer buildup nearwellbores which would

suggest leakage of CO2

Single baseline,

annually during andpost-injection

Baseline sampling on

Sept 11, 2012 at theD-9-1, D-9-2, D-9-3,

D-9-6, D-9-7, D-9-8,D-9-9, D-9-10 and D-9-11

well locations

MVA Testsand Their Frequencies (2)


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Shallow MVA

Shallow water sampling Quarterly

Soil Flux sampling continuous

PFT Surveys annually


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Reservoir Fluid sampling - annually Crosswell Seismic Base/Inj/Post Mechanical Integrity Test (MIT) - annually CO2 Volume, Pressure, & Composition

analysis - continuous

Injection, Temperature, & Spinner logs -annually

Pulse Neutron Capture logs - annually Vertical Seismic Profile - annually

Deep MVA

D 4-14 Observation Wellbore

Documents

Types of Storage (Mechanisms) and Lessons Learned from SECARB's Citronelle Storage Site