Tab 6 F_ Sandstone Acidizing Chem and Design

Sandstone Acidizing

Outline • • • • • • • •

Sandstone vs. Carbonate Sandstone composition Mineral surface area Reaction of HF with silicates Design methodology Fluid selection Mud Acid, Clay Acid and Organic Clay Acid. Avoid problems Matrix Stimulation Engineering Solutions

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Objectives • • • • • • • • • • • •

Describe the sandstone acidizing process. List the key components in sandstones. State the importance of mineral surface area. Describe the primary, 2nd and tertiary reactions of mud acid with clay. State the major components of spent mud acid. List the incompatible ions with spent mud acid and state why they are incompatible. State the problems associated with illite and chlorite. State the purpose of the each sandstone treatment stage. Describe the fluid selection process. Describe when/why Mud Acid, Clay Acid and OCA are used. Describe Mud Acid, Clay Acid and OCA treatment designs and how they are different. State how to avoid potential problems during a treatment. Matrix Stimulation Engineering Solutions

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Carbonate vs. Sandstone SANDSTONE • Dissolution of the damaging mineral

CARBONATE • A large fraction of the matrix is soluble (>50%)

• A small fraction of the matrix is dissolved

• Dissolution of rock (wormholes) – damage bypass

• Potential precipitation

• Diversion

•Treatment of sandstone with high calcite content (>20%): – Use carbonate design methodology – Use sandstone diversion techniques – Iron control may be a problem Matrix Stimulation Engineering Solutions

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Sandstone Constituents Secondary Cement (Carbonate Quartz)

Quartz

Clays (Pore lining i.e., illite)

*Feldspars

Clays (Pore filling i.e., Kaolinite)

*Chert *Mica

Remaining Pore Space

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Formation Minerals - Silicates Minerals

Chemical Composition

Quartz Quartz

Quartz Quartz

Si0 Si022

Feldspars Feldspars

Orthoclase Orthoclase Microcline Microcline

KAlSi KAlSi33OO88 KAlSi KAlSi3OO8

Albite Albite Plagioclase Plagioclase

Micas Micas Clays Clays

3

8

NaSi NaSi33AlO AlO88 Si Si2-3Al Al1-2OO8(Na,Ca) (Na,Ca) 2-3

1-2

8

Biotite Biotite Muscovite Muscovite

(AlSi (AlSi33OO1010))K(Mg, K(Mg,Fe) Fe)33(OH) (OH)22 (AlSi O ) K(Al) OH) (AlSi3 O10 ) K(Al)2 OH)2

Chlorite Chlorite Kaolinite Kaolinite

+2 +3 (Mg, (Mg,Fe Fe+2, ,Fe Fe+3))66Si Si33AlO AlO1010(OH) (OH)88 Al (Si O )(OH) Al4 (Si4 O10 )(OH)8

Smectite Smectite MixedMixed MixedLayer Mixed--Layer

(AlSi (AlSi33OO1010)Mg )Mg55(Al,Fe)(OH) (Al,Fe)(OH)88 Illite Kaolinite, Kaolinite, Illiteor orChlorite Chloritewith withSmectite Smectite

Illite Illite

3

4

4

10

10

2

2

8

Si Si33AlO AlO1010(OH) (OH)22KAl KAl22

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Formation Minerals Minerals Carbonates

Sulfates

Others

Chemical Composition

Calcite

CaCO3

Dolomite

Ca, Mg(CO3)2

Ankerite

Ca,(Mg,Fe)(CO 3) 2

Siderite

FeCO 3

Gypsum

CaSO4·2H 2O

Anhydrite

CaSO4

Halite Iron Oxides

NaCl

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Reaction Rate - Factors • Mineral Composition & Surface Area • Dominant Factor « Surface Area Mineral

Specific Area

Quartz

Few cm2/g

Feldspar

Few cm2/g

Clays:

Kaolinite

22 m2/g

Illite

113 m2/g

Smectite

82 m2/g

• Reaction Rate: Clays > Feldspars > Quartz Matrix Stimulation Engineering Solutions

