Introduction to Stimulation

Introduction to Reservoir

Stimulation

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}

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)}

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

WELLBORE

•

Primary Purpose :

Restore flow capacity by removing restrictive damage to

fluid flow in the wellbore.

•

Methods :

•

_Mechanical

•

_{Chemical Treatment}

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 0 1,000 ft 4,934 2.5 100 ft 4,719 10.8 50 ft 4,654 1.3 psi/ft 13.3 20 ft 4,568 16.6 10 ft 4,503 6.5 psi/ft 19.0 5 ft 4,439 21.5 3 ft 4,391 23.3 2 ft 4,000 850 psi/ft 24.8 1 ft 3,150 27.3 (Pwf) 0 ft 2,000 1,150 psi/f 100

Major Goals of Matrix Treatment

•

1. Restore Natural Permeability

•

_{By Treating the Critical Matrix}

•

2. Minor Stimulation

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

Applications For Matrix Treatment

•

High Permeability Formation with Damage.

•

Unproppable Formations.

•

Treating Limitations.

•

Thick Zones.

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

X_L

Darcy’s Equation

Oil Well :

Oil Well :

Gas Well :

Gas Well :

q =

kh (P

e

- P

wf

)

141.2

β

µ (In r

_r

_we

+ S)

q =

kh (P

e2

- P

wf2

)

Skin (s)

•

The total Skin (S

_T

) 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.

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

Example

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

conditions: k = 10 md h = 50 ft ß_o= 1.23 res bbl/stb µ_o= 0.6 cp P_r= 2,000 psi P_wf = 500 psi r_w = .33 ft r_e = 1,320 ft

• What is the Skin Factor?

INTRODUCTION TO MATRIX

TREATMENT

Formation Damage

•

Damage Definition :

•

_{Partial or complete plugging of the near wellbore area}

which reduces the original permeability of the formation.

Types of Formation Damage

• Emulsions • Wettability Change • Water Block • Scale Formation • Organic Deposits • Mixed Deposits • Silt & Clay

Areas of Damage

Scales Organic deposits Silicates, Aluminosilicates Emulsion Water block Wettability change

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}

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:

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:

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 ■

_Iron

_Iron

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

■

_Silica

_Silica

Keys to Diagnosis of a Sample

Floats 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

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

Iron Fe 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 2 2 2

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)

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/

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)}

Bacterial Slime

•

Definition:

•

_{Anaerobic bacteria grows downhole without oxygen up}

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

reservoir to H2S.

•

Treatment:

Sources of Formation Damage

• Drilling • Cementing • Perforating

• Completion and Workover • Gravel Packing

• Production • Stimulation

Successful Matrix Treatment

•

REQUIREMENTS :

•

Enough Treating Fluid Volume

•

Correct Reactive Chemicals

•

Low Injection Pressure

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.

Hydraulic Fracturing Treatment

•

Primary Purpose :

•

To increase the effective wellbore area by creating a fracture

of length X

_L

whose conductivity is greater than that of the

formation.

Dimensionless Conductivity ( Fcd ) = K

_f

W

_f

/ K

_e

X

_f

•

Two Methods :

•

Sand Frac

Propped Frac & Acid Frac

1/2"

open fracture during job

fracture tends to close once the pressure has been

released

sand used to prop the

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 X_Land F_CD

• Calculate the benefit of the treatment => $

Acid Fracture

•

Bottom hole pressure above fracturing pressure

•

Acid reacts with the formation

•

Fracture is etched

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.

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

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

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 like geometry. Usually associated with

Fracture Propagation Models

•

KGD

•

X

_L

< h

•

PKN

•

X

_L

> h

•

Radial

•

X

_L

= h/2

Rock Mechanical Behavior

• Young’s Modulus : • E = δ / ε • Poisson’s Ratio : ∀υ = ε 2 /ε 1 ε 1 = L1 - L2 / L1 ε 2 = d1 - d2 / d1 D1 D2

Rock Mechanical Behavior

• Young’s Modulus : • E = δ / ε • Poisson’s Ratio : ∀υ = ε 2 /ε 1 ε 1 = L1 - L2 / L1 ε 2 = d1 - d2 / d1

Fracture Width

• W = ( _µ Q L) 1/4 _PKN E • W = (µ QL2₎1/4 _KGD EH

−

µ

= Viscosity of fluid • Q = Injection Rate • H = Gross Height • L = X_f • E = Young’s Modulus

