Geologic Sequestration in Saline Formations Frio Brine ... Papers/05...2 8 9 0. 2 89-3 0 7 0. 3 07-3 2 5 0. 3 25- 0. 3 4 3 0. 3 43-3 6 1 0. 3 61- 0. 3 7 9 0. 3 79-3 9 7 Porosity (fraction)

$Page 1: Geologic Sequestration in Saline Formations Frio Brine ... Papers/05...2 8 9 0. 2 89-3 0 7 0. 3 07-3 2 5 0. 3 25- 0. 3 4 3 0. 3 43-3 6 1 0. 3 61- 0. 3 7 9 0. 3 79-3 9 7 Porosity (fraction)$
Geologic Sequestration in Saline Formations Frio Brine Storage Pilot Project, Gulf Coast, Texas

GCCC Digital Publication Series #05-04g

M. H. Holtz K. Fouad P. Knox

S. Sakurai J. Yeh

Cited as: Holtz, M.H., Fouad, K., Knox, P., Sakurai, S., and Yeh, J., Geologic sequestration in saline formations: Frio Brine Storage Pilot project, Gulf Coast, Texas: presented at the National Energy Technology Laboratory Fourth Annual Conference on Carbon Capture and Sequestration, Alexandria, Virginia, May 2-5, 2005. GCCC Digital Publication Series #05-04g, pp. 1-34.

Keywords: Frio Depositional Systems, Sandstone Lithology, Seismic Mapping, Property Distribution, Interpolation

Bureau of Economic GeologyGeologic Sequestration in Saline Formations

Frio Brine Storage Pilot Project, Gulf Coast Texas

Geologic Sequestration in Saline Geologic Sequestration in Saline FormationsFormations

Frio Brine Storage Pilot Project, Gulf Frio Brine Storage Pilot Project, Gulf Coast TexasCoast Texas

Mark H. Holtz ,Khaled Fouad, Paul Knox, Shinichi Sakurai,Mark H. Holtz ,Khaled Fouad, Paul Knox, Shinichi Sakurai,and Joseph Yehand Joseph Yeh

Gulf Coast Carbon CenterGulf Coast Carbon Center

The University of Texas at AustinThe University of Texas at Austin

Bureau of Economic Geology

Frio Brine Pilot :Tapping the Potential for Large Volume Sequestration

Frio Brine Pilot :Tapping the Potential for Large Volume Sequestration

Project Goal: Early success in a high-permeability, high-volume sandstone representative of a broad area that is an ultimate target for large-volume sequestration.

•Demonstrate that CO2 can be injected into a brine formation without adverse health, safety, or environmental effects.

•Determine the subsurface distribution of injected CO2 using diverse monitoring technologies.

•Demonstrate validity of conceptual models.

•Develop experience necessary for success of large-scale CO2 injection experiments.


OutlineOutline

• Geologic setting• Depositional system and lithology’• Structure• Petrophysical properties• Aquifer model• Conclusions


Regional Geological SettingRegional Geological Setting


Texas Gulf Coast Regional Geologic Setting

Texas Gulf Coast Regional Geologic Setting

Pilot site


Shelf, prodelta, and upper slope

Basinward limit of Frio paleomargin

Slope system

Major fluvial axis

Minor fluvial axis

Shore-zone system

Delta systemFloodplain and lacustrine

Greta/CarancahuaBarrier/Strandplain System

Modified from Galloway (1986)

0 100 mi

Frio Depositional SystemsTexas Gulf Coast

Frio Depositional SystemsTexas Gulf Coast

Pilot Site


OutlineOutline



Injection well Observation well

Top A ss

Top B ss

Top C ss

Injectionzone

Anahuac shale•MFS 43

•MFS 44

•MFS 45

•MFS 47



Upper C Sandstone Core DescriptionUpper C Sandstone Core Description

Rew

orke

d flu

vial

cha

nnel

Dis

tribu

tary

chan

nel



““C” SANDSTONEC” SANDSTONEISOPACHISOPACH

Pilot area


Frio Sandstone LithologyFrio Sandstone Lithology

•General Frio Lithology•Subarkose( > 70 % quartz, and Feldspar)


OutlineOutline



Reconnaissance: Seismic Resolution

•Area of 3-D: •Square Miles: 13.46•Acres: 8600•Shot in the early 1990’s•Dynamite source•Bin Size: 82.5 X 82.5 ft

•Resolution:•Max Freq: 80 Hz•Tuning thickness: 43 ft

•Calibration:•2 sonic logs•One Check shot

•Surfaces Mapped•Top of Anahuac•Base o Anahuac•Maximum flooding surface 47


Structure ComponentsStructure Components


Seismic MappingTime structure on top of MFS-43

Seismic MappingTime structure on top of MFS-43

InjectorMonitor

Salt dome


OutlineOutline



Upper Gulf Coast Frio PorosityUpper Gulf Coast Frio Porosity

0

50

100

150

200

250

300

0.091

-0.109

0.109

-0.127

0.127

-0.145

0.145

-0.163

0.163

-0.181

0.181

-0.199

0.199

-0.217

0.217

-0.235

0.235

-0.253

0.253

-0.271

0.271

-0.289

0.289

-0.307

0.307

-0.325

0.325

-0.343

0.343

-0.361

0.361

-0.379

0.379

-0.397

Porosity (fraction)

Num

ber o

f Sam

ples

Injection well core mean

Injection well core range


Permeability DistributionUpper Gulf Coast Frio Formation

Permeability DistributionUpper Gulf Coast Frio Formation

0

100

200

300

400

500

600

700

800

Permeability (md)

