using oil fields for the disposal of concentrate · using oil fields for the disposal of...

Please Pass the Salt:Using Oil Fields for the Disposal

of Concentrate

Robert E. MaceTexas Water Development Board

Jean-Philippe NicotBureau of Economic Geology

September 29, 2004Bureau of Reclamation

The problem:

• Communities interested in desalination need a cost-effective and safe solution for disposing of concentrate.

A possible solution:

• Inject concentrate into depleted oil fields.

Goal of the project:To develop the scientific foundation upon which we cansupport recommended policy change to allow an easierapproval path for permitting concentrate injection wells in oil fields.

• Show location of oil fields across state that may be potential injection sites.

• Show through physical and geochemical modeling that oil fields can accept concentrate.

• Make a recommendation on how to streamline permitting.

TECHNICAL APPROACHTECHNICAL APPROACHIdentify depleted oil and gas fieldsIdentify depleted oil and gas fieldsHistorical perspective on fluid injection in Historical perspective on fluid injection in oil and gas fields in Texasoil and gas fields in TexasCharacteristics of analysis areasCharacteristics of analysis areasCharacteristics of concentratesCharacteristics of concentratesFormation damageFormation damage

ScalingScalingClay sensitivityClay sensitivity

Formation damage controlFormation damage controlInjection ratesInjection rates

IDENTIFYIDENTIFYDEPLETED OIL AND GAS DEPLETED OIL AND GAS

FIELDSFIELDS

0 100 200 300 mi

0 100 200 300 400 km

Major oil reservoirsMajor gas reservoirs

N

Aquifer

Injection Formation

Formation Pressure Head

Minimum 500-ft Separation

Depth to BUQW

WaterWell

OilWell Ground Surface

Aquifer

Injection Formation

Formation Pressure Head

Minimum 500-ft Separation

Depth to BUQW

WaterWell

OilWell Ground Surface

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Pressure Depletion and AORPressure Depletion and AORMinTOF - MaxBUQW; Permian Basin

0%

5%

10%

15%

20%

25%

30%

-5000

-3500-200

0-500100025

0040

00550070

0085

00

Separation (ft)

Per

cent

N=436

MinTOF - MaxBUQW; Anadarko Basin

0%

5%

10%

15%

20%

25%

30%

-5000-350

0-200

0-50010

00250040

0055

00700085

00

Separation (ft)

Per

cent

N=18

MinTOF - MaxBUQW; East Texas Basin

0%

5%

10%

15%

20%

25%

30%

-5000-350

0-200

0-50010

00250040

0055

00700085

00

Separation (ft)

Per

cent

N=139

MinTOF - MaxBUQW; Fort Worth Basin

0%

5%

10%

15%

20%

25%

30%

-5000-350

0-2000 -500100025

00400055

00700085

00

Separation (ft)

Per

cent

N=285

MinTOF - MaxBUQW; Maverick Basin

0%

5%

10%

15%

20%

25%

30%

-5000

-3500-200

0-500100025

0040

00550070

0085

00

Separation (ft)

Per

cent

N=121

MinTOF - MaxBUQW; Southern Gulf Coast Basin

0%

5%

10%

15%

20%

25%

30%

-5000

-3500-200

0-5

0010

00250040

005500700085

00

Separation (ft)

Per

cent

N=356

67% 50% 57%

63% 36% 56%% values represent percentage of fields candidates for a AOR variance

Why Do We Care about Pressure Why Do We Care about Pressure Depletion?Depletion?

Create opportunity to inject fluid with little Create opportunity to inject fluid with little risk of exceeding maximum pressure that risk of exceeding maximum pressure that can be sustained by reservoircan be sustained by reservoirSimplify Area of Review ProcessSimplify Area of Review ProcessField production history guarantees Field production history guarantees surface infrastructure needed to move surface infrastructure needed to move around fluidsaround fluids

Major Oil and Gas ReservoirsMajor Oil and Gas Reservoirs

0 100 200 300 mi

0 100 200 300 400 km


N

1

234

5

6

Analysis AreasAnalysis Areas

1 Anadarko1 Anadarko2 Permian2 Permian3 East Texas3 East Texas4 Fort Worth4 Fort Worth5 Maverick5 Maverick6 Southern 6 Southern

Gulf CoastGulf Coast

SelectedSelectedStratiStrati--

graphic graphic ColumnsColumnsin Texas in Texas with Oil with Oil

ProductionProduction��

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Target FormationsTarget Formations

Anadarko B.: Anadarko B.: Granite Wash Fm.Granite Wash Fm.

