1

Introduction to Reservoir Stimulation

Kellyville Training Center

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Well Stimulation

Stimulation is a chemical or mechanical method of increasing flow capacity to a well.

Dowell Schlumberger is mainly concerned with three methods of stimulation:

1. Wellbore Clean-up : “ Fluids not injected into formation”• a. Chemical Treatment• b. Perf Wash

2. Matrix Treatment : “ Injection below frac pressure”• a. Matrix Acidizing• b. Chemical Treatment

3. Fracturing “ Injection above frac pressure”• a. Acid Frac• b. Propped Frac

3

Stimulation Techniques

Restores Flow Capacity:• Wellbore Clean-up• Matrix Treatment

These procedures are performed below fracture pressure.

Create New Flow Capacity:• Hydraulic Fracturing (Acid and Sand)

These procedures are performed above fracture pressure.

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Areas Where Reduction in Flow Capacity May Occur

1. Wellbore:• Scale Damage• Sand Fill• Plugged Perforations• Paraffin Plugging• Asphalt Deposits• Etc.

2. Critical Matrix:• Drilling Mud Damage• Cement Damage• Completion Fluids• Production• Native Clays/Fines

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WELLBORE

Primary Purpose :

Restore flow capacity by removing restrictive damage to fluid flow in the wellbore.

Methods :• Mechanical• Chemical Treatment• Acidizing Treatment

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Critical Matrix What is It?

• The area of formation that is 3' to 5' from the wellbore. Why is it critical?

r % Pressure Drop (Drainage Radius) P (psi) P/ft (Pe - P) (Pe - Pwf) * 100

(Pe) 2,000 ft 5,000 0.07 psi/ft 01,000 ft 4,934 2.5100 ft 4,719 10.850 ft 4,654 1.3 psi/ft 13.320 ft 4,568 16.610 ft 4,503 6.5 psi/ft 19.05 ft 4,439 21.53 ft 4,391 23.32 ft 4,000 850 psi/ft 24.81 ft 3,150 27.3

(Pwf) 0 ft 2,000 1,150 psi/f 100

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Major Goals of Matrix Treatment

1. Restore Natural Permeability• By Treating the Critical Matrix

2. Minor Stimulation

3. Leave Zone Barrier Intact

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Matrix Acidizing 1. Sandstone:

• Major Effects: Dissolves/Disperses Damage Restores Permeability

• Minor Effects: Minor Stimulation

2. Limestone:• Major Effects:

Enlarge Flow Channels/Fractures Disperse Damage by Dissolving Surrounding Rock Creation of Highly Conductive Wormholes

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Applications For Matrix Treatment

High Permeability Formation with Damage.

Unproppable Formations.

Treating Limitations.

Thick Zones.

To Supplement Fracturing.

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Low Permeability Reservoir Increase well productivity by creating a highly conductive path

compared to the reservoir permeability.

The fracture will extend through the damaged near wellbore area. The fracture size is limited to two criteria :

• Drainage Radius• Cost

Fracturing is : Pumping fluid into the formation above fracture pressure.

Damage

XL

XL = Fracture half length

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Darcy’s Equation

Oil Well : Oil Well : Gas Well : Gas Well :

q = kh (Pe - Pwf)

141.2 µ (In rerw + S)

q = kh (Pe2 - Pwf2)

1424 µzT (In rerw + S)

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Skin (s) The total Skin (ST) is the combination of mechanical and pseudo-skins. It

is the total skin value that is obtained directly from a well-test analysis.

Mechanical Skin:• Mathematically defined as an infinitely thin zone that creates a steady-

state pressure drop at the sand face.• S > 0 Damaged Formation• S = 0 Neither damaged nor stimulated• S < 0 Stimulated formation

Pseudo Skin:• Includes situations such as fractures, partial penetration, turbulence,

and fissures. The Mechanical Skin is the only type that can be removed by stimulation.

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Skin Example Pseudo Skin:

• Producing at high rates --> turbulence• Collapsed tubing, perforations• Partial penetration / Partial perforation• Low Perforation Density (Shots/ft)• Etc.

Formation Damage:• Scales• Organic/Mixed Deposits• Silts & Clays• Emulsions• Water Block• Wettability Change

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Example An oil well produces 57 B/D under the following reservoir and producing

conditions:

k = 10 md

h = 50 ft

ßo = 1.23 res bbl/stb

µo = 0.6 cp

Pr = 2,000 psi

Pwf = 500 psi

rw = .33 ft

re = 1,320 ft

What is the Skin Factor?

Is there potential for Stimulation?

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INTRODUCTION TO MATRIX TREATMENT

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Formation Damage

Damage Definition :

• Partial or complete plugging of the near wellbore area which reduces the original permeability of the formation.

