Sonatrach's Stimulation

Development Phase

September – October 2005©abalt solutions limited - 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION

Abalt Solutions

Introduction to Hydrocarbon Exploitation

©2005 Abalt Solutions Limited. All rights reserved

Stimulation Techniques

Pratap Thimaiah

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Characterizing Damage and Stimulation

1. List causes of damage skin2. List causes of geometric skin3. Calculate skin from pressure drop4. Calculate flow efficiency from skin5. Calculate skin factor and wellbore radius6. Convert skin to fracture half-length

Development Phase



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Damage Caused by Drilling Fluid

Mud filtrateinvasion

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Damage Caused by Production

p < pb p > pb

In an oil reservoir, pressure near well may be below bubblepoint, allowing free gas which reduces effective permeabilityto oil near wellbore.In a retrograde gas condensate reservoir, pressure near wellmay be below dew point, allowing an immobile condensatering to build up, which reduces effective permeability to gasnear wellbore.

Development Phase



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Damage Caused by Injection

“dirty”water

incompatiblewater

Injected water may not be clean - fines may plug formation.Injected water may not be compatible with formation water -may cause precipitates to form and plug formation.Injected water may not be compatible with clay minerals information; fresh water can destabilize some clays, causingmovement of fines and plugging of formation.

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Reservoir Model of Skin Effect

Bulkformation

h

rw

ka

ra

k

Alteredzone

Development Phase



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Reservoir Pressure Profile

500

1000

1500

2000

1 10 100 1000 10000Distance from center of wellbore, ft

Pre

ssu

re,

psi

ps

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Skin and Pressure Drop

spqB

hk00708.0s

k = mdh = ftq = STB/DB = bbl/STBps = psi = cp

Development Phase



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Skin and Pressure Drop

skh

qB2.141ps

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Skin Factor and Properties of the Altered Zone

w

a

a rrln1

kks

Development Phase



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Skin Factor and Properties of the Altered Zone

wa

a

rrlns

1

kk

The skin factor may be calculated from the properties of the altered zone.If ka < k (damage), skin is positive.If ka > k (stimulation), skin is negative.If ka = k, skin is 0.

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Effective Wellbore Radius

w

wa

rr

lns

swwa err

•If the permeability in the altered zone ka is much larger than the formationpermeability k, then the wellbore will act like a well having an apparentwellbore radius rwa .•The apparent wellbore radius may be calculated from the actual wellboreradius and the skin factor.

Development Phase



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Minimum Skin Factor

w

emin r

rlns

The minimum skin factor possible (most negative skin factor) would occur whenthe apparent wellbore radius rwa is equal to the drainage radius re of the well.

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Geometric Skin - Converging Flow to Perforations

When a cased wellbore is perforated, the fluid must converge toone of the perforations to enter the wellbore. If the shot spacing istoo large, this converging flow results in a positive apparent skinfactor. This effect increases as the vertical permeabilitydecreases, and decreases as the shot density increases.

Development Phase



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Geometric Skin - Partial Penetration

h

hp

A well is completed through only a portion of the net payinterval, the fluid must converge to flow through a smallercompleted interval. This converging flow also results in apositive apparent skin factor

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Partial Penetration

hp

ht

h1

pdp

t sshh

s

Where : Ht =pay thickness ft

hp=perforated thickness

h1=height to top of perforations

Kv=Vertical permeability (md)

Kh=Horizontal permeability(md)

Rd=dimensionless radius

Development Phase



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Partial Penetration Apparent Skin Factor

21

11

2ln1

2ln11

BA

h

h

hrhs

pD

pD

pDDpDp

21

h

v

t

wD k

khr

r

tppD hhh

tD hhh 11

41

1 pDD hhA

431

1 pDD hhB

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Geometric Skin - Deviated Wellbore

sechh

sss d

When a well penetrates the formation at an angle other than90 degrees, there is more surface area in contact with theformation. This results in a negative apparent skin factor.This effect decreases as the vertical permeability decreases,and increases as the angle from the vertical increases.

Development Phase



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Geometric Skin - Well With Hydraulic Fracture

Lf

Often to improve productivity in low-permeability formations, or to penetratenear-wellbore damage or for sand control in higher permeability formations, awell may be hydraulically fractured.

This creates a high-conductivity path between the wellbore and the reservoir.If the fracture conductivity is high enough relative to the formation permeabilityand the length of the fracture, there will be virtually no pressure drop down thefracture. This distributes the pressure drop due to influx into the wellbore overa much larger area, resulting in a negative skin factor.

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Skin Factor and Fractured Wells

2L

r fwa

waf r2L

Development Phase



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Completion Skin

dpdp ssss

d

R

dp

R

p

dp

pdp k

kkk

r

r

nLh

s ln

rdp

Lp

kR

kdp

kd

rp

rd

rw

After McLeod, JPT (Jan. 1983) p. 32.

sp- geometric skin due to converging flow toperforationssd - damage skin due to drilling fluid invasionsdp - perforation damage skinkd - permeability of damaged zone aroundwellbore, mdkdp - permeability of damaged zone aroundperforation tunnels, mdkR - reservoir permeability, mdLp - length of perforation tunnel, ftn - number of perforationsh - formation thickness, ftrd - radius of damaged zone around wellbore, ftrdp - radius of damaged zone around perforationtunnel, ftrp - radius of perforation tunnel, ftrw - wellbore radius, ft