Permian B.:Permian B.:San Andres Fm.San Andres Fm.

East Texas B.:East Texas B.:Woodbine Fm.

Fort Worth B.:Fort Worth B.:Atoka Fm.Atoka Fm.

Maverick B.:Maverick B.:San Miguel/San Miguel/OlmosOlmos Fm.Fm.

Southern Gulf Coast B.:Southern Gulf Coast B.:Frio Fm. Woodbine Fm. Frio Fm.

PressurePressure--depleted Fieldsdepleted FieldsSouthern Gulf Coast Basin

BHP = (1/465)DR2 = 0.975

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

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

Bottom Hole Pressure (psig)

Dep

th b

elow

Gro

und

Surf

ace

(ft)

East Texas Basin

D=(1/0.460)DR2 = 0.84

0

1,000

2,000

3,000

4,000

5,000

6,000

0 500 1,000 1,500 2,000 2,500 3,000


Dep

th b

elow

Gro

und

Surf

ace

(ft)

Permian Basin

BHP= (1/0.403)DR2 = 0.409

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

0 500 1,000 1,500 2,000 2,500 3,000


Dep

th b

elow

Gro

und

Surf

ace

(ft)

HISTORICAL HISTORICAL PERSPECTIVEPERSPECTIVE

ON OIL AND GAS ON OIL AND GAS FIELDS IN TEXASFIELDS IN TEXAS

Water Injection in Water Injection in Oil&GasOil&Gas FieldsFieldsReservoir drive mechanisms in Reservoir drive mechanisms in oil&gasoil&gas fields:fields:

Water driveWater driveGas cap driveGas cap driveSolution gas driveSolution gas drive

Pressure maintenance and Pressure maintenance and waterfloodingwaterflooding with with fresh, brackish, or produced watersfresh, brackish, or produced watersFresh water needs no treatment before Fresh water needs no treatment before injectioninjectionFresh water reduces or eliminates scaling in Fresh water reduces or eliminates scaling in pipes but could generate pipes but could generate downholedownhole scaling scaling and/or fine pluggingand/or fine plugging

Source for figure: http://www.kgs.ukans.edu/Publications/Oil

Injection Historical DataInjection Historical Data

Data compilation up to 1982Data compilation up to 1982

0

2

4

6

8

10

12

Anadark

o B.

Permian B

.

East Texa

s B.

Fort Wort

h B.

Maveric

k B.

Sth. Gulf C

oast B

.Cum

ulat

ive

Inje

ctio

n (b

illio

n bb

ls)

Water >3,500ppmWater <3,500ppm

0

5

10

15

20

25

30

35

Anadark

o B.Perm

ian B.

East Texa

s B.

Fort Wort

h B.

Maveric

k B.

Sth. Gulf C

oast B

.All D

istric

tsCum

ulat

ive

Inje

ctio

n (b

illio

n bb

ls)

Water >3,500ppmWater <3,500ppm

From RRC database (1982) – last year with data compilation

ConclusionsConclusions

Oil and Gas industry in Texas has an Oil and Gas industry in Texas has an extensive experience with fluid injectionextensive experience with fluid injectionFluids include fresh, brackish and saline Fluids include fresh, brackish and saline waterswaters

Source: Hycal.com

SELECTSELECTANALYSIS AREASANALYSIS AREAS

0 100 200 300 mi

0 100 200 300 400 km


N

0 100 200 300 Miles

Injection Well Depth

<3450 ft

3451 - 6100 ft

>6100 ft

Counties with unmet needs

§

0 250 500125 Miles

Analysis Area Selection CriteriaAnalysis Area Selection Criteria

Counties with depleted oil/gas fieldsCounties with depleted oil/gas fieldsCounties with a predicted shortfall of water Counties with a predicted shortfall of water supply over the next 50 yearssupply over the next 50 yearsCounties with brackish ground water Counties with brackish ground water resourcesresourcesCounties with injection wells not too deepCounties with injection wells not too deep

