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Formation Damage and Matrix Stimulation Core

Introduction

Why Take This Module?

It is a common occurrencefor an oil and gas operatororganization to bring on awell after initial drilling andcompletion or after aworkover and observe thatthe production rate is notas expected

Formation Damage and Matrix Stimulation Core ═════════════════════════════════════════════════════════════════════════

© PetroSkills, LLC. All rights reserved._____________________________________________________________________________________________

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If rates are greater thanexpected, there is someinterest and evaluation asto why and a study maycommence

Production Rates


Not accurately identifyingthe correct causes of lessthan expected productionwill often lead to costlyremedial attempts that likelywill result in the failure toachieve a well’s maximumproductive capacity

Proper investigative studiesthat lead to identification oftrue formation damage willprovide the engineer withproven remediation tools toregain well productivity



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If acidizing a formation ischosen as a remediationstep to take, the stimulationdesign engineer must alsounderstand corrosioncontrol, iron control, aciddiversion, etc., to achieveoptimum stimulation results

Acid Diverting Agents


Poor corrosion control practicescan lead to catastrophic failureof well completions

Elemental iron is often presentthroughout a reservoir’slithology and ignoring theeffects of iron that goes intosolution during an acid jobto restore productivity can

readily turn a successfulacid job into a failure



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If proper acid diversion techniquesare not properly analyzed anddesigned as a fundamentalcomponent of an acid job, theacid pumped may just reactthe most permeable portionsof the reservoir, thus leadingto job failure

Acid Diverting Agents


The chemistry of limestoneand sandstone remedialacid job treatments torestore production differgreatly

Properly identifyingformation damage andapplying remedial actionswill provide the opportunityto restore a well to itsmaximum productivity



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Formation Damage

Formation Damage

Matrix Stimulation

Module Contents



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Learning Objectives

By the end of this lesson, you will be able to:

Identify the basic causes of oilfield formation damage and how they are recognized

Outline the concept of “True Formation Damage” and the principles of formation remediation once it has been correctly identified as being the cause of lost production

Describe examples of “pseudo” formation damage and identify how it differs from True Formation Damage

This section will cover the following learning objectives:

Near Wellbore Formation Damage

near-wellbore area affected by unwanted

pressure drop “S” value

damage is concentrated radially near the wellbore

rw wellbore radius

re drainage radius

rd damaged zone

reservoir drainage area

h reservoir thickness

area x thickness =volume

is approximate

- ∆ Pskin

damaged zone



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Clean Sandstone Sandstone With Some Clay Content

Sandstone With Significant Clay Content

Formation damage is often assessed by reservoir engineering conducting a form of well test

• Build-up test• Fall off test • Multi-rate well test

Well Inflow Equation:

Stimulation Affects “S”:• Skin Factor, S

– Damage removal by acidizing will reduce the skin factor “S”

• Formation Capacity, kh– Formation can produce at its unrestricted “kh value” when skin is

removed

Near Wellbore Formation Damage – “Skin”

Qkh P Pres wf

rB ln r Sew 0Flow rate

Reservoirparameters

Pressuredrop



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• Formation Capacity, kh – Formation can produce at its unrestricted “kh value” when skin is

removed


Qkh P Pres wf

rB ln r Sew 0

If the well has a negative S, then the well has a higher than

expected flowing bottom hole pressure, indicating less

drawdown is required to produce the well at a given rate. This

would be a highly stimulated well.

If S is positive, then the well has a lower than expected flowing

bottom hole pressure, indicating more drawdown is required to

produce the well at a given rate. This would be damage.






• Formation Capacity, kh – Formation can produce at its unrestricted “kh value” when skin is

removed


Qkh P Pres wf

rB ln r Sew 0

If the well has a negative S, then the well has a higher than

expected flowing bottom hole pressure, indicating less

drawdown is required to produce the well at a given rate. This

would be a highly stimulated well.



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The term skin is actually a combination of many individual pressure changes.

Positive skin would be unwanted pressure drops.

Negative skin would be less pressure drop than expected.

There is more concern over unwanted pressure drops, as these can reduce production.