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Gravel Pack Skin

Lg

Cement

Sgp - skin factor due to Darcy flow throughgravel packh - net pay thickness,ftKgp - permeability of gravel pack gravel,mdk - reservoir permeability, mdLg - length of flow path through gravel pack,inn - number of perforations opendp – diameter of perforation tunnel, in

Sgp = 96 (K/Kgp) h Lg

dp2 n

Development Phase



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Productivity Index

wfppq

J

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Flow Efficiency

wf

swf

ideal

actualf pp

pppJJ

E

We can express the degree of damage on stimulation withthe flow efficiency.For a well with neither damage nor stimulation, Ef = 1.For a damaged well, Ef < 1For a stimulated well, Ef > 1

Development Phase



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Flow Efficiency and Rate

fold

fnewoldnew E

Eqq

qnew = Flow rate after change in skin factorqold = Flow rate before change in skin factorEfnew = Flow efficiency after change in skin factorEfold = Flow efficiency before change in skin factor

We can use the flow efficiency to calculate the effectsof changes in skin factor on the production ratecorresponding to a given pressure drawdown

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Remove damage near the wellbore

Superimpose a highly conductive structure onto theformation

Increase the effective area of the reservoir in communicationwith the wellbore

Well Stimulation Objectives

Increase theIncrease theproductivityproductivityof a well by:of a well by:

Production EnhancementProduction Enhancement

Development Phase



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Primary Methods of Stimulation

Matrix acidizing Hydraulic fracturing(acid or proppant)

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Hydraulic Fracturing

Hydraulic fracturing is a stimulation technique whichconsists in fluid injection into the formation at high flowrates, causing an increase in pressure and a subsequentformation breaking.

Development Phase



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Hydraulic Fracturing

The breakdown and early growth,expose new formation area to theinjected fluid.

The injected fluid leaking off into theformation starts to increase.

If the pumping rate is maintained ata higher rate than the fluid loss rate,then the fracture must continue topropagate & grow.

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Hydraulic Fracturing Once pumping stops, the fracture closes. In order to prevent this, it is added propping agent to the injected

fluid to be transported into the fracture. When pumping stops and the fluids flows back from the well, the

propping agent remains in place to keep the fracture opened. A conductive flow path for the increased formation flow area is

created.

Development Phase



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Hydraulic Fracturing Objectives

Clearing Skip damaged area around thewellbore.

Productivity increase is attached to decreasethe high velocities at the near-wellbore area dueto drawdown

Asphaltene deposition prevention.

Natural fractures connection

Scale deposition and H2S prevention: Timereleased chemicals.

Water conning retardation

Production Enhancement through:Production Enhancement through:

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Impact on Performance

Hydraulics fractures can be classified accordingto one of three models:

infinite conductivity model– assuming no pressure loss in the fracture

uniform flux model– assumes a slight pressure gradient in the fracture

finite conductivity model– assumes constant and limited permeability in the

fracture from proppant crushing or poor proppantdistribution.

Development Phase



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The fracture case can beapproximated by an equivalentwellbore having the same areaas the fracture, and the radiusof this wellbore is rw’

Effective wellbore radius

rrww’’rrww

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Production from DarcyProduction from Darcy’’s Law (radial flow)s Law (radial flow)

Q: Stabilized production rate for oil BPDk: Effective formation permeability, mDh: Formation thickness, ftpavg: Average reservoir pressure, psipwf: Bottomhole flowing pressure, psi: Fluid viscosity, cpo: Oil formation volume factor,re: Drainage radius, ftrw: Wellbore radius, fts: Skin effect

srr

ppkhxQ

weo

wfavg

75.0/472.0ln

)(1008.7 3


Development Phase



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Production increaseProduction increase


we

we

i

f

rrrr

Q

QPI

/ln/ln

Qf = Stabilized production after fracQi = Stabilized production before fracre = Drainage radiusrw = Wellbore radiusrw’ = Effective wellbore radius

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Production increase calculations assumptionsProduction increase calculations assumptions

Steady state productionSame drawdown for each production rateSingle phase flowNo skin damage for production before fracture

Development Phase



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Damage bypass.

Fracture length becomesless important.

Geometry: Short and widefractures.

High permeability formations (k>20 mD)High permeability formations (k>20 mD)

Hydraulic Fracturing Types

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Put more reservoir area incontact with the well.

Fracture length controlsproduction increase

Geometry: Long andnarrow fractures

Low permeability formations (kLow permeability formations (k<1<1 mD)mD)

Hydraulic Fracturing Types

Development Phase



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Production History

Oil

Flo

wra

te

Time (months)00 1010 2020 3030

(bp

d)

101011

101022

101033

101044

Without fracture

With fracture

Effect over productionEffect over production


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Effect over productionEffect over productionProductionProduction

performanceperformance

4000

6000

8000

10000

12000

0 1000 2000 3000 4000 5000 6000Bo

tto

mh

ole

flo

win

gp

res

sure

(psi

a)

Oil flow rate (bpd)

1/41/4””

3/83/8””

7/167/16””

Productivity Index0.58 bpd/psi

Productivity Index8.0 bpd/psi


Development Phase



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Hydraulic Fracturing Design

Proper treatment design is tied to severalProper treatment design is tied to severaldisciplines:disciplines:

Production engineeringRock MechanicsFluid MechanicsSelection of optimum materialsOperations

It is a multidisciplinary approach with a multitude of variablesinvolved, with some uncertainty in the absolute values of thesevariables: Engineering judgment is very important.