County Water NeedsCounty Water Needs

Cities

County Water NeedsMetUnmet

0 100 200 300 Miles

Target Locations

Source: TWDB, 2002 Water for Texas

Water Quality of Shallow GroundwaterWater Quality of Shallow Groundwater

Blue = Fresh water < 1,000 mg/L TDSYellow = 1,000–3,000 mg/L TDSOrange = 3,000–10,000 mg/L TDSRed = > 10,000 mg/L TDS From LBJ Guyton

Associates (2003)

Target Brackish Water SourcesTarget Brackish Water Sources

Anadarko B.: Anadarko B.: Ogallala Ogallala AqAq..DockumDockum AqAq..Permian B.:Permian B.:Ogallala Ogallala AqAq..DockumDockum AqAq..East Texas B.:East Texas B.:CarrizoCarrizo--Wilcox Wilcox AqAq.

Fort Worth B.:Fort Worth B.:Trinity Trinity AqAq..

Maverick B.:Maverick B.:CarrizoCarrizo--Wilcox Wilcox AqAq..

Southern Gulf Coast B.:Southern Gulf Coast B.:Gulf Coast Gulf Coast AqAq.. .

CHARACTERISTICSCHARACTERISTICSOFOF

ANALYSIS AREASANALYSIS AREAS

Important ParametersImportant ParametersLithologyLithology/Mineralogy:/Mineralogy:

Rock typeRock typeMineral in contact with flowing fluidsMineral in contact with flowing fluidsClay content and natureClay content and nature

Formation water compositionFormation water compositionFlow properties:Flow properties:

Porosity, permeabilityPorosity, permeabilityOther fluid present (relative permeability)Other fluid present (relative permeability)

Field characteristicsField characteristicsPay thicknessPay thicknessGeothermal gradientGeothermal gradientAverage pressure and depthAverage pressure and depth

Mineralogical CharacteristicsMineralogical Characteristicsof Analysis Areasof Analysis Areas

BasinBasin Rock TypeRock Type Important MineralsImportant Minerals

AnadarkoAnadarko SilicoSilico--clasticclastic Feldspars, quartz, claysFeldspars, quartz, clays

PermianPermian CarbonateCarbonate Calcite, dolomiteCalcite, dolomite

East TexasEast Texas SilicoSilico--clasticclastic Feldspars, quartz, claysFeldspars, quartz, clays

Fort WorthFort Worth SilicoSilico--clasticclastic Quartz, feldsparsQuartz, feldspars

MaverickMaverick SilicoSilico--clasticclastic Quartz, feldsparsQuartz, feldspars

S. Gulf CoastS. Gulf Coast SilicoSilico--clasticclastic Feldspars, quartz, claysFeldspars, quartz, clays

Porosity/PermeabilityPorosity/Permeabilityof Analysis Areasof Analysis Areas

East Texas Basin

10

100

1000

10000

15 20 25 30 35 40

Porosity (%)

Perm

eabi

lity

(md)

Permian Basin

0.1

1

10

100

1000

0 5 10 15 20 25

Porosity (%)

Perm

eabi

lity

(md)

Southern Gulf Coast Basin

10

100

1000

10000

15 20 25 30 35 40

Porosity (%)

Perm

eabi

lity

(md)

Fort-Worth Basin

1

100

10000

0 5 10 15 20 25 30

Porosity (Percent)

Perm

eabi

lity

(mD

)

Median and Range of Median and Range of Porosity/PermeabilityPorosity/Permeability

BasinBasin Porosity (%)Porosity (%) Permeability Permeability ((mDmD))

AnadarkoAnadarko ~12 (4 ~12 (4 -- 20)20) ~20 (6 ~20 (6 –– 65)65)

PermianPermian ~9.3 (<3 ~9.3 (<3 -- >20)>20) ~5 (1 ~5 (1 -- >100)>100)

East TexasEast Texas ~25 (20 ~25 (20 -- >35)>35) ~500 (15 ~500 (15 -- >3,000)>3,000)

Fort WorthFort Worth ~14.5 (6 ~14.5 (6 –– 28)28) ~20 (1 ~20 (1 -- >1,000>1,000

MaverickMaverick ~25 (19 ~25 (19 --32)32) ~30 (3 ~30 (3 -- >2,000)>2,000)