Skin Factor “S” Defined

Stotal =

Sdam Skin caused by true formation damage

+Sperf Skin caused by poor perforation charge / gun design

+Sturb Skin caused by non-laminar flow

+Sdev Skin caused by wellbore deviation


h

Deviated Wellbore Through Zone



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Stotal =





**Skin caused by gravel packs + Sgravel

**Skin caused by stimulation + Sstim

**Skin caused by frac jobs + Stemp

Skin caused by natural fracs + Sfrcs

** Skin by other causes + Sother


** When these jobs are properly designed, skin will not result

Stotal =





**Skin caused by gravel packs + Sgravel

**Skin caused by stimulation + Sstim

**Skin caused by frac jobs + Stemp

Skin caused by natural fracs + Sfrcs

** Skin by other causes + Sother


** When these jobs are properly designed, skin will not result

* For example, skin caused by dirty fluid, Sdam is likely a result of True Formation Damage which consists of absolute permeability reduction, or “plugging” and relative permeability reduction, or “fluid related oil or water

wetting”, depending upon the type of dirty fluid; True Formation Damage may also be caused by fluid viscosity increase which is caused by emulsions

forming



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Altered Zones

Created by (altered by) Formation Damage

Improved (altered by) acidizing

h

XX


Represents “dimensionless” near well bore pressure drop

Pressure drop caused by damage is typically near the well

“True Formation Damage” consists of:• Absolute permeability reduction – effects plugging the rock pore space• Relative permeability reduction – effects altering wettability of rock • Viscosity increase – effects caused by emulsions

pskin – This would be positive skin, showing a lower than expected flowing bottom hole pressureF

low

ing

Bot

tom

Hol

e P

ress

ure

(P

wf)

Distance from Well

Pwf expected

Pwf actual

Examples of True Formation Damage

- Any filtrate invasion- Any solids invasion- Oilfield scales- Waxes- Asphaltenes- Emulsions



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The clay occupies porethroats which would thenreduce the ability ofreservoir fluids to flowthrough those pore throats

For a given productionrate, Q, this rock wouldrequire a greater pressuredrop to overcome therestriction caused by theclays

That additional pressuredrop shows up as apositive skin in thedenominator of the usualinflow equation

Illite Clay Damage in Sandstone


Pressure drop that is not “True Formation Damage” consists of:• Drilling related induced stresses in the rock• Formation compaction over time• Partially penetrating a zone• Deviated well through zone

Flo

win

g B

otto

m H

ole

Pre

ssur

e (

Pw

f)

Distance from Well

Pwf expected Pwf actual



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Pressure drop that is “True Formation Damage”:• May be removed using proper stimulation techniques

Pskin

Flo

win

g B

otto

m H

ole

Pre

ssur

e (

Pw

f)

Distance from Well

Pwf expected

Pwf actual

Formation Damage Resolution

Acid Stimulation Treatment Gains

Acid matrix stimulation treatments achieve productivity increase results

Matrix stimulation refers to treatment of the formation below fracture pressure

• Matrix stimulation treatment selection process is critical

Fluid selection parameters important

Treatment design important

Operational procedures for matrix stimulation important



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Learning Objectives


Identify the basic causes of oilfield formation damage and how they are recognized

Outline the concept of “True Formation Damage” and the principles of formation remediation once it has been correctly identified as being the cause of lost production

Describe examples of “pseudo” formation damage and identify how it differs from True Formation Damage

This section has covered the following learning objectives:



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Matrix Stimulation

Formation Damage

Matrix Stimulation

Module Contents



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Learning Objectives


Outline the principles of limestone matrix acidizing and thechemistry and reactions involved

Outline the principles of sandstone matrix acidizing and thechemistry and reactions involved

This section will cover the following learning objectives:

8 Years of Acid Stimulation Treatment Gains

Typical Results

0

4,000

8,000

12,000

16,000

20,000

Productivity Gains Due to Stimulation(m3/d oil equivalent)

Major Operator “A” 8 Year Historical Comparison Period

(25,160 bpd)

(50,320 bpd)

(75,480 bpd)

(100,640 bpd)

(125,800 bpd)



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Stimulation Treatment Gains Over 6 Years

350 Treatments: Average gain of 75 m3 oil/d/job (472 bpd)

Average Job Cost: $118,000

Total gain: 27,833 m3/d (175,060 bpd)

Total Expenditure: US$ 44,250,000 in year #6

Failure Rate: 20% (mainly matrix treatments)