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Fracture Design Base Sequence

1. Identification of

elastic constants,

effective stress

stress field orientation.

2. Fluid selection system.

3. Proppant selection

4. Fracture propagation model on the basis

of in-situ stress and laboratory tests

calibration treatments

log analysis (e.g. stress profile, gamma ray, sonic logs).

5. Tubing stress analysis

Development Phase



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Fracture Design Base Sequence

6. Determine

fracture penetration

fracture conductivity

7. Determine

injection rates

fluids and proppant volumes required and fracture conductivityobtained.

8. Determine the production rate and cumulative recovery over aselected period of time for a specific propped penetration

9. Calculate the NPV

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Fracture Design - Input data

Geomechanical

•Poisson's Ratio (Logs, Core Tests)•Young’s Modulus (Logs, Core Tests)•Fracture Toughness (Tests, HistoryMatch)•Minimum Horizontal Stress(Minifrac, Calculations)•Stress Contrasts (Logs, Core Tests)

Reservoir

•Porosity (logs, cores)•Compressibility (Test, Calculations)•Net Pay (Logs, Cores)•Permeability (Cores, Tests)•Fluid Viscosity (Lab Tests, PVT)•Fluid Compressibility (Lab Test, PVT)

Fracture Fluids

•Rheology (Lab Tests)•Density (Lab Tests)•Filter Cake (Lab Tests)•Filtrate Viscosity (Lab Tests)

Completion

•Completion Schematic.•Tubular and Connections Ratings•Completion components specifications

Development Phase



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Rock Mechanics in Hydraulic Fracturing

In situ stressesIn situ stresses

The minimum in-situ stress is thedominant parameter controllingfracture geometry.

The minimum in situ stress isgenerally horizontal.

Hydraulic fractures are alwaysperpendicular to the minimum stress,except in some complex cases.

Direction of theminimumhorizontal

stressHmin

Direction of themaximumhorizontal

stressHmax.

Direction of thevertical stress

V

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Rock Mechanics in Hydraulic Fracturing

Stresses field and wellbore orientationStresses field and wellbore orientation

Schematic of the orientation of hydraulicfractures for two horizontal wells

Orientation of hydraulic fracturesbetween the minimum and maximum

principal stresses

Development Phase



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Geometry modelsGeometry models

2D Model

•The fracture height estimated remains constant for the simulation.• The fracture length grows from a line source of perforations, and alllayers have the same penetration.•The simulation can be approximated by the average modulus of allthe layers.

•KGD (De Klerk-Geertsma) the fracture height is relatively largecompared with its length.•PKN (Perkins-Kern) the fracture length is the much largecompared with its height.

Rock Mechanics-ModelsRock Mechanics - Models

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Geometry modelsGeometry models

Pseudo 3D model

•Pseudo three-dimensional model is the same as the PKN model – that is,vertical planes deform independently.•The height of the fracture depends on the position along the fracture andthe time.•A vertical fracture will grow in a layered medium as a function of thelayer properties

Rock Mechanics-ModelsRock Mechanics - Models

Development Phase



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Rock Mechanics - Models

2D models as a function of2D models as a function of PP

L: Fracture half length ; W: Fracture width; C: Leak off coefficient H:heigh

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Fracturing fluids

Sufficient Viscosity to Create Fracture

Low Friction Pressure to Minimize Equipment Horsepoweron Location

Sufficient Leakoff Control to Efficiently Create andPropagate Fracture

Sufficient Viscosity to Transport Proppant

Must lose Viscosity (or “break”) after placement tofacilitate production

Development Phase



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Fracturing fluids

Year

0

20

40

60

80

100

49 53 57 61 65 69 73 77 81 85 89 93 97

%T

reat

me

nts

Water

Oil

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Fracturing fluids

Oil fluids

Non-damaging to clays

Compatible with formation fluidsMore expensive & operationally difficult to handle. Only

used in extremely water sensitive formations.

Water fluids

SafeAvailable

EconomicalControlled break times

Broad temperature range

Development Phase



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Fracturing Fluids

ViscosityViscosity

Newtonian FluidNewtonian FluidViscosity = Stress / Shear Rate

NonNon--Newtonian FluidNewtonian FluidViscosity = k/(1-n)

Power law Model of Viscosity used in FractureSimulations= Shear ratek = Consistency Index.n = Fluid Behaviour index

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Fracturing fluids

Fracturing Fluids Chemicals

Polymers

Cross linkerspH Control

Gel BreakersClay Control

SurfactantsFluid loss Additives

Biocides

Development Phase



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Fracturing fluids - Polymers

Hydrated Polymer

+ H2O

Dry polymer is added to water to swell (hydrate),forming a viscous gel fluid.

Base GelDry polymer

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Fracturing fluids - High Viscosity Guar

Can be used inbrines.6-8 % residue.Easy to crosslink.40 Lb/Mgal 36 cp

Viscosity of Linear GuarViscosity of Linear GuarFluids vs. TemperatureFluids vs. Temperature

Development Phase



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Fracturing Fluids – Hydroxypropyl Guar (HPG)

Can be used in brines.

1-2 % residue.

Good crosslink control

Good thermal stability-High

temperature wells

20 lb/Mgal 30 lb/Mgal 40 lb/Mgal

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Fracturing Fluids CarboxymethylhydroxypropylGuar(CMHPG)


1-2 % residue.

Good crosslink control.

Excellent thermal stability.

40 lb/Mgal 28 cp

Development Phase



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Fracturing Fluids - Hydroxyethyl Cellulose (HEC)


Residue Free.Not Crosslinkable.