S. Gulf CoastS. Gulf Coast ~25 (<15 ~25 (<15 -- >35)>35) ~305 (20 ~305 (20 -- >1,000)>1,000)

CHARACTERISTICSCHARACTERISTICSOFOF

CONCENTRATESCONCENTRATES

2 MGD Oceanside, CA RO Installation

12 MGD Sarasota, FL EDR plantFrom R.W. Beck

ConcentrateConcentrateMost feed water TDS between 1,000 and Most feed water TDS between 1,000 and 3,000 mg/L3,000 mg/LConcentration factor of 4 (all ions have the Concentration factor of 4 (all ions have the same rejection rate)same rejection rate)Closed system (no equilibration with COClosed system (no equilibration with CO22))Two cases:Two cases:

Addition of Addition of antiscalantantiscalantAddition of Addition of antiscalantantiscalant and sulfuric acid to a and sulfuric acid to a pH=6pH=6

Difficulty in obtaining minor element (Difficulty in obtaining minor element (SiSi, , Fe, Fe, BaBa, , SrSr) concentrations) concentrations

FORMATION DAMAGEFORMATION DAMAGE

Formation Damage DefinitionsFormation Damage Definitions

A condition that occurs when barriers to A condition that occurs when barriers to flow develop in the nearflow develop in the near--wellborewellbore region. region. Results in lower than expected production Results in lower than expected production rate from (or injection rate into) rate from (or injection rate into) Any process causing a reduction in the Any process causing a reduction in the natural inherent productivity or natural inherent productivity or injectivityinjectivity of of a producing or injection wella producing or injection well

Mechanical Formation DamageMechanical Formation DamageOrigin: injected suspended solids, formation Origin: injected suspended solids, formation fine migration plugging pore throatsfine migration plugging pore throats

Fines bridgedat pore

restrictions

Fluid flowMobilefines

Mod. From Michael DixonOMNI Laboratories, Inc.

Chemical Formation DamageChemical Formation Damage

Origin1: Origin1: deflocculationdeflocculation of clays, swelling of of clays, swelling of clays due to chemical changes (pH, ionic clays due to chemical changes (pH, ionic makeup) makeup) Origin2: formation of Origin2: formation of scales due to mixing of scales due to mixing of incompatible water and incompatible water and change in environmental change in environmental conditionsconditions

Pore throats

Pore

Pore throats

Pore

Flocculated

Deflocculated

Mod. From Michael DixonOMNI Laboratories, Inc.

SCALINGSCALING

UCLA, Cohen et al

What is scaling?What is scaling?

Precipitation of minerals in the Precipitation of minerals in the wellborewellbore or or in the formation.in the formation.Calcite, gypsum, barite, silica (iron oxides, Calcite, gypsum, barite, silica (iron oxides, brucitebrucite, siderite, anhydrite, , siderite, anhydrite, strontianitestrontianite))Term also applies to corrosion productsTerm also applies to corrosion productsFluid injection is typically less scaleFluid injection is typically less scale--prone prone than productionthan production

ApproachApproachCompute concentrate composition with the USGS Compute concentrate composition with the USGS geochemical code PHREEQC using standard geochemical code PHREEQC using standard industry pretreatment and a factor of 4industry pretreatment and a factor of 4Mix in different proportions concentrate with Mix in different proportions concentrate with formation water with the USGS geochemical code formation water with the USGS geochemical code SOLMINEQ (able to handle high salinity fluids)SOLMINEQ (able to handle high salinity fluids)Choose randomly 2x5,000 samples to mixChoose randomly 2x5,000 samples to mixAnalyze statistically (histograms) saturation index for Analyze statistically (histograms) saturation index for relevant minerals of resulting combinationsrelevant minerals of resulting combinationsDetermine the fraction of mixing combinations above Determine the fraction of mixing combinations above the the SISI threshold beyond which threshold beyond which antiscalantsantiscalants are not are not effectiveeffective

Examples of Examples of SISI HistogramsHistogramsPermian Basin - Mixed Water - Calcite SI