US$ Invested / Additional BOPD ProductionUS$/bpd

0

100

200

300

400

Major Operator “B” - 6 Yr Historical Comparison Period

Acid “diversion” may improve treatment effectiveness

• Below the formation “fracture gradient”

Matrix Acid Stimulation Objectives

Treat the pore spaces in the formation near the well bore

Use acids to attack and chemically react and removedamage

Conduct job at pressures below that which would fracturezone



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Matrix acid treatment volumes are typically pumped at a plannedwell bore depth for acid penetration to be most effective

Lab core analyses with chemical treatment options and costs areevaluated

Chemical volume increases as a function of r2

% o

f P

rod

uct

ivit

y L

ost

Radial Extent of Damaged Zone (m)

Matrix Acid Stimulation Objectives

CriticalMatrixRegion

0

20

40

60

80

100

0 0.5 1 1.5 2 2.5 3

80% Damage90% Damage95% Damage98% Damage

Note: 55% of damage at approximately

0.65 m (2.1 ft) from well per lab analysis

(1.6 ft) (3.3 ft) (4.9 ft) (6.6 ft) (8.2 ft) (9.8 ft)

Matrix Stimulation Candidate Selection

Hydrocarbon Saturation 30% or more

Water Cut 40% or less

Gross Reservoir Height no limit

Permeability Gas > 1 mD, Oil > 20 mD

Reservoir Pressure Gas: 2 x abandonment pressure Oil: pressure at 80% depletion

Production System: Current production not more than 80% of maximum facilities capacity

Establish Appropriate Guidelines



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Hydrocarbon Saturation 30% or more

Water Cut 40% or less

Gross Reservoir Height no limit

Permeability Gas > 1 mD, Oil > 20 mD

Reservoir Pressure Gas: 2 x abandonment pressure Oil: pressure at 80% depletion

Production System: Current production not more than 80% of maximum facilities capacity

Establish Appropriate Guidelines

WILL WILL NOT

Increase the average reservoir pressure

Create more hydrocarbon saturation in the pore space

Improve the rate of production of the reservoir fluids

Improve the production of water


GUIDING PRINCIPLES

Start with the best available information for well data, decision criteria, assumptions, and expectations

Conduct involved analyses on candidates

Rank candidates on all combinations of properties (local circumstances, risk, etc.)

Evaluate the organized hierarchy (group, operating unit, field specific, etc.) from past experience

Apply system “learning” through feedback to check defaults (post job analysis)

Avoid the tendency to choose poor candidates with the intent to turn poor ones into great ones



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Stimulation Planning

Stimulation Treatment Process

Treatment Design

Site Preparation

Evaluation Cycle

Operational Stimulation

Program

Schedulingand

Logistics

Treatment ResultPrediction

Treatment Selection

Problem Classification

Problem Well Identification

Diversion, Additives,Other, etc.

Operational Constraints

Job Execution

Types of Treatment Chemicals to Treat Damage Causes

CAUSE OF DAMAGE

*Stim Damage, Gravel Packing, Perforating, etc.

Drilling, Completion,

etc.

Chemical Interaction

Wax, Asphaltenes

Mud Acid Treatment

Solvent / Surfactant Treatment

Acid Treatment

Produced Fluids

Formation Fines

Precipitates, Clay Swelling

Emulsions


Acid Treatment

Injected Fluids

Water

Precipitates, Scale

Clay Swelling Mud Acid Treatment

Oily / Inhibitor Residues


Specific Well Treatment*

(Mud) Acid Treatment

LIM

ES

TO

NE

O

R

SA

ND

ST

ON

E

Gas

TYPE OF TREATMENTDAMAGE TYPESolids

Invasion



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Work Closely with Chosen Service Company

Work Closely with Chosen Service Company

Perform Laboratory Tests• This is most important to be able to determine the correct and

appropriate treatment method

Purpose• Identify and quantify damage type• Evaluate suitable removal treatment options• Decide upon key treatment design parameters• Assess necessity / application of additives, solvents, etc.• Conduct various lab evaluations

– Fluid compatibility tests– Core flow tests

– Corrosion tests

– Emulsion tests– Reaction rate measurements

– Rock mechanical properties

• Propose/write a program to perform a remedial activity on the well



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Various Treatment Designs

Matrix acidizing of sandstones• Complex HCl-HF acid

3 stage pumping schedule

• Water wet rock conditions must be retained

Solvent treatments

Matrix treatments of limestones• Normally, HCl acid

used due to its reacting power and low cost

Treatments with surfactants, specialty treatments, etc.

