ACIDIZING USING A RULE BASED SYSTEM

AUTOMATING SANDSTONEACIDIZING USING A RULE BASED SYSTEM

Ali A. GarrouchHaitham M. Lababidi

AbAllah Ebrahim

Kuwait UniversityKuwait University

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Ebrahim, A., Garrouch, A.A., and Lababidi, H. 2014, Automating sandstone acidizing using a rule-based system, Journal of Petroleum Exploration and Production Technology, v. 4, no. 4, p. 381-396.

REFERENCEREFERENCE

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Purpose of Acidizing Oil an Gas Fields Sandstone Acidizing Stages Causes of Failure of Sandstone Acidizing Challenge/Study Objectives Expert System Development Expert System Validation Conclusions Reference

Outline

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1. Particle damage from drilling 2. Fines migration 3. Clay swelling4. Polymer residue from drilling5. Bacterial infestation6. Surfactant stabilized emulsions7. Water blocks

Damage Types - Considered

Zone of altered permeability ks, near a well.

Zone of altered permeability

pe

hwr

rs

ks

er e

Near well-bore zone: ideal, real and stimulated bottom- hole pressures.

Damaged (Real) well

Undamaged (Ideal) well

pw

Stimulated well

Reservoir Pressure

k

rwrs

ks

s p (due to stimulation)

p (due to damage)

s

p

How Does a Well Produce?

pwf

pwh

pflowline

Pwf

qo

Natural flow-rate

pR

NodalAnalysis

Types of Damage

Begin by estimating the damage skin (Sd) from the total skin:

Evaluate single skin ( Spp , Sp , S , SG, Sf)

,, ,

3,750 STB/D

Oil

Openhole and Production log

TracesMG Well

Depthft

GR, API

Rt, ohm-m

4250

4300

4350

4400

4450

4500

0 20 40 60 80 100

1 10 100 1000

p/qpsi/STB/D

t, hr

0.0001

0.001

0.01

0.1

0.001 0.01 0.1 1 10

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Pre-flush Main Acid: 12% HCl-3% HF Over-flush

Sandstone Acidizing Stages

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Usually HCl (5-15% in strength) Displaces water, minimizing contact of

HF acid with Na+ and K+ ions. HCl removes CaCO3 cementing material

Pre-flush Stage

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Usually 12% HCl-3% HF HF reacts with clays, fines, drilling mudcake, and

silica to improve near-wellbore permeability. HCl keeps pH low and helps to prevent secondary

HF reactions.

Main Acid Stage

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Condition Acid

HCL Solubility > 20% Use HCL only

High Permeability (100md plus)

High Quartz (80%), low clays(<5%) 10% HCL-3% HF (1)

High Feldspar (>20%) 13.5% HCL-1.5% HF (1)

High Clay (>10%) 6.5% HCL-1% HF (2)

High Iron Chlorite Clay 3% HCL-0.5% HF (2)

Low Permeability (10 md or less)

Low Clay (<5%) 6% HCL-1.5% HF (3)

High Chlorite 3% HCL-0.5% HF (4)

Notes:

(1)Preflush with 15% HCL(2)Preflush with sequestered 5% HCL(3)Preflush with 7.5% HCL or 10% acetic acid(4)Preflush with 5% acetic acid

Traditional Guidelines

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Overflush

Displacement of acid flush away from wellbore area

Oil wells: NH4Cl/Weak HCl/mutual solvent (if necessary)

Surfactant/Mutual Solvent: Leave formation water-wet Facilitate flow-back

Nitrogen: Promotes flow-back in low pressure wells Results are not always as expected.

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Causes of Failure of Sandstone Acidizing

“With acidizing, there are many more exceptions to the rules than there are rules. In fact, true success in acidizing is associated with the better understanding of the exceptions.”

The global success rate for sandstone acidizing is generally about 30%.

A quote by a Leonard Kalfayan

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poor candidate selection. lack of mineralogical information wrong acid design, use of inappropriate acid additives, insufficient iron control. Formation of emulsions Formation of asphaltene sludge

Effect of HCl:HF Acid Strength on Sludging

Effect of HCl Strength on Sludging

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The major defects of HF are the formation of by-products like: • calcium fluoride (CaF2), with calcareous material • sodium hexafluorosilicate (Na2SiF6)

• hydrated silica (SiO2.2H2O)

• potassium hexafluorosilicate (K2SiF6)


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The major defects of HCl is the formation of precipitates

•Ferrous Hydroxide (Fe(OH2), if HCl is neutralized and pH~7 •Gelatinous precipitates in contact with Zeolites (natrolite, analcime) •Ferric Hydroxide (Fe(OH3), •Iron sulfide scale (FeS), if do not use a reducing and a sequestering agent.


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Design a sandstone acidizing job that is damage type specific, taking into account acid-mineralogy interaction and acid-crude interaction.Multiple damage types may be suspected, and all should be considered in designing the treatment.This is a very perplexing task to the practicing engineer.

Challenge/Study Objectives

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Expert System Development

Damage Type Rock Mineralogy Reservoir Temperature Rock Permeability Formation fluids Amount, type, distribution of clays Degree of rock consolidation Presence of sour gas

The acidizing advice must account for the following variables:

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1. Formation oil displacement stage2. Formation water displacement stage3. Acetic acid stage4. HCl pre-flush stage5. Main acid stage6. Over-flush stage

The treatment design will include the following stages:

Expert System DevelopmentMethodology

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Fluoboric acid: a clay acid

Phosphonic acid blends

Acidic chelant-based blends

Mud acids

EDTA (Ethylene diamene tetracetic acid)

HCL/Acetic acid/Citric acid/Formic acid

Erythorbic acid

Expert System DevelopmentAcid Types Expanded

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Fluoboric acid is recommended when the sandstone contains potassic minerals to avoid damaging precipitates and in the case of fines migration owing to its fines stabilization properties.