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

-1 -0.5 0 0.5 1 1.5 2 2.5 3Saturation Index

Number of bins: 41; Bin size: 0.1; Number of data points: 20,000

Prob

abili

ty

East Texas Basin - Mixed Water - Calcite SI

0.00

0.05

0.10

0.15

0.20

0.25

0.30

-2 -1.5 -1 -0.5 0 0.5 1 1.5 2Saturation Index


Prob

abili

ty

South. Gulf Coast Basin - Mixed Water - Calcite SI

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14



Prob

abili

ty

South. Gulf Coast Basin - Mixed Water - Gypsum SI

0.00

0.02

0.04

0.06

0.08

0.10

0.12



Prob

abili

ty

Permian Basin - Mixed Water - Gypsum SI

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

-1 -0.5 0 0.5 1 1.5 2 2.5 3Saturation Index


Prob

abili

ty

East Texas Basin - Mixed Water - Gypsum SI

0.00

0.05

0.10

0.15

0.20

0.25



Prob

abili

ty

Permian Basin - Mixed Water - Barite SI

0.00

0.00

0.00

0.01

0.01

0.01

0.01

0.01



Prob

abili

ty

East Texas Basin - Mixed Water - Barite SI

0.000.000.000.000.000.000.000.000.000.000.00

-1 -0.5 0 0.5 1 1.5 2 2.5 3 3.5 4Saturation Index

Number of bins: 51; Bin size: 0.1; Number of data points: 320

Prob

abili

ty

South. Gulf Coast Basin - Mixed Water - Barite SI

0.00

0.00

0.00

0.01

0.01

0.01

0.01

-3 -2.5 -2 -1.5 -1 -0.5 0 0.5 1 1.5 2 2.5 3Saturation Index


Prob

abili

ty

South. Gulf Coast Basin - Mixed Water - Silica SI

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

-3 -2.5 -2 -1.5 -1 -0.5 0 0.5 1Saturation Index


Prob

abili

ty

East Texas Basin - Mixed Water - Silica SI

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14



Prob

abili

ty

Permian Basin - Mixed Water - Silica SI

0.00

0.02

0.04

0.06

0.08

0.10

0.12



Prob

abili

ty

With acidified concentrate

Summary of Summary of SISI’’ss of Mixing of Mixing CombinationsCombinations

Most Most SISI are <1 are <1 including including amorphous amorphous (colloidal) silica(colloidal) silicaBarite may be a Barite may be a problem locally (problem locally (SISIis also higher is also higher because of Hbecause of H22SOSO44))

-2-1.5

-1-0.5

0

0.51

1.52

Cal

cite

Anad

arko

G

ypsu

mBa

rite

Cal

cite

Perm

ian

Gyp

sum

Barit

eC

alci

teEa

st T

exas

G

ypsu

mBa

rite

Cal

cite

Fort

Wor

th

Gyp

sum

Barit

eC

alci

teM

aver

ick

Gyp

sum

Barit

eC

alci

teSo

ut.G

ulf C

oast

G

ypsu

mBa

rite

Satu

ratio

n In

dex

Median and 95th percentileWith acidified concentrate

Scaling DiscussionScaling Discussion

Previous results assume thorough mixing Previous results assume thorough mixing between concentrate and formation waterbetween concentrate and formation waterThis is conservative because mixing is This is conservative because mixing is likely to be less than thorough owing to likely to be less than thorough owing to ~piston flow of concentrate displacing ~piston flow of concentrate displacing formation water formation water

CLAY SENSITIVITYCLAY SENSITIVITY

Source: hycal.com

What is Clay Sensitivity?What is Clay Sensitivity?Clay sensitivity is due to the ability of clays to Clay sensitivity is due to the ability of clays to exchange ions with surroundings and/or to exchange ions with surroundings and/or to absorb water (swelling)absorb water (swelling)A change in environmental conditions (ionic A change in environmental conditions (ionic makeup, salinity, pH) may also disperse clay makeup, salinity, pH) may also disperse clay particles (particles (deflocculationdeflocculation))

Before injection, two Before injection, two questions need to be questions need to be answered:answered:

Is there any clay?Is there any clay?What type of clay?What type of clay?

High salinityHigh DivalentLow pH

Low salinityLow DivalentHigh pH

Flocculation

++

+

+

++

----- -

+

+

+

+

+

+

+

-- -

---

Deflocculation

Mod. From Michael Dixon OMNI Laboratories, Inc.