Sandstone Stimulation

For sandstone rock reservoirs• HF acid reacts and removes damaging clays

In any acid job, corrosion is a primary concern• Corrosion inhibitors protect well tubulars and equipment

• For a sandstone reservoir, hydrofluoric acid is used

• The acid is blended and is toxic

• Blending it with hydrochloric acid allows sandstones to be properly treated

Hydrochloric Acid / Hydrofluoric Matrix Acid Sandstone Job



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Stage #3 Post Flush Mutual solvent and surfactant return rock to the preferred

“water wet” state

Summary – Mechanism of Sandstone “Mud Acid” Job

Stage #1 Pre Flush Reacts carbonates Displaces formation water away from zone being acidized

Stage #2 Main Flush (mineral dissolution is by reactivity) Reacts clays – very reactive with HF Reacts feldspars – reactive with HF Reacts silica – slowly reactive with HF

SiO2 + 4HF SiF4 + 2H2OSiF4 + 2HF H2SiF6

CaCO3 + 2 HF CaF2 + CO2 + H2O

Al2Si2O5(OH)4 + 18HF 2H2SiF6 + 2AlF3 + 9H2O

NaAlSi3O8 + 22HF 3H2SiF6 + AlF3 + NaF + 8H2O

HCl/HF “Mud Acid” Stage #2 Reactions

Mud acid treatment reaction with feldspar

Mud acid treatment reaction with clay (kaolinite)

Mud acid treatment reaction with carbonate (calcite)

Mud acid treatment reactions with silica (quartz)



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HCl Matrix Acid Job Basics

Limestone Stimulation

For carbonate rock reservoirs• HCl reacts and removes the rock matrix • Damage in the rock matrix is flowed away with the reaction

products

In any acid job, corrosion is a primary concern• Corrosion inhibitors protect well tubulars and equipment

HCl Acid Stimulation

Acid Reaction on Carbonate Reservoir• Dissolves the matrix and thus removes damage • Reaction is: (much simpler compared to sandstone reactions)

2HCl + CaCO3 CaCl2 + CO2 + H2O



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2 HCl + CaCO3 CaCl2 + CO2 + H2O

Hydrochloric Acid / Limestone Reaction Products

The above reaction is immediate, total, and linear.

That is, 50% increase in 15% HCl volume would react a 50% increase in limestone volume to create a 50% increase in reaction products.

1000 gallons 15% HCl

1840 lbs CaCO3 (10.5 ft3)

7600 lbs water (3447 kg)

1350 lbs HCl (612 kg)

2050 lbs CaCl2 [68 gals (2.6 m3)]

812 lbs CO2 [6600 ft3 (187 m3)]

333 lbs H2O [40 gals (.15 m3)]

(3.8 m3)

(835 kg) (.3 m3)(930 kg)

(368 kg)

(151 kg)



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Acid Corrosion Inhibitors

ALL acid jobs require an acid inhibitor

Protect tubulars from acid corrosion

Protect downhole equipment

Protect surface treating equipment

Importance of Inhibitor Program Design

Check to assure that the inhibitor layer is thoroughly mixed into the acid volume for all acid jobs

Mechanical setup to assurethat mixing occurs

Pump

Inhibitorproperly

recycled with acid



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Acid Diverting Agents Used

Ideal acid injection patternwith acid uniformly enteringradial matrix

Normally does not happenwith uniform aciddistribution

Diverting agents function byselectively reducing the flowof acid into the morepermeable portions of theproducing zone

rWH

req

rw

Acid “Wormhole” Effect – Lab Core Tests

2% SGA-II Only All VCA AdditivesCastings From Hollow Core Tests 141°F (60.6°C), 5% HCl, 10 ml/min

Lab tests clearly illustrate that acid seeks high perm streaks



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HighPermeable

Zone

Various Acid Diversion Techniques

SelectivePlacement

Tool

Ball Sealers Viscous Pill

PerforationBlocked WithBenzoic Acid

PerforationBlocked With

Foam

ZoneBlocked

WithViscous Gel

Ball Sealers Type of Acid Diverting Agent

Ball Sealers Features• Effectively Seal on Perforations• Achieve Positive Shut-off• Non-Damaging• Easy to Use• Independent of Formation



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Other Damage Treatment Designs

Matrix acidizing of sandstones• Complex HCl-HF acid

3 stage pumping schedule

• Water wet rockconditions must be retained

Solvent treatments

Matrix treatments of limestones• Normally, HCl acid

used due to its reacting power and low cost

Treatments with surfactants, specialty treatments, etc.