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Mud Acids: HCl – HF • Hydrochloric wt% + Hydrofluoric wt%






12 – 3, 12 – 2 13.5 – 1.5 9 –1.5, 9 – 1 6 –1.5, 6 - 1 4.5 – 0.5

• Siliceous minerals Matrix Stimulation Engineering Solutions

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Reaction of Mud Acid (HCl – HF) with Clay +

HF

+

Na or K Primary (5+x) HF + MM-AlAl-Si + (3(3-x+1) H + = HSiF5 + AlFx(3(3--x)+ + M+ + 2H 2O

Clay Spent HF

Secondary X/5 HSiF5 + M-Al-Si + (3-x+1) H+ + H2O =

Si(OH)4

AlFx(3-x)+ + M+ + Si(OH)4 Tertiary AlF2+ + M-Al-Si + (3-x+1) H+ + H2O =

AlF2+ Si(OH) Si(OH) Si(OH)

2AlF2+ + M+ + Si(OH)4 Matrix Stimulation Engineering Solutions

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Precautions to Avoid Precipitates • Potassium fluosilicates K2SiF6 AVOID CONTACT WITH K, Na, Ca

•Calcium fluoride CaF2 •REMOVE CALCITE

•Aluminum fluoride AlF3 MAINTAIN A LOW pH Matrix Stimulation Engineering Solutions

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Hydrated/Amorphous Silica: Cannot Avoid

Si(OH)4

Al

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Former Site of Kaolinite Following Mud Acid Treatment

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Design Methodology to Maximize Stimulation

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Sandstone Acidizing Fluid Stages

Pre-acid Preflush: Overflush: Displaces spent acid away from the critical matrix. Diverter: Preflush: Main Fluid: NH Cl brine or displaces water containing Decreases fluidtoluene/xylene flow thief zone/s and increases flowdamage into HCl organic acid) removes CaCO matrix to prevent the Mud acid removes siltinto andthe clay (alumino-silicate) formation 4 (or 3 from + + ++ incompatible cations (Na , K , Ca ) away from the wellbore. other non-treated zones. precipitation of CaF . 2

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Sandstone Acidizing Fluid Stages

1. Pre-acid Preflush: NH4Cl brine or toluene/xylene displaces water containing incompatible cations (Na+, K+, Ca++) away from the wellbore. 2. Preflush: HCl (or organic acid) removes CaCO3 from matrix to prevent the precipitation of CaF2. 3. Main Fluid: Mud acid (HCl – HF) removes silt and clay (aluminosilicate) formation damage 4. Overflush: Displaces spent acid away from the critical matrix. 5. Diverter: Decreases fluid flow into the thief zone/s and increases flow into other non-treated zones. Matrix Stimulation Engineering Solutions

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Sandstone Acidizing Fluid Selection

Matrix Treatment Design Methodology • • • • • • • •

Candidate Selection Establish Nature and Location of Damage Treating Fluid/Additive Selection Determine Pressure/Injection Rate Establish Fluid Volumes Develop Pumping Schedule and Placement Strategy Define Shut-in/Cleanup Stages Economics Assess Productivity and Profitability Matrix Stimulation Engineering Solutions

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Fluids Available •

Hydrochloric acid – Preflush – Main acid component – Overflush

•

Hydrofluoric acid systems – Mud Acid – Organic Mud Acid – Fluoboric Acid (Clay Acid) – Organic Fluoboric Acid (OCA)

•

Organic Acids – Formic – Acetic – Citric

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Selection Criteria • Formation mineralogy – Reactivity • Chemical composition • Surface area – Rock Structure • HCl solubility • Clay distribution – Sensitivity • Deconsolidation • Precipitation • Fines release

• Permeability – Type of damage – Mobility of induced damage • Produced Fluids – Oil wells: Sludge/Emulsions – Gas wells: Water saturation • Temperature – Corrosion – Penetration • Bottomhole pressure

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Pre-Acid Preflush • Ammonium chloride (NH4Cl) • Guideline – – – –