Limited Thermal Stability.

40 lb/Mgal 46 cP

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Bio-polymer and behaves like a power fluid


3% Residue.Difficult to break control

Easy to Crosslink.

Good Thermal stability.40 lb/Mgal 20 cp

More expensive than gaur but provide better

suspension

Fracturing Fluids – Xanthan (XC)

Development Phase



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Liquid Gel Concentrates ( LGC )Liquid Gel Concentrates ( LGC )

A dispersion of non-swelling polymer stabilized in

a hydrocarbon base

50 % polymer + 50 % diesel

Fracturing Fluids – LGC

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Fracturing Fluids – Crosslinking agent

Metal Ions used to cross link

polymers

Borate

Zirconium

Titanium

Antimony

Aluminium

Crosslink ReactionCrosslink Reaction

Linking the –OH at high Ph

Development Phase



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Fracturing Fluids – Crosslinked Frac fluids

350BG,HPG

400ZrCMHPG

275ZrCMHPG

200BG

300BG,HPG

300TiHPG

300B+ZrG

275ZrG

Max. Temp ºFCrosslinkerPolymer

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•Relatively high viscosity fluids are used to transport proppantinto the fracture.

•Leaving a high-viscosity fluid in the fracture would reduce thepermeability of the proppant pack to oil and gas, limiting theeffectiveness of the fracture treatment.

•Gel breakers are used to reduce the viscosity of the fluidintermingled with the proppant.

•Breakers reduce viscosity by cleaving the polymer into small-molecular weight fragments.

•The most widely used fracturing fluid breakers are oxidizersand enzymes.

Fracturing Fluids – Gel breakers

Development Phase



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EnzymesEnzymes-- HemicellulaseHemicellulaseSoluble / 60 -140 °F / pH 4 -8

Encapsulated / 75 - 175 °F / pH 4 –9They begin to degrade the polymer on mixing at

ambient temperatures.

Oxidizers (Soluble and encapsulated)Oxidizers (Soluble and encapsulated)Ammonium peroxydisulfateCalcium peroxideSodium bromate


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SeSelection of Breakerlection of Breaker


Development Phase



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pH ControlpH Control

High pH (12) for Borate crosslinked fluids.

0 7 14

Basic

Neutral

Acid

)(HLogpH

Importance of pH controlImportance of pH control

Polymer Hydration rate. Crosslinking rate.

Gel Stability

Gel Break rate.

Fracturing Fluids – pH control

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pH Control ChemicalspH Control Chemicals

AcidAcid Sulphamic Acid Acetic Acid (CH3COOH) Fumaric Acid, Organic acid. HCL

BaseBase Sodium bicarbonate. Sodium carbonate Liquid carbonate Solution 25% NaOH

Fracturing Fluids – pH control

Development Phase



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Properties of SurfactantsReduce interfacial tension and capillary pressureAlter wetting properties of surfaces-Formation

conditioning agents Stabilize or break emulsionsStabilize Foams and prevent sludge

Fracturing Fluids – Surfactants

Surfactants molecules have two distinct parts.

Water Soluble HeadWater Soluble HeadOil Soluble TailOil Soluble Tail

A surface active agent that at low concentration adsorbsat interface between two immiscible substances.

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Surfactants migrate to interface between solids, liquidSurfactants migrate to interface between solids, liquidand gasesand gases

Water Oil

Fracturing Fluids – Surfactants

Development Phase



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Inorganic SaltsKCL, NACL, CaCL2, NH4CL

Cationic Polymers-Quaternary amines

Fracturing Fluids – Clay swelling control

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Fracturing Fluids – Fluid loss

Fluid LossFluid LossFluid loss to the formation during a fracturing treatment is a filtrationprocess that is controlled by a number of parameters, including fluidcomposition, flow rate and pressure, and reservoir properties such aspermeability, pressure, fluid saturation, pore size and the presence ofmicro fractures.

Fluid Loss ControlFluid Loss ControlFiltrate viscosity and relative permeability.Wall-building fluids: Filter Cake.

(polymer and/or fluid-loss additives, silica, starch, soaps, waxes)Multi Phase Flow viscosity

Development Phase



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Fluid LossFluid Loss

Fracturing fluid

Gel Filter Cake

Zone Invaded by water

Uncontaminated Formation

Fracturing Fluids – Fluid loss

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Fracturing Fluids – Polymer damage

Development Phase



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PrimeFRAC

Low Polymer HighTemperatureFracturing Fluid

Fracturing Fluids – Low polymer/High T

Broad field water chemistry compatibility

No pre-treatment required

Thermally delayed crosslink easily controlled

Low buffered crosslink pH

Controllable viscosity reduction with breakers

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PrimeFRACStable Low Polymer Rheology Over a Broad Temperature Range

(30 ppt polymer, Fann50 B5Bob, API Testing)

0

100

200

300

400

500

600

700

800

0 50 100 150 200Time (minutes)

Vis

cosi

ty@

100

sec-1

(cp)

350°F

300°F

YF850HT -300°F250°F

Fracturing Fluids – Low Polymer/High T

Development Phase



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Viscoelastic Surfactant Based Systems (VES)