Clay Types in Analysis AreasClay Types in Analysis Areas

BasinBasin Clay Clay AbundanceAbundance Clay TypeClay Type

AnadarkoAnadarko Chlorite, Chlorite, illiteillite , , kaolinitekaolinite

PermianPermian RareRare KaoliniteKaolinite

East TexasEast Texas CommonCommon SmectiteSmectite, , illiteillite, chlorite, , chlorite, kaolinitekaolinite

Fort WorthFort Worth Chlorite, Chlorite, illiteillite, , kaolinitekaolinite

MaverickMaverick AbundantAbundantMxMx--layer layer illiteillite--smectitesmectite,,chlorite, chlorite, kaolinitekaolinite

S. Gulf CoastS. Gulf Coast AbundantAbundant MxMx--layer layer illiteillite--smectitesmectite, , smectitessmectites, , kaolinitekaolinite

Clay Sensitivity PrinciplesClay Sensitivity Principles

10

100

1,000

10,000

0% 10% 20% 30%

Divalent Cations (% of TCC)

Tota

l Cat

ion

Con

cent

ratio

n (m

eq/L

)

SmMxIlKa

Ka=kaoliniteIl=illiteMx=mixed layers; Sm=smectiteTCC=Total Cation Conc.

Any water inside the delineated domain will deflocculate the corresponding clay at equlibrium.

Possible cation stripping and deflocculation in the transient stage

Frio Formation - South Texas - San Patricio Cty

1

10

100

1000

10000

0% 5% 10% 15% 20% 25% 30%

Divalent Cations (% of TCC)To

tal C

atio

n C

once

ntra

tion

(meq

/L)

SmMxIlKa

<4,000ft <5,000ft <6,000ft <7,000ft<9,000ft <11,000ft >11,000ft no depth data

Plot mod. from Scheuerman and Bergersen, 1990, SPE Paper No. 18461

MAR Study: East TX B. Analysis A.MAR Study: East TX B. Analysis A.Carrizo-Wilcox and Woodbine Formations

1

10

100

1000

10000

0% 10% 20% 30% 40% 50% 60% 70%

Divalent Cations (% of TCC)

Tota

l Cat

ion

Conc

entra

tion

(meq

/L)

East Texas Basin - CZWX Concentrate MAR / Woodbine Fm. MAR

0.00

0.05

0.10

0.15

0.20

0 0.5 1 1.5 2 2.5 3Mass Action Ratio (MAR) Ratio

Number of bins: 31; Bin size: 0.1; Number of trials: 100,000P

roba

bilit

y

MAR Ratio =MAR Ratio ={[Na]{[Na]22/[Ca]}/[Ca]}concconc/ {[Na]/ {[Na]22/[Ca]}/[Ca]}formformIf MAR Ratio <0.5, problems areIf MAR Ratio <0.5, problems areexpected for expected for smectitesmectite clayclay

FORMATION DAMAGE FORMATION DAMAGE CONTROLCONTROL

Chemical and Physical SolutionsChemical and Physical SolutionsMatrix Matrix acidizingacidizing by by HClHCl, H, H22SOSO44 (both for (both for carbonates), HF (for silicates), organic acids carbonates), HF (for silicates), organic acids Treatment with KOH and Treatment with KOH and NaOHNaOH (for calcium (for calcium sulfate)sulfate)CaClCaCl22 brine treatment (to limit clay sensitivity). brine treatment (to limit clay sensitivity). NaClNaCl and and KClKCl. Clay stabilizers that bind clays . Clay stabilizers that bind clays to the substrateto the substrate

Hydraulic fracturingHydraulic fracturingHeat treatment (?)Heat treatment (?)

Damaged Zone

Mod. From Michael Dixon, OMNI Laboratories, Inc.