Formation Brine

3 wt% (15%)

• Calculated Concentration = 3% + – – – – –

(% Smectite + % Mixed Layer*0.5)*0.3) + (% Illite+ % Mixed Layer*0.5)*0.12) + % Kaolinite*0.08 + % Chlorite*0.12 + % Feldspar*0.05)

HCl

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HCl Preflush/Overflush HCl Fluid Selection Guide for All Temperatures >100 md

20-100 md

10% clay

13.5 - 1.5

9- 1

4.5 - .5

> 10%silt and < 10% clay

12 - 2

9 - 1.5

6- 1

< 10%silt and > 10% clay

12 - 2

9 - 1.5

6- 1

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Mud Acid Guidelines for Reservoirs with < 2% Zeolites* < 10% Silt and 10% Silt and >10% Clay Other

> 20 md 8% HCl/2% HF with 5% Acetic 9% HCl/1% HF with 5% Acetic 9% HCl/1.5% HF with 5% Acetic

< 20 md 6% HCl/1.5% HF with 5% Acetic 4.5% HCl/0.5% HF with 5% Acetic 6% HCl/1.5% HF with 5% Acetic

Mud Acid Guidelines for Reservoirs with 2 -5% Zeolites* All Silt and Clay Ranges

> 20 md OCA

< 20 md OCA

Mud Acid Guidelines for Reservoirs with >5% Zeolites* All Silt and Clay Ranges

> 20 md OCA HT

< 20 md OCA HT

*10% Acetic Acid PF/OF and use OCA when fines migration is a problem.

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Mud Acid Guidelines for Reservoirs with < 3 Chlorite/Glauconite > 20 md

< 20 md

6% HCl/1.5% HF

6% HCl/1.5% HF

> 10% Silt and >10% Clay

4.5% HCl/0.5% HF

4.5% HCl/0.5% HF

Other

6% HCl/1% HF

6% HCl/1% HF

< 10% Silt and 20 md

< 20 md

< 10% Silt and 10% Silt and >10% Clay

9% HCl/1% HF with 5% Acetic

4.5% HCl/0.5% HF with 5% Acetic

Other

9% HCl/1.5% HF with 5% Acetic

6% HCl/1% HF with 5% Acetic

Mud Acid Guidelines for Reservoirs with >6% Chlorite/Glauconite* All Silt and Clay Ranges

> 20 md

< 20 md

OCA

OCA

* 10% Acetic Acid PF/OF

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Clay Instability in HCl All clays have a temperature at which they become unstable in HCl. Unstable clays decompose quickly, consume HCl and can migrate.

Max. T in HCl (deg F) Short Berea CoreMud #2: Acid 12-3 Mud Acid Test @ 300 F Jauf Core # 710 HCl and Sensitivity 2500 Effluent From Core #640 6 wt% wt% Acetic Acid 15 wt% HCl 12 12 wt% wt%HCl HCl- 6 6wt% 10 + 75 wt%Cl NH Cl 15 wt% HCl 12 wt% 3HCl - HF 6 wt% NH Ammonium wt% Ammonium 6 wt% NH Cl 3 wt% HF 20000 3 wt%Mud HF Acid Chloride Chloride 150 2000 Fe 190 Al 15000 1500 Si 200 Ca Al Fe 10000 1000 200 K Si Mg 250 500 o

14000

4

4

4

Concentration ( mg/L)

Delta Pressure (psi)

12000

Concentration (mg/L)

Mineral • Zeolites • Chlorites • Illite • Mixed Layer • Smectite • Kaolinite

10000

8000

6000

4000

5000

Mg 2000

0

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K

0

0 1

0.00 1

3 3

25.00 50.00 7 Cumulative 9 11 Volume 13 15 Pore

5 5

7

9

Sample11#

13

75.00 19

17 15

17

19

Sample Number

17

Organic Mud Acid • Formic acid (9% L036 replaces 12% HCl) • Less corrosive than comparable Mud Acid formulations • Reaction rate ~ 1/4 that of Mud Acid • Reduces sludge tendency