Geometric mean 243 md

Frio injection well core


Permeability VariabilityPermeability Variability

Dykstra Parson Coefficient Probability Plot: Injection Well Core Data

y = 0.0135x + 2.4089R2 = 0.7005

00.5

11.5

22.5

33.5

4

0 20 40 60 80 100

Probability (%)

Log

k

DP = 0.15


Permeability-Porosity relationshipUpper Gulf Coast Frio Formation

Permeability-Porosity relationshipUpper Gulf Coast Frio Formation

Porosity - Permeability Relationship

10

100

1000

10000

0.000 0.100 0.200 0.300 0.400 0.500Porosity (fraction)

Perm

eabi

lity

(md)

Series1injection well


Vertical/Horizontal Relationship as a Function of Porosity

Vertical/Horizontal Relationship as a Function of Porosity

y = 22.679x - 5.3601R2 = 0.6817

0.2

0.4

0.6

0.8

1

0.24 0.25 0.26 0.27 0.28 0.29 0.3Porosity (fraction)

kV/k

H

kV/kH Arith. Mean: 0.622Porosity (Boyle's law) Arith. Mean: 0.2638kV/kH geo. Mean: 0.5602

Porosity is 0.28; when the ratio equals 1.0


Anahuac Shale CharacterAnahuac Shale Character

•Entry pressure nearly 4,000 psi•Bulk Mineralogy

•41 % clay• 28 % quartz•20 % calcite•12% other

•Clay Mineralogy•75 % illite/smectite• 11 % illite &mica•11 % kaolinite•3% chlorite

0

10,000

20,000

30,000

40,000

50,000

60,000

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00

Wetting phase saturation (fraction)

Cap

illar

y pr

essu

re (p

si)

Sample 3ASample 2ASample 1A

0.082 md, 0.108 φ

2.74 md, 0.174 φ0.093 md, 0.11 φ


Capillary Pressure CharacterUpper Frio Formation

Capillary Pressure CharacterUpper Frio Formation

0.00

1000.00

2000.00

3000.00

4000.00

5000.00

6000.00

0.000 0.100 0.200 0.300 0.400 0.500 0.600 0.700 0.800 0.900 1.000

Wetting phase saturation (fraction)

Pres

sure

(psi

)

Clean Sandstone Shaly SandstoneDepth 5051.2Permeability 44.8 mdPorosity 0.244Swi = 0.53

Depth 5051.75Permeability 837 mdPorosity 0.308Swi = 0.08


Comparison of Frio Sgr With Published Data

Comparison of Frio Sgr With Published Data

y = -0.3136Ln(x) - 0.1334R2 = 0.8536

0

0.2

0.4

0.6

0.8

1

0 0.1 0.2 0.3 0.4 0.5 0.6Porosity (fraction)

Res

idua

l gas

sat

urat

ion

(frac

tion)

Gas Residual saturation to water (fraction)

Frio Barrier bar

Log. (Gas Residual saturation to water(fraction))

N = 143


Relationship Between Natural Gamma and Porosity

Relationship Between Natural Gamma and Porosity

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.00 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00 90.00 100.00

Core gamma ray

Poro

sity

(fra

ctio

n)

Shale

Sandstone


Liberty Vshale–Porosity ModelLiberty Vshale–Porosity Model

r = – 0.91r = – 0.91

φsc = 0.357 – 0.3824 * Vshφsc = 0.357 – 0.3824 * Vsh

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1Vshale (fraction)

Shal

e co

rrec

ted

poro

sity

(fra

ctio

n)


OutlineOutline



Proportional Cell-Layering Character Applied to Liberty Model

Proportional Cell-Layering Character Applied to Liberty Model

Proportionallayering

Genetic unit(Sequence)Boundaries

A Sandstone

B Sandstone

Upper C

Lower C


Property DistributionProperty Distribution

Adds direction to intragenetic-unit heterogeneity

1) Geologic template (object modeling)1) Gross sandstone thickness2) Facies template3) Net pay thickness

2) Trend weighting1) High-percentage weighting is applied to primary

direction2) Low-percentage weighting is applied to

secondary direction


Net Sandstone Distribution ModelingC Sandstone

C Sandstone

Geologic trend weighting

Bulk volume shaleLow High

Study area


Basic Attribute InterpolationBasic Attribute Interpolation

Key attribute model(1) Interpolate one key attribute(2) Calculate remaining attributes on the basis of

key attributeVsh is key attribute used

(1) Other attributes derived for key attribute• Porosity• Absolute horizontal permeability• Absolute vertical permeability• Residual gas saturation


Reservoir ModelReservoir Model

Porosity

A sandB sandC sand


SummarySummary

• Test site is a highly faulted, steeply dipping, fluvial-deltaic environment.

• Sandstone is a subarkose– moderately sorted – fine grained– Poorly cemented

• Reservoir quality is dependent on bulk volume shale– Clean sandstones are highly porous and permeable

• Shale is Illite/Smectite mix• Residual saturation modeled as a function of porosity• Pilot site is typical of the Upper Gulf Coast Frio

Documents

Geologic Sequestration in Saline Formations Frio Brine ... Papers/05...2 8 9 0. 2 89-3 0 7 0. 3 07-3 2 5 0. 3 25- 0. 3 4 3 0. 3 43-3 6 1 0. 3 61- 0. 3 7 9 0. 3 79-3 9 7 Porosity (fraction)