Damage Problem / Solvent Treatment Selection Chart

Aromatic Solvent

Kerosene/Diesel

AlcoholicSolvent

MutualSolvent

Wax

Asphaltene

Emulsions

Scale/SludgeWaterBlock

Legend: Reasonable Poor Preferred

Problem Surfactant

Pipe Dope

Oil BasedMud

Paint, etc.



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Common Commercially Available Solvents

Brand Name Chemical Class Manufacturer Claims

Musol EGMBE Halliburton

Musol A EGMBE derivative Schlumberger Dowell

Improved action

U-66 EGMBE BJ

J-40 EGMBE BJ?

WSA-1 EGMBE (?) BJ?

Cellosolve EBMBE BJ?

A-sol series Alcoholic mixtures Petrolite Better than EGMBE in most applications

MAS Micellar Solvent BJ? Prevents emulsions

EGMBE = Ethylene Glycol Mono Butyl Ether

Oilfield Scale Damage Remediation Selection

HCl Converter+ HCl

ChelatingAgents Skinfrac

Carbonates

IronCompounds

CalciumSulphateBarium

SulphateMixedScales

Legend Preferred

Reasonable

Poor

Problem

Soluble or Insoluble



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Matrix Stimulation Job Control

Well site job control is, in principle, the responsibility of thestimulation contractor

Pre-treatment safety meeting by contractor and siterepresentative

• To be attended by all staff on location

Safety Aspects• All activities, emergency plans, safe working practices etc.

Operational Aspects• Discussion of the plan and individual roles

HSE Issues• Disposal plans for produced fluids, empty drums, etc.

Learning Objectives

Outline the principles of limestone matrix acidizing and thechemistry and reactions involved

Outline the principles of sandstone matrix acidizing and thechemistry and reactions involved

This section has covered the following learning objectives:



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Back to Work Suggestions

Drilling Fluids and Solids Control Core

Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.

Meet with a reservoir engineer to review well data that indicates skin damage that has been identified based upon build up or fall off pressure tests.

Review well history files to attempt to determine the potential source or causes of the skin damage identified above. Consider damage causes related to activities such as: drilling, completion, workover, intervention, stimulation, or other treatment related causes when reviewing the referenced files.




Meet with a production engineer and review well stimulation programs previously performed on your wells. Also review post stimulation job results that indicate production improvement as well as limited or minimal production improvement.

Meet with a geologist to review the differing formation mineralogy components present if your reservoirs are sandstones. If your organization’s production comes primarily from limestone formations, have the geologist illustrate the matrix porosity reservoir model or dominant fracture porosity reservoir model that contributes to providing most, or the greater proportion, of overall production.



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Work with operations engineers to review if and how diverting agents are a regular and important component of acid jobs performed in your wells.

Work with operations engineers to determine how diverse your well stimulation problems are to address issues such as paraffins, asphaltenes, oilfield scales, and other downhole factors affecting production and requiring attention and treatment.

Visit with a service company representative and review the detailed, multi‐step programs and production chemistry recommended to improve overall well performance.

PetroAcademyTM Production Operations

Production Principles Core Well Performance and Nodal Analysis Fundamentals Onshore Conventional Well Completion Core Onshore Unconventional Well Completion Core Primary and Remedial Cementing Core Perforating Core Rod, PCP, Jet Pump and Plunger Lift Core Reciprocating Rod Pump Fundamentals Gas Lift and ESP Pump Core Gas Lift Fundamentals ESP Fundamentals Formation Damage and Matrix Stimulation Core Formation Damage and Matrix Acidizing Fundamentals Flow Assurance and Production Chemistry Core Sand Control Core Sand Control Fundamentals Hydraulic Fracturing Core Production Problem Diagnosis Core Production Logging Core Production Logging Fundamentals



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