+ L36 (Formic)

HF or

Y1 Mud Acid

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Retarded HF Systems • Problem

– Mud Acid (HCl-HF) spends very rapidly near the wellbore and is not effective in removing clays and other fines deep in the formation. – Some wells show good stimulation initially, but experience a rapid production decline. • Solution

– Retarded Mud Acid system for deep Hydrofluoric penetration. – A system that stabilizes formation fines. – Low HF concentrations Matrix Stimulation Engineering Solutions

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Retarded HF formulation using Fluoboric Acid (HBF4) Clay Acid • Ammonium bifluoride + boric acid + HCl • HBF4 + H20 HBF3(OH) + HF • HF reacts with silt and clay • HBF4 continues to generate HF slowly

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Kaolinite Observed With SEM

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Improved Penetration with Fluoboric Acid Permeability, % Change

800 Fluoboric/Clay Acid 12% HCl - 3%HF

600 400 200 1st 6 in. Unconsolidation

0 0

10

20

30

40

Distance From Inlet (in.) Matrix Stimulation Engineering Solutions

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Water Sensitivity Test Frio Sand Untreated

Treated

% of Original Permeability 140

% of Original Permeability 140

120

120

100

100

80

80

60

60

40

40

20

20

0

0 0

5

10

15

20

25

Pore Volumes

30

0

5

Distilled Water 6% Sodium Chloride Clay Acid

10

15

20

25

30

Pore Volumes

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Fluoboric Acid Shut-In Time Minimum ShutShut -in Time (hr) BHST (°F) ( F)

Regular Clay Acid

Clay Acid LT

100 110 120

96 76 52

48 38 26

130 140 150

35 24 16

18 * *

160 170 180

11 8 5

* * *

190 225 250 300

3 2 1 0.5

* * * *

*Clay Acid LT can be used to 130O F, Engineering Solutions but isMatrix not Stimulation recommended above 130O F.

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Clay Acid Applications • Preflush to Mud Acid: Very acid sensitive formation • Main Acid: Carbonate-cemented sandstones • Overflush to Mud Acid: Enhanced fines control • Shut-in and bring production back slowly NH4Cl w/ U66 30-60 gal/ft

Clay Acid 100-125 gal/ft

HCl or DAD 50-75 gal/ft

Mud Acid 100-150 gal/ft

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Publications on Clay Acid Mobil - SPE 8399 Arco - SPE 11722 Exxon - SPE 9387 Tenneco - SPE 14820 AGIP - SPE 20623 Statoil - SPE 24991 Statoil - SPE 31077 Ashland - IPA

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Evaluation of Fluoboric Acid Treatment in the Grand Isle Offshore area using Multiple Flow Rate Test • Seven case histories were presented • A plot of (Pws2 - Pwf2) / Qg vs. Qg (the turbulence plot) was used as an evaluation tool. 2 2 ∆( P 2 ) Pws − Pwf = = C L + D 'Q g Qg Qg

REF: McBride, Rathbone, and Thomas, SPE 8399

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∆(p2 ) / Q (PSI2 / SCFD) 2

6 months after RMA After RMA 1

After Clay Acid 3 years after Clay Acid 0 0

5

10

15

Q (MMCFD) Matrix Stimulation Engineering Solutions

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12.0

Q (MMscf/D)

10.0

After Mud Acid Trt.

After Fluoboric Acid Treatment

8.0 6.0 4.0 2.0 0 -6

0

10

20

30

40

50

Time (Months) Matrix Stimulation Engineering Solutions

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Silicon to Aluminum ratios in HF and Fluoboric Acid effluents Zone

Sample

HCL/HF

Fluoboric

C(3.4)

B C C’

0.6 -

2.9 2.5

A(1.7)

E F F’

0.5 -

1.6 1.7

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SPE 20623 ADVANCES IN MATRIX STIMULATION TECHNOLOGY G. Paccaloni and M. Tambini AGIP Spa

• Incorrect Stimulation Fluid • • • •

Initial: Reperforate: Mud Acid: Fluoboric Acid:

2200 BOPD 2000 BOPD 2000 BOPD 1900 BOPD

400 BOPD @ 6 months Same decline Same decline @ 60 months

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Ashland Oil Well No. 3

2000

Production (BLPD)

1500

1000 After Fluoboric Acid Treatment

500 Decline after Mud Acid & Clay Control Treatment 0 0

0.5

1

1.5

2

Time (Years) Figure 8 - Production of Oil Well No. 3 showing decline after Mud Acid treatment indicative of fines migration and sustained production after fluoboric acid treatment. Matrix Stimulation Engineering Solutions

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CONCLUSIONS • HBF4 generates HF at a slow rate thus providing deeper live-acid penetration than is possible with ordinary HCl/HF acid. • Treatment with HBF4 prevents silt and clay migration/swelling through fusion of platelets and reduction of CEC. This should prevent fines dispersion resulting from both ionic shock and mechanical dislodgment. • HBF4 normally is used n combination with HCl/HF acid. The faster-reacting HCl/HF acid removes damage immediately around the wellbore, while the HBF4 penetrates deeper to remove formation damage and to stabilize clays and other fines. • A shut-in period is required following injection of HBF4 to allow spending of the acid and stabilization of the clay. • HBF4 is less damaging to formation integrity than HCl/HF acid. • Fluoboric acid minimizes silica formation. • Case history studies of the use of fluoboric acid in sandstone matrix acidizing indicate that the system is very effective in removing formation damage and stabilizing formation fines. Matrix Stimulation Engineering Solutions

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Organic Fluoboric Acid (OCA) for HCl Sensitive Sandstone Formations

Applications • HCl Sensitive Formations –Unconsolidated sandstones –Chlorite –Zeolite

• High Silt/Clay Content –> 30% Silt/Clay

• HT formations –T > 300 F Matrix Stimulation Engineering Solutions

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Fluid Selection Guidelines OCA-HT Temp >300F

OCA

yes

Temp < 300F

yes

Zeolite 5% any temp

yes

Chlorite 5% any temp

yes yes

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Experimental Methods • Sequential Acid Spending

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Testing Results • Sequential acid spending on 90% 100 mesh sand and 10% zeolite, 200oF

Si Concentration (Molar)

0.4

0.35

Organic Clay Acid 9/1 mud acid Clay Acid 3/1 mud acid

0.3

0.25

0.2

0.15

0.1

0.05

0

2

1

3

4

Sequential Reaction ----->

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Core Flow Testing 9/1 Mud Acid

140

Potential Fine Migration after Acidizing

Permeability (md)

120

100

80

60 6% N aC l F re s h W a te r 3% N H 4C l 15% H C L 9 /1 M u d A c id

40

20

0 0

50

100

150

200

250

T im e (m in ) Matrix Stimulation Engineering Solutions

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Core Flow Testing OCA 1000

6% N aC l F r e s h W a te r 3% N H 4Cl 15% H C l OCA

900

Permeability (md)

800 700 600 500

Fines stabilized

400 300 200 100 0 0

20

40

60

80

100

120

140

160

T im e (m i n ) Matrix Stimulation Engineering Solutions

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Placement 1. NH4Cl preflush 2. 10% Acetic Acid 3. OCA 4. NH4Cl overflush 5. Diverter 6. Repeat 2-5 as required No Shut-in Required

(25-50 gpf) (75-100 gpf) (100-200 gpf) (3-4 feet radially)

OCA 100-200 gal/ft

NH4Cl 25-50 gal/ft

NH4Cl w/ U66 25-50 gal/ft

10% Acetic Acid 75-100 gal/ft

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Differentiation Recomended Procedure Low Temperature Non Sensitive Clays Low Clay Content Low Temperature Non Sensitive Clays High Clay Content