First polymer free, water-basedfracturing fluid

Commercialized in 1997

Three VES systems currentlyavailable

Fracturing Fluids – Viscoelastic

+ + + + + + + + + + +

+ + + + + + + + + + +

+

+

+ + + + + + + + + + + +

+ + + + + + + + + + +

+

+

+

+ + + + + + + + + + +

+ + + + + + + + + + +

+

+

+ + + + + + + + + + + +

+ + + + + + + + + + +

+

+

+

+ + + + + + + + + +

+ + + + + + + + + + ++

+

+ + + + + + + + + + +

+ + + + + + + + + + +

+

+

+

Viscoelastic Surfactant

Electrolyte

Rod Shaped Micelles

e.g.,

NH4Cl

KCl

MgCl2

+

=

ClearFRAC Principle

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Micellar Structure

Rod Shaped Wormlike

Fracturing Fluids – Viscoelastic

Development Phase



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Fracturing Fluids – Selection

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Proppant selection-Fracture conductivity

Fracture conductivityFracture conductivity

Placing the appropriate amount and type of proppant in thefracture is critical to the success of a hydraulic fracturingtreatment.

It is defined as the relative ease with which the injectedfracture fluids and proppants flow to the wellbore fracture.

Development Phase



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Proppant selection – Fracture Conductivity

Fracture ConductivityFracture Conductivity

Fracture permeability x Fracture width

Cf = kf x wf

Fracture withproppant

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Fracture lengthFracture widthProppant concentration-Physical propertiesProppant size and typeProppant transportClosure stress on proppant bedBottomhole temperatureTreatment fluid effects

Movement of formation fines

Factors affecting conductivityFactors affecting conductivity


Development Phase



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Closure stressClosure stress

The stress applied to the proppant bed when thefracture has closed.


Closure pressureClosure pressure

The pressure above reservoir pressure which a fracturewill open or close.This pressure is equal to the least principal stress.

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Proppants

They are used to hold the walls of fracture apart andcreate a conductive path to the wellbore after pumpinghas stopped and fracturing fluid leaked-off.

SandPremium sands come from Illinois, Minnesota andWisconsin. These sands greatly exceed API standards.They are commonly known as:

Northern sand; White sand; Ottawa sand; Jordan sand; St. Peters sand; Wonewoc sand.The specific gravity of sand is approximately 2.65.

Development Phase



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Resin Coated Sand Resin coatings may be applied to improve proppant

strength. The resin coating on the proppant is usually cured during

the manufacturing process to form a non melting, inertfilm.

When the grains crush the resin coating helpsencapsulate the crushed portions of the grains andprevents them from migrating and plugging the flowchannel.

Resin coated sands usually have a specific gravity ofabout 2.55.

Proppants

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Types of Proppants

Intermediate Strength Proppants Intermediate strength proppants (ISP) are fused ceramic

proppants that have a specific gravity between 2.7 and3.3.

ISP’s are mainly used for closure stress ranges between5,000 psi and 10,000 psi.

High Strength Proppants Sintered bauxite and zirconium oxide are high strength

propping agents with a specific gravity of about 3.4 orhigher.

Generally limited to wells with very high closure stresses.

Development Phase



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Effect of Proppant TypeEffect of Proppant Type

20/40, 200 °F, 2.0 lb/ft²

00:00 3000 6000 9000 12000 15000

Stress (psi)

0

2000

4000

6000

8000

10000

12000

Con

duct

ivity

(md*

ft)

Proppant TypeH BradyH OttawaH CARBOPROP/INTERPROPS SINTERED BAUXITE

At 7000 psi,Cond = 5336 md*ft


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Sand

Resin Coated Sand

Inter-Strength Ceramic

Inter-Strength Bauxite

High-Strength Bauxite

0 5 10 15 20

6

8

1015

20

Closure Stress psi x 1000

Proppant type vs. Closure stressProppant type vs. Closure stress


Development Phase



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Dimensionless Conductivity RatioDimensionless Conductivity Ratio -- CincoCinco--LeyLey

FCD: Dimensionless conductivity ratiokf: Fracture permeability (mD)k: Formation permeability (mD)w: Fracture width (ft)Xf: Fracture half length (ft)

FractureFractureConductivityConductivity

FormationFormationconductivityconductivity

f

fCD xk

wkF

Conductivity considerations

Excellent>50

Good10-50

Poor<10FcD

Excellent10000 md-ft

Good1000 md-ft

Poor100 md-ftk f.W

Excellent1000 D

Good100 D

Poor10 Dkf

CharacteristicValueQuantity

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Moderate permeability formationsModerate permeability formations(1 mD < k< 15 mD)(1 mD < k< 15 mD)

ECONOMIC ANALYSIS

Damage bypass.Fracture length becomesless important.Geometry: Short and widefractures.

High permeabilityHigh permeabilityformations (k>20 mD)formations (k>20 mD)

Put more reservoir area incontact with the well.Fracture length controlsproduction increaseGeometry: Long andnarrow fractures

Low permeability formationsLow permeability formations(k(k<1<1 mD)mD)

Conductivity considerations

Development Phase



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2)2) Proppant costProppant cost

Including,• Proppant,• Proppant transportation tolocation and storage,• Proppant pumping charges.

4) Other fixed costs4) Other fixed costsIncluding,

• Mobilization,• Personnel,• Well preparation (workoverrig, etc.)• Cleanup costs (coiled tubing,disposal, etc.)

1)1) Fluid costFluid cost

Including,• Fracture fluid,• Fracture additives,• Mixing and blending

charges,• Transportation, storage

and disposal charges.

3)3) Hydraulic horsepowerHydraulic horsepower(hhp)(hhp)

cost = ($/hhp)x((injectionrate x surface treatingpressure/40.8) +standby hhp)

Economic considerations

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Quality of the cement job forzonal isolation.