• Damage is quantified by the skin factor ( S ).

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Types of Formation Damage Emulsions

Wettability Change

Water Block

Scale Formation

Organic Deposits

Mixed Deposits

Silt & Clay

Bacterial Slime

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Areas of Damage

Scales

Organic deposits

Silicates, Aluminosilicates

Emulsion

Water block

Wettability change

Tubing Gravel Pack Perforations Formation

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Emulsions Definition:

• Formed by invasion of filtrates into oil zones or mixing of oil-based filtrates with formation brines.

• Any two immiscible fluids

Keys to Diagnosis:• Sharp decline in production• Water breakthrough• Production of solids• Fluid samples• Injection of inhibitors

Treatment:• Surfactants • Mutual solvents

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Wettability Change Definition:

• Oil wetting of rock from hydrocarbon deposits or adsorption of an oleophilic (attracts oil) surfactant from treating fluid.

Keys to Diagnosis: (Normally difficult to diagnose)• Rapid production decline• Casing leak• Water breakthrough• Water coning• Decrease or disappearance of gas

Treatment:• Mutual solvent followed by water-wetting surfactant.

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Water Block Definition:

• Caused by an increase in water saturation near the wellbore which decreases the relative permeability to hydrocarbons.

Keys to Diagnosis: • Rapid oil or gas production decline• Casing leak• Water breakthrough• Water out• Abnormally high water cut through lower perforations

Treatment:• Mutual solvents or surfactants

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Scale Formation Definition:

• Scales are precipitated mineral deposits. Scale deposition occurs during production because of lower temperatures and pressures encountered in or near the wellbore.

Keys to Diagnosis: • Sharp drop in production• Visible scale on rods/tubing• Water breakthrough

Treatment:• Carbonate (Most Common)

HCl, Aqueous Acetic• Sulfate

EDTA NARS

• Chloride 1 - 3% HCl

IronIron» HCl with various iron control agentsHCl with various iron control agents

SilicaSilica» Mud AcidMud Acid

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Keys to Diagnosis of a SampleFloats in H2O 2

Soluble in H O2

Soluble in HCl

No

Soluble in hot HCl

No

No

Iron Oxide

Magnetic

Magnetite FeCo

Soluble in U42

Soluble in hot HCl/HF

3

No

No

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

No

Organic

NaCl (probably)

Odor of rotten eggs

Silica Base (sand/clay)

SrSO (slow) BaSO (very slow)

CO Evolves

FeCO

Fe (CO ) CaCO

MgCO Ca(SO ) slowly soluble (also soluble in U42)

FeS (possible)

3

2 3 3

3

3

4 2

2

4

4

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Scales : Inorganic Mineral Deposits

Types of Scale

Usual Occurrence

Treating Fluids Comments

Carbonates CaCO3 HCl Very Common

Sulfates

CaSO •2H O (gypsum)

BaSO /SrSO

EDTA

EDTA

Common

Rare

Chlorides NaCl H O/HCl Gas Wells

IronFe S

Fe O

HCl + EDTA

HCl + Sequestering Agent

CO /H S Possible Produced

Silica SiO HF Very Fine

Hydroxides Mg/Ca(OH) HCl

4

4 4

3

2

2

2

2

22

2

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Organic Deposits Definition:

• Organic deposits are precipitated heavy hydrocarbons (parrafins or asphaltenes). They are typically located in the tubing, perforations and/or the formation.

• The formation of these deposits are usually associated with a change in temperature or pressure in or near the wellbore during production.

Keys to Diagnosis: • Sharp decline in production• Visual parrafin on rods and pump• Operator is "hot oiling"

Treatment:• Aromatic Solvents (Xylene, Toluene)• Mutual Solvents

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Keys to Diagnosis of Actual Organic Deposit

Floats in water Yes Organic Deposit

1. Burns evenly with clean flame Yes Paraffin/wax

No

Black sooty flame Yes Asphaltene

2. Soluble in pentane Yes Paraffin

No

Asphaltene

3. Soluble in Toluene/Xylene Yes Paraffin/ Asphaltene

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Silts & Clays Definition:

• Damage from silts and clays includes the invasion of the reservoir permeability by drilling mud and the swelling and/or migration of reservoir fines.

• Keys to Diagnosis: • Sharp drop in production• Lost circulation during drilling• Production tests• ARC tests

Treatment:• HCl: Carbonate Reservoirs• HF Systems: Sandstone• Quaternary Amine Polymers (L55)• Cationic Surfactant (M38B)• Fusion (Clay Acid)

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Bacterial Slime

Definition:• Anaerobic bacteria grows downhole without oxygen up

to 150°F. Bacteria may chemically reduce sulfate in a reservoir to H2S.