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

Design Execution Evaluation

DEE

Design

Identify The Potential

0 100 2 00 300 400 50 0 600 700 0 200 400 600 800 1000 1200 1400

Liq uid R a te, B b l/D

Pr es su re , p si g

In flow @ S andface (1 ) N ot U sed

In flow (1 ) O utflow (A)

C a se 2 (2) C ase 2 (B ) C a se 3 (3) C ase 3 (C ) N o t U sed N ot U sed N o t U sed N ot U sed N o t U sed N ot U sed N o t U sed 1 A 1 2 3 In flow In flo w R eservo ir S kin (1 ) 0 .000 (2 ) 1 0.00 0 (3 ) -2 .0 00

0 100 200 300 400 500 H ydraulic H a lf-Length - ft -100000 0 100 000 200 000 300 000 400 000 500 000 600 000 N e t P re s e n t V a lu e $ (U S ) YF120LG ClearFRAC (3

Production tim e 1 year

Fluid Type

FracCADE*

Net Present Value

W ell XXXX 1235.5//1249.5 08-26-1997

0 2500 5000 Stress - psi 1220 1230 1240 1250 1260 1270 W e ll D e p th m -0.3 -0.1 -0.0 0.1 0.2 0.3 AC L W idth at W ellbore - in 0 10 20 30 40 50 60 70 80 90 100 Fracture H alf-Length - m < 0.0 lb/ft2 0.0 - 0.2 lb/ft2 0.2 - 0.4 lb/ft2 0.4 - 0.6 lb/ft2 0.6 - 0.8 lb/ft2 0.8 - 0.9 lb/ft2 0.9 - 1.1 lb/ft2 1.1 - 1.3 lb/ft2 1.3 - 1.5 lb/ft2 > 1.5 lb/ft2

FracCADE*

ACL Fracture Profile and Proppant Concentration

W ell XXXX Logs 08-26-1997

DataFRAC* Service

Closure pressure Rebound pressure Net pressure B H P Fracture extension pressure

Closure Test

Calibration Test

Closure ISIP Increasing rate Constant rate Constant flowback

Shut-in Constant rate Falloff

Execution

_PE22 500 1000 1500 2000 2500 3000 3500 4000 P re s s u re ( P S I ) 5 10 15 20 25 R a te ( B P M ) - P ro p p a n t C o n c e n tr a ti o n ( P P A ) Treating_Pressure BHP-CADE Slurry_Rate Proppant_Conc

Evaluation

•

Realdata fracture

simulation, to adjust

leak off and Young

Modulus.

•

It can be performed in

Real Time.

0 2500 5000 1220 1230 1240 1250 1260 1270 W e ll D e p th m -0.3 -0.1 -0.0 0.1 0.2 0.3 0 10 20 30 40 50 60 70 80 90 100 < 0.0 lb/ft2 0.0 - 0.2 lb/ft2 0.2 - 0.3 lb/ft2 0.3 - 0.5 lb/ft2 0.5 - 0.7 lb/ft2 0.7 - 0.9 lb/ft2 0.9 - 1.0 lb/ft2 1.0 - 1.2 lb/ft2 1.2 - 1.4 lb/ft2 > 1.4 lb/ft2 FracCADE*

ACL Fracture Profile and Proppant Concentration

PE22 1235.5//1249.5 mts Real Job 08-26-1997 0 2500 5000 Stress - psi 1220 1230 1240 1250 1260 1270 W e ll D e p th m -0.3 -0.1 -0.0 0.1 0.2 0.3 ACL Width at Wellbore - in

0 10 20 30 40 50 60 70 80 90 100 Fracture Half-Length - m < 0.0 lb/ft2 0.0 - 0.2 lb/ft2 0.2 - 0.4 lb/ft2 0.4 - 0.6 lb/ft2 0.6 - 0.8 lb/ft2 0.8 - 0.9 lb/ft2 0.9 - 1.1 lb/ft2 1.1 - 1.3 lb/ft2 1.3 - 1.5 lb/ft2 > 1.5 lb/ft2 FracCADE* *Mark of Schlumberger

ACL Fracture Profile and Proppant Concentration

Well XXXX Logs 08-26-1997

Evaluation

Forecast vs Actual Production

PE22 Production 0 100 200 300 400 500 600 700 0 50 100 150 200 250 Days B O P D Pe22 Forecast PE22 Bbl/d

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 ?