Size and conditions of wellboretubulars.

PerforationsWellbore deviation

Other factors to take into account for designOther factors to take into account for design


Development Phase



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Tubing stress analysis

Completion integrity during theHydraulic Fracture Treatment

•Define potential completion risks andIdentify the required operationalconsiderations to meet the specified safetyfactors for burst, tension and collapseunder the load conditions.

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Evolution of Proppant DistributionDuring Pumping

Evolution of Proppant DistributionEvolution of Proppant DistributionDuring PumpingDuring Pumping

The first proppant stage is injected

PadPad1 lb/gal1 lb/gal

c

Design

Development Phase



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At intermediate time

1 lb/galConcentrated

to 3 lb/gal

1 lb/gal1 lb/galConcentratedConcentrated

to 3 lb/galto 3 lb/gal3 lb/gal3 lb/gal

2 lb/galto

3 lb/gal

2 lb/galto

3 lb/galPadPad

c



Design

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At End of Pumping

1 lb/gal1 lb/galconcentratedconcentrated

to 5 lb/galto 5 lb/gal

55lb/gallb/gal

3 to 5 lb/gal3 to 5 lb/gal

ProppantProppantSettlingSettling

4 to 5 lb/gal4 to 5 lb/gal 2 to2 to5 lb/gal5 lb/gal

c

Design

Development Phase



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The pad volume determines how much fracture penetration can beachieved before proppant reaches the tip and stops penetration inthe pay zone.

Too much pad can cause that fracture tip continues to propagateafter pumping stops, leaving a large umpropped region near thefracture tip. An afterflow can occur in the fracture, carrying proppanttoward the tip and living a poor final proppant distribution.

The ideal schedule is one where the pad depletes and proppantreaches the fracture tip just at the desired fracture penetration isachieved and also just as pumping stops.

Design

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The tip screen-out fracturing technique applies hydraulic fracturingtechnology to create a wide, short, fracture that yields highproduction rates with reduced pressure drops. It can be a highlyeffective technique in stimulating maximum production from weakformations.

A TSO is designed to cause proppant to pack at an specific locationbecause of width restriction, pad depletion or slurry dehydration.

Once packing occurs, further fracture propagation ceases at thispoint, usually at the tip. Continued injection increases the hydraulicfracture width and final conductivity

Tip Screen-out (TSO)Tip ScreenTip Screen--out (TSO)out (TSO)

Design

Development Phase



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Strategic Locationson a Pressure Response Curve

Strategic LocationsStrategic Locationson a Pressure Response Curveon a Pressure Response Curve

Job execution

Inje

ction

Rate

Inje

ctio

nRa

te

Botto

mho

lePr

essu

reBo

ttom

hole

Pres

sure

Shut-inShut-inFlowbackFlowback

Injection RateInjection Rate

PressurePressure

Seco

ndIn

jecti

onSe

cond

Inje

ctio

n

Cycl

eCy

cle

Firs

tIn

ject

ion

Firs

tIn

jecti

on

Cycle

Cycl

e22

33444

55

66

77

88

11

1- Formation Breakdown

2- Propagation

3- Instantaneous Shut-In

4- Closure Pressure From Fall-Off

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Strategic Locations on a Pressure Response CurveStrategic Locations on a Pressure Response Curve

Development Phase



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Treatment schedule-ExampleJob execution

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Fcd = 0.9

Simulation results - Example

Job execution

Development Phase



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Job execution

Operation Layout

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Additives/proppant deposits

Manifold(inlet/outlet)

Blender

Job execution

Development Phase



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Pump Truck

Job execution

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Equipment

Reference treatmentReference treatment

Qmax: 60 bbl/minhhp used: 17600hhp Available: 20000Volume: 3.2 million lb proppant

Job execution

Development Phase



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Job execution

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MLD (Minilateral Lateral Drilling). The drilling of lateralstunnels around the wellbore, through the casing and cement intothe formation, creating a draining architecture (fish bonestructure) that will have a direct impact over the flowperformance in the well, depending on the number of tunnelscreated.

Formation Penetration (MLD tool): Up to 2 mt (6.6 ft), tunnels.

Description (MLD Tool): Downhole tool system designed toproduce communication tunnels, radially from an existingwellbore into reservoir rock, for up to 2 meters in length. The tooldrills one tunnel at a time, each requiring 10 to 20 minutes tocomplete, and is capable of making multiple tunnels during asingle run.

Alternative technology – wellbore communication

Development Phase



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Tool sizes: The MLD tool is available for casing sizes of 4 1/2", 5",5 1/2", 6 5/8", 7" , 8 5/8", 9 5/8".

Drilling Tunnels: The creation of the tunnels will be governed byfactors such as well depth and rock Lithology. The completion fluidwill also affect the number of tunnels that can be completed on asingle trip – normally the tool will be capable of 4 to 8 tunnels perrun.

Work over fluids: A selection of the work over fluid should be madebased on its compatibility with the formation fluids and mineralogyto reduce the risk of formation damage during the operation. Fluidssuch as light oil would often be a good choice.