A

5% NH4Cl Preflush

B

HCl Preflush

C

Organic Acid Preflush

D

Mud Acid

E

Clay Acid

F

Organic Clay Acid

G

Shut In

H

5% NH4Cl Postflush

I

Immediate Flow Back

A B D H I

Mud Acid A B D E G

Clay Acid

Low Temperature Sensitive Clays Any Clay Content

A C F H I

High Temperature Sensitive Clays Any Clay Content

A C F H I

OCA OCA HT

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Case History #1 - GOM • • • • • • •

Deep water turbidite sand 11,000’ TVD, BHST 175 F Frac-Pac completion Permeability - 400 to 1600 md 5% Zeolite Compaction - 20 - 30% perm reduction Increasing skins - higher drawdowns

BOPD MCFD

Well #1 Before After 775 1034 498 547

11,592’

11,928’

Well#2 Before After 218 1045 216 837 12,060’

Production levels sustained for more than 1 year

12,141’

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Case History 1: GOM 5000

10

Treating Pressure - psi Injection Rate - BPM

8

4000

Acid at Perfs

3000

6

Pump OCA

Start Displacement Start PostFlush

2000

4

End of Treatment

Prime Pumps

1000

0 220

Injection Rate - (BPM)

Pressure - psi

Increase Rate

2

245

270

295

320

345

370

0

Job Time (Minutes)

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Case History #4- Venezuela • • • • •

Temp: 140 – 235 °F Reservoir Pressure: 950 – 1400 psi Reservoir Permeability: 100 - 300 mD Depth: 2900 -4200 ft Gravel Packed with sand 20/40

Average Oil Prod, BOPD

280

Average Bef ore

Average Expected

Average Act ual

M ud A cid Treatments

240

Formation lithology: Quartz: 48%-56% Mica: 3%-11% K-Feldspar: 1%-3% Kaolinite: 28%-36% Smectite: 1.4%-2.3% Illite: 1%-2.5% Chlorite: 1.1%-3%% Zeolites: 1.2%

200 160 120 80 40 0 0

30

60

90

120

Tim e after Treatm ent (days) Matrix Stimulation Engineering Solutions

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Case History #5- Pakistan • • • • • •

Temp: 340 °F Reservoir Pressure: 4300 psi Reservoir Permeability: 160 mD Perfs: 3318.5m to 3328.0m Gravel Packed with sand 20/40 Acetic acid and OCA w/ VES diverter

Post-Stimulation

Formation lithology: Quartz: Mica: Feldspar: Smectite: Glauconite: Chlorite: Siderite: FeFe-Dolomite

49%49%-60% 1%1%-3% 1%1%-6% 1.4%1.4%-2.3% 1% 7%7%-10% 7%7%-20% 0%0%-7%

Lowered FWHP ~400 psi Maintain production at 50 MMscfd

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Organic Fluoboric Acid: Conclusions • OCA provides safe stimulation of sensitive formations – Zeolites, Chlorites and high temp formations – High clay content

• • • •

OCA provides deeper penetration Undesirable precipitates are minimized Fines Migration is controlled No shut in required

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Sandstone Acidizing Conclusions • Damage identification determines the types of acid and other solvents used. • Fluid selection for a mud acid treatment is based on permeability and mineralogy. • A knowledge of the chemical reactions involved between acids with formation minerals and connate fluids is required. • Appropriate volumes of preflushes and overflushes help prevent incompatibilities. • The primary reaction of mud acid with silt and clay occurs very fast. • Secondary and tertiary reactions do not contribute to damage removal. • Hydrated silica (silica gel) is normally not a damaging precipitate. • Retarded acid with silt and clay control properties are required in sandstone reservoirs with production declines. • Acid sensitive sandstone reservoirs cannot be treated with a conventional mud acid treatment, i.e. they require a organic fluoboric acid system. • Although guidelines exist for volume selection a numerical simulator is recommended to quantify acid volumes. Matrix Stimulation Engineering Solutions

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Matrix Stimulation: Sandstone Sandstone Stages 1. Pre-acid Preflush Fluids @ End 2. Acid Preflush of Treatment?? 3. Main Treating Fluid 4 3 2 1 4. Overflush

StimCADE Demo

5. Diverter Stage

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