Treatment:• M91 (Bleach+Caustic soda)

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Sources of Formation Damage Drilling

Cementing

Perforating

Completion and Workover

Gravel Packing

Production

Stimulation

Injection Operations

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Successful Matrix Treatment

REQUIREMENTS :

• Enough Treating Fluid Volume

• Correct Reactive Chemicals

• Low Injection Pressure

• Total Zone Coverage

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INTRODUCTION TO FRACTURING

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Applications For Hydraulic Fracturing

If wells natural permeability is low ( Ke < 10 md )

Natural production is below economic potential

Skin By-Pass “ HyperSTIM “ or higher permeability and soft formations.

The injected fluid is pumped at a rate above the fracture pressure of the reservoir to create cracks or fractures within the rock itself.

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Hydraulic Fracturing Treatment

Primary Purpose :• To increase the effective wellbore area by creating a

fracture of length XL whose conductivity is greater than that of the formation.

Dimensionless Conductivity ( Fcd ) = Kf Wf / Ke Xf

Two Methods :• Sand Frac• Acid Frac

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Propped Frac & Acid Frac

1/2"open fractureduring job

fracture tends to closeonce the pressure has been

released

sand used to prop thefrac open

acid etched frac walls

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Propped Fracture Optimization

Optimize the reservoir deliverability by balancing fracture characteristics and reservoir properties

Analyze the effect of production systems :• Perform => Nodal Analysis

Determine the pumping parameters :• DataFRAC

Tailor the fracturing fluid and proppant to the reservoir Determine treatment size (Fluid & proppant amount)

• Calculate XLand FCD

Calculate the benefit of the treatment => $• FracNPV

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Acid Fracture

Bottom hole pressure above fracturing pressure

Acid reacts with the formation

Fracture is etched

Formation must retain integrity without fracture collapse

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Hydraulic Fracturing Accomplishes:

Creates Deep Penetrating Fractures to :

Improve productivity Interconnect formation permeability Improve ultimate recovery Aid in secondary recovery Increase ease of injectivity

• A hydraulic Fracture has to be cost effective to the customer.

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Fracture Penetration is influenced by: FORMATION CHARACTERISTICS :

• Type • Hardness• Permeability• Zone Height “ Presence of Barriers “• Drainage Radius

FRAC FLUID CHARACTERISTICS :• Base Fluid• Viscosity• Volume• Pump Rate• Fluid Loss

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Orientation Of The Fracture

The fracture will extend perpendicular to the axis of the least stress.

• X - Y - Z Coordinate :Overburden Pressure

Least Principal Stress

Favored Fracture Direction

(i.e. Vertical Fracture)

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Vertical Or Horizontal Fracture

Rule-Of-thumb :• Frac Gradient < 0.8 psi / ft --------> Vertical Fracture• Frac Gradient > 1.0 psi / ft --------> Horizontal Fracture

Vertical fracture plane is perpendicular to earth’s surface due to overburden stress being too great to overcome

Horizontal fracture with a pancake likegeometry. Usually associated withshallow wells of less than 3,000 ft. depth

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Fracture Propagation Models

KGD

• XL < h

PKN

• XL > h

Radial

• XL = h/2

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Rock Mechanical Behavior Young’s Modulus :

• E =

Poisson’s Ratio : L1 - L2 / L1

d1 - d2 / d1D1

D2

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Rock Mechanical Behavior

Young’s Modulus :• E =

Poisson’s Ratio : L1 - L2 / L1

d1 - d2 / d1

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Fracture Width

W = ( Q L) 1/4 PKN E

W = ( QL2)1/4 KGD EH

= Viscosity of fluid

• Q = Injection Rate • H = Gross Height

• L = Xf

• E = Young’s Modulus

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Net Present Value FracNPV BENEFITS :

• Design lowest cost job• Realize full production rate potential• Forecast post treatment decline• Study impact of treatment variables

APPLICATION :

• Select optimum XL, W & proppant type

• Aid in determining whether or not to fracture a new well• Determine size of production equipment• Evaluation of the fracture treatment based on well performance

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FracNPV

52

0 100 200 300 400 500

Hydraulic Half-Length - ft

-100000

0

100000

200000

300000

400000

500000

600000

Ne

t Pre

se

nt V

alu

e -

$(U

S)

YF120LG

ClearFRAC (3

Production time 1 year

Fluid Type

FracCADE*

*Mark of Schlumberger

Net Present Value

Well XXXX1235.5//1249.508-26-1997

Design

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Conclusion Three Types of Stimulation :

• Wellbore Clean-up• Matrix Treatment• Hydraulic Fracturing

Well Candidate Selection :• What is it ?• How does Dowell Schlumberger use it ?• What are some of the tools associated with it ?

NPV• What is it ?• How can it be used to design a treatment ?• How does the output benefit our customers and us ?