Operational SolutionsOperational SolutionsSurface treatment to remove suspended Surface treatment to remove suspended solidssolidsLower flow rate, increase perforation Lower flow rate, increase perforation densitydensityGradual change in salinity to avoid salinity Gradual change in salinity to avoid salinity shockshockInjection of a buffer solutionInjection of a buffer solutionOxygen scavengers, Oxygen scavengers, antiscalantantiscalant

INJECTION RATESINJECTION RATES

Injection Rate IssuesInjection Rate Issues

Maximum injection Maximum injection rate controls number rate controls number of wells neededof wells neededInjection rate is Injection rate is dependent on dependent on formation parameters:formation parameters:

Average Injection Rate Distribution

0

25

50

75

100

125

150

175

200

<25 150 275 400 525Average Injection Rate (gpm)

Number of bins: 22; Bin size: 25 gpm; Number of data points: 390

Freq

uenc

y

Maximum Injection Rate Distribution

0

25

50

75

100

125

150

175

200

<25 150 275 400 525Maximum Injection Rate (gpm)

Number of bins: 22; Bin size: 25 gpm; Number of data points: 437 including 10 points >525 gpm

Freq

uenc

y

⎟⎟⎠

⎞⎜⎜⎝

⎛= 2

2.25lnb4π

∆rckt

kQP

µφµ

(Limited sampling of injection wells)

Computed Injection RatesComputed Injection RatesAnadarko Basin - Computed Maximum Injection Rate

0.000.100.200.300.400.500.600.700.800.901.00

0 500 1000 1500 2000 2500 3000 3500Maximum Injection Rate (gpm)

Number of bins: 36; Bin size: 100 gpm; Number of trials: 10,000

Prob

abili

ty

West Texas Basin - Computed Maximum Injection Rate

0.00

0.100.20

0.30

0.400.50

0.60

0.700.80

0.90

<100 500 1000 1500 2000 2500 3000 3500Maximum Injection Rate (gpm)


Prob

abili

ty

East Texas Basin - Computed Maximum Injection Rate

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

<100 500 1000 1500 2000 2500 3000Maximum Injection Rate (gpm)


Prob

abili

ty

Fort Worth Basin - Computed Maximum Injection Rate

0.00

0.100.20

0.30

0.400.50

0.60

0.700.80

0.90


Number of bins: 36; Bin size: 100 gpm; Number of trials: 10,000Pr

obab

ility

Maverick Basin - Computed Maximum Injection Rate

0.00

0.100.20

0.30

0.400.50

0.60

0.700.80

0.90



Prob

abili

ty

Southern Gulf Coast Basin - Computed Maximum Injection Rate

0.00

0.05

0.10

0.15

0.20

0.25

<100 500 1000 1500 2000 2500 3000Maximum Injection Rate (gpm)


Prob

abili

ty

median = 13.2 gpm; 95th = 153 gpm


median = 278 gpm; 95th = 9,038 gpm


median = 466 gpm; 95th = 3,347 gpm


Injection Rate ConclusionsInjection Rate Conclusions1 MGD of concentrate:1 MGD of concentrate:

Is equivalent to 695 Is equivalent to 695 gpmgpmWould require a couple of wells in the eastern Would require a couple of wells in the eastern half of the state in recent formationshalf of the state in recent formationsWould require one or several well clusters in Would require one or several well clusters in the the paleozoicpaleozoic formationsformations

Injection rate can be augmented by Injection rate can be augmented by screening the pay thickness and screening the pay thickness and stimulating the wellstimulating the well

Summary of Technical ConclusionsSummary of Technical ConclusionsA significant fraction of the wells would A significant fraction of the wells would qualify for a variance of AORqualify for a variance of AORScaling can be mitigated with standard Scaling can be mitigated with standard approaches (acidification, approaches (acidification, antiscalantantiscalant))Clay sensitivity may be a local issue for Clay sensitivity may be a local issue for several fields. It could be dealt with but at several fields. It could be dealt with but at a pricea priceMultiple wells/well clusters are needed to Multiple wells/well clusters are needed to accommodate concentrate output of a accommodate concentrate output of a typical planttypical plant

Policy procedures:

• Met with RRC and TCEQ• Met with EPA Region 6 and headquarters• Talked with other states about their

solutions• Researched permitting and permitting

options

Current permitting process:

• History• Class I• Class II• Class V

Possible permitting paths:

• Non-hazardous Class I• Class II• Class V• Dual-permitted wells• General permit, Class I• Special Class I• Change Federal regulations

using oil fields for the disposal of concentrate · using oil fields for the disposal of...

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