Fluoboric Acid

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Acidic-Chelant based blends: are obtained by mixing a chelating agent with an acid based salt. Boric acid, or ammonium bifloride are examples of acid based salts.

Examples of a chelating agent: EDTA, HACA

Acid – chelant blends

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The advantage of chelant based fluids is their ability to

Dissolve both calcium and aluminosilicates Prevent the possible precipitation of reaction by-products by sequestering many of the metal ions present in the aqueous solution: ca2+, Fe2+, Al3+ ions.Treat formations with low clay content.Treat formations with high calcite contentTreat formations with high iron content.Treat formations with Zeolite bearing minerals. Treatment restricted for high temperature formations

Acid-chelant blends

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The phosphonic acid formulation offers the following benefits: Retarded reaction rate, hence the ability to get the

acid deeper into the formation before becoming completely spent.

No risk of insoluble precipitates such as CaF2, Na2SiF6, K2SiF6 and SiO2.2H2O.

The ability to leave the formation water-wet.

Phosphonic acid blends

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Expert System Structure

Stage 5bChloride Scale

Stage 5cSulfate Scale

Stage 5dWater Blocks

Stage 5aMain Acid

Stage 1Formation Oil Displacement

Stage 2Formation Water Displacement

Stage 3Acetic Acid Pre-Flush

Type of Damage

Damage Types1, 2, 3, 4, 5 & 6

Damage Type 15

Stage 6Over-Flush

Stage 7Diversion Selection

Damage Types 8, 9 & 10

Damage Type 17

Stage 4HCL Pre-Flush

Damage Types7, 11, 12, 13 & 14

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Expert System Development – Decision Trees

Stage no. 2: Formation Water Displacement Stage

Inject water with ammonium chloride (NH4CL) at concentrations between 3% and 8% depending on

the formation water salinity

Are there any iron compounds in the formation:

- pyrite, or- siderite, or

- hematite, or- Magnetite, or

- Antcerite ?

Stage no. 3: Acetic Acid Pre-flush Stage

No

No action needed

Inject 3% to 10% acetic acid according to Table below:

Yes

Are there any- chlorite clay, or

- mixed layer clay, or- Illite

Yes

Are there any zeolites like

- analcime, or- natrolite ?

YesNo

No

CaCO3 Acetic acid volume (gal/ft

0-5 255-10 50

10-15 7515-20 100

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Expert System Log in Details

http://lababidi.chemeng.kuniv.edu/WBES/

Username: KCUser88Password: KC@q88

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Graphical User Interface

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Field Case I: Niger Delta Region (Nigeria)

Low pressure SS oil producer Mineralogical makeup of the rock shown in Table (next) Permeability ranges from 100 md to 5000 md Crude downhole specific gravity = 0.663 Reservoir temperature = 188 oF Water cut about 60% Pay thickness = 21.7 ft Presence of zeolites, feldspars, and clays Mud reports indicate mud losses Water-Based mud Crude is paraffinic Iron-rich minerals exist as authigenic Feldspars exist as detrital

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Field Case I: Niger Delta Region (continue)

Intermediate matrix treatment is needed N2 is required for diversion Main problem: Fines Migration

Location Niger Delta

Depth (ft) 6230

Quartz 73.2

K-Feldspar 13.6

Plagioclase (Calcium-Sodium Feldspar) 4.1

Illite/Smectite 0.7

Mica 0.0

Kaolinite 6.3

Chlorite 0.0

Dolomite 0.0

Calcite 0.0

Siderite 1.4

Pyrite 0.7

Hematite 0.0

Zeolite 0.7

TOTAL 100.0

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Field Case I: Niger Delta Region (Solution)

Stage One: inject a mixture of diesel and toluene at 75:25 ratio. Soak overnight and flow back. Inject a mutual solvent.

Stage Two: inject water with ammonium chloride at concentrations between 3% and 8%

Stage Three: Acetic acid preflush: no action is needed. Stage Four: HCl preflush: inject HCl 3% + Fluoboric acid+Erythorbic acid + EDTA. Stage Five: inject phosphonic acid, 50-150 gal/ft.

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Field Case I: Niger Delta Region (Solution)

Stage Six: Over-flush stage: inject 8% NH4Cl.Stage Two: Formation water displacement stage: inject water with ammonium chloride at concentrations between 3% and 8%, depending on the formation water salinity.

Stage Seven: Diversion: inject foam.

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We developed an web-based expert system for designing matrix acidizing of sandstones.

The system helps automate a very perplexing designing task. The system can be easily upgraded with new scientific advances

in the area. The expert system accounts for compatibilities between crude,

mineralogical composition, reservoir properties, and acid types.

Conclusions

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REFERENCE

Ebrahim, A., Garrouch, A.A., and Lababidi, H. 2014, Automating sandstone acidizing using a rule-based system, Journal of Petroleum Exploration and Production Technology, v. 4, no. 4, p. 381-396.

THANK YOU

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ACIDIZING USING A RULE BASED SYSTEM