Alternative technology – wellbore communication

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Pratap Thimaiah

Acidizing Applications

Development Phase



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Overview

Matrix stimulation is injecting an acid/solventat below the fracturing pressure of theformation

– to dissolve/disperse materials that impair wellproduction in sandstone reservoirs

– to create new, unimpaired flow channels incarbonate reservoirs

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Sandstone vs. Carbonate Acidizing

Sandstone:– A small fraction of the matrix is soluble– Relatively slow reacting acid dissolves the

permeability damaging minerals

Carbonate:– A large fraction of the matrix is soluble (>50%)– Rapid reacting acid creates new flow paths by

dissolving formation rock

Damagedzone

Wellbore

Development Phase



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Key Issues

Successful matrix treatments require

– Correct choice of fluid to attack damage

– Uniform placement of treating fluid

Improper placementincreases heterogeneity

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Candidate Selection

“Good Wells Make the Best Candidates forWell Stimulation” - Al Jennings

Candidate Selection (Recognition) is theprocess of identifying and selecting wells fortreatment which have the capacity for higherproduction and better economic return.

Development Phase



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Candidate Selection Process

– Review numerous wells.

– Review of well logs/records, reservoir characteristicsand information on the completion/previousworkovers.

– Map the productivity of each well.

– Establish reasonable upper production potential forfracturing and matrix stimulation techniques.

– Evaluate potential mechanical problems.

– Focus on wells with the highest reward and lowestrisk.

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1

10

100

1000

0 20000 40000 60000 80000 100000 120000

Cumulative Oil, Bbls

Oil

Rat

e,B

OP

D

offset well

Data Sources

Production History– Oil/Gas/Water

production– Decline curve– Drive mechanism

Logs– SP, Gamma, Porosity,

Production logs– Reservoir

characteristics Hydrocarbon Homogeneous/Laminat

ed Thickness WOC/GOC

Water oil contactGas-oil contact

Development Phase



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Data Sources Workovers Well tests

– Kh– Skin– Pres

Drilling records– Type of mud– Losses

Completion– Openhole/Cased/Fractur

ed– Directional survey– Tubing/Casing

USITCallipers

Build up test

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Establish Production Potential

Gap

Pre

ssu

re

Flow Rate

Reservoir

Tubing

Existingproduction

Potentialproduction

Development Phase



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Matrix Acidizing

Formation Damage Characterization

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Near-wellbore damage limits production

Swelling clays

Migrating clays/silts

Inorganicscales

Paraffin/Asphaltenedeposits

Drilling damage

Emulsion

damage

Wettability change

Damagereduces oil

flow

Development Phase



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Formation Damage Characterization

Fines Migration Swelling Clays Scale Deposits Organic Deposits

– Paraffins– Asphaltenes

Mixed Deposits Bacteria

Induced Particles– Solids– LCM/Kill Fluids– Precipitates

Oil Based Mud Emulsion Block Wettability Changes Water Block

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Silt and Clays = Fines

Origins– Indigenous - clays, silica fines– Drilling fluid invasion

Potential problems– Fines migration causes plugging– Clay swelling

High production rates can entrain particles andcause bridging.

Indicators of particle migration– Produced water may be turbid– Production decline increases with increasing flow

rate.– Clays and silica fines are insoluble in HCl.

Development Phase



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Inorganic mineral deposits. Formed due to supersaturation at wellbore

conditions or commingling of incompatible fluids. Form in the plumbing system of the well, in the

perforations or in the near-wellbore region. E.g.

– Calcium carbonate/sulfate– Barium sulfate– Iron carbonate/oxide/sulphide

Scale

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Linear or branched-chain saturated aliphatichydrocarbons– C20H42 to C60H122

Moderate molecular weights– Sharp melting points– Needle like crystals - granular particles– Soft to hard, brittle solids– Limited solubility in crude oils– Soluble in: Distillates Aromatics Carbon Tetrachloride and Carbon Disulfide

Burns with a clean flame

Paraffins

Development Phase



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Asphaltene Deposits on Calcite

Asphaltene Deposits

Aggregate of condensed polycyclic aromatic ring Types of asphaltene deposits

– Hard coal-like deposits– Sludges and rigid film emulsions

Colloidally dispersed in crude oils

Burns with black sooty flame

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RDF (STARDRILL) Filter Cake

Filter cake Formation

Drilling Damage

Filter cake should preventextensive damage toformation during drilling

Low permeability (~ 0.001md)filter cake may be damagingduring production– formation permeability may

be impaired– potential plugging of

screen/ gravel pack Openhole completions do not

have perforations or fracturesto bypass any damage

Filter cake removal maybe anecessity!

Development Phase



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Emulsion

A stable dispersion of two immiscible fluids.

Formed by invasion of filtrates into all zonesor co-mixing of oil-based filtrates withformation brines.

Stabilized by fines and surfactants

Treatment: Mutual Solvents, Clean Sweep

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Water Block

Reduction in relativepermeability to oil due toincreased water saturation inthe near wellbore region.

Favored by pore-lining clayminerals (Illite)

Treatment

– Reduction of interfacialtension usingsurfactants/alcohol's in acidcarrier

1 1

Kro Krw

0

0 1Swc 1-SorSw

Water WetOil Wet

Kro

Krw

Development Phase



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Sandstone Acidizing

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Sandstone Acidizing

Fluid selection – acid type concentration andvolumeWellbore and Completion characteristicsInjection schedule – planned rate schedule andsequence of injected fluids.Acid coverage and diversion (placementtechnique) – special steps taken to improve acidcontact with the formation.

Primary design considerationsPrimary design considerations

Development Phase



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MethodologyMethodology

Identify the damage mechanismDetermine the mineralogyKnow the well parametersKnow the well fluidsSelect the specific systemApply the treatmentFollow the results

Sandstone Acidizing

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Quartz

*Feldspars

*Chert

*Mica

SecondaryCement

(Carbonate Quartz)

Clays(Pore liningi.e., illite)

Clays(Pore filling

i.e., Kaolinite) Remaining Pore Space

*Mud Acid Soluble/Sensitive*Porosity-Filling

Minerals

Sandstone'sSandstone's -- MineralogyMineralogy

Sandstone Acidizing

Development Phase



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Well parametersWell parameters –– Well fluidsWell fluids

Type of well (gas, multiphase)..Bottomhole static temperatureFormation permeability

K 5 mD isrequired

Sandstone Acidizing

It is important to knowthe compatibility betweenthe produced fluids and theacid (emulsion/sludge test).Also the fluids used to drillor complete the well.

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The most common acids are Hydrochloric acid,HCl, and Hydrofluoric Acid, HF.HCl is used to dissolve carbonate minerals.Mud Acid (Hydrofluoric/ Hydrochloric) is usedto attack silicate minerals such as clays andfeldspars.The regular mud acid is 12%HCl –3%HFSome weak organic acid are used in specialapplications such high temperature wells.

Sandstones acidsSandstones acids

Sandstone Acidizing

Development Phase



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Sandstone Acidizing – HF reactions

Due to mineralogical differences, HF chemicalreactions in sandstones acidizing are verycomplex.Carbonate acidizing involves only one reaction:the reaction of acid with carbonate minerals toform calcium salts, water and carbon dioxide .

HF reactionsHF reactions

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Primary reactions dissolves skin damageas assumed.

1st Reac..


Development Phase



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Primary Reaction:

HF + M-Al-Si AlFx + HSiF5 + M+

Silicon FluoridesAluminium Fluorides

This is the reaction that removes damage and improvespermeability


Aluminium Silicates

Metals ions associated withthe clay

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2nd Reac..

Secondary precipitation decreases formationpermeability. Silicon fluorides form when acids are

incompatible with mineralogy.


Development Phase



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Secondary and Tertiary Reactions

Secondary Reaction:

HSiF5 + M-Al-Si + H+ Silica gel + H2O + AlFx +M

This is the reaction of the silicon fluorides with clays and feldspar.The silicon is precipitated in a silica gel.During this reaction a secondary precipitation can occur, decreasing the

treatment efficiency or the treatment to fail.Sodium and potassium present in the formation can form gelatinous

solids which can cause severe plugging problems.

Silicon Fluorides Aluminium Silicates(M: Metals ions associated with

the clay)

Aluminium Fluorides

Metals ionsassociated with the

clay

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Acid continues to react causing aluminium to precipitate.Aluminium-silicate scale clogs wellbore.

Scales in a pipe.

Development Phase



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Tertiary Reaction:AlFx + mineral + AlFy + silica gel


In this reaction the aluminium fluorides react until all remainingacid is consumed

The resulting high aluminium concentration and low acidconcentration can lead to aluminium precipitation within theformation or scaling within the wellbore. This aluminium-silicatescaling can occur days or months following an HF treatment.

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Can cause fines migrationproblems; is ionexchanging. Containspotassium which can causefluosilicate precipitationfrom spent HF.


Sandstone Acidizing - design

Illite

Development Phase



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Is ion exchanging, swells infresh water, and frequentlycontains potassium whichcan cause fluosilicateprecipitation from spent HF.



Mixed-layer clay

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Potassium feldsparFluosilicate precipitation cancreate major problems

ChloriteIs ion exchanging and isunstable in HCl

Development Phase



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Sandstone Acidizing – design

Treatment stagesTreatment stages –– PrePre--flushflush conditions by:conditions by:

Dissolving carbonatesPushing fluids out of the wayPreparing formation through ion exchange

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Treatment stagesTreatment stages –– Main TreatmentMain Treatment

Dissolves skin damage to improve formationpermeability

Development Phase



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Treatment stagesTreatment stages –– Over flushOver flush

Secondary precipitation near wellbore bydriving out fluids

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Treatment stagesTreatment stages –– DisplacementDisplacement

Maximizing by forcing fluids from pipe

Development Phase



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Sandstone Acidizing Fluid Stages

Brine preflush displaces brines containing incompatiblecations away from the wellbore.HCl (or organic acid) preflush removes CaCO3 from matrixto prevent the precipitation of CaF2.

Mud acid removes alumina-silicate formation damage

Overflush displaces spent acid away from the critical matrix.

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Acidizing Additives

Inhibitors Surfactants Foaming Agents Mutual Solvents Anti-sludge Agents Non-Emulsifiers Iron Control Friction Reducers Clay Control Specialty Additives

Development Phase



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Guidelines for Acid Placement

Several placement techniques are availableMechanical methodsBridging agents and divertersselective fluids

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Fluid Placement - Diversion

Successful acid matrix treatments, requirethe acid to be placed so that all potentiallyproductive intervals accept a sufficientquantity of the total acid volume.

To achieve uniform damage removal, theoriginal flow distribution across thetreated interval needs to be altered toprovide generally equal acid distribution.

The methods used to alter this flowdistribution are called diversion methods.

Development Phase



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Fluid Placement - Diversion

Criteria for selection of a diversion techniqueCriteria for selection of a diversion technique

Must provide uniform distribution of treating fluidMust not cause permanent damage to formationA rapid and complete cleanup must be possibleDiversion agent must be compatible with thetreating fluidMust be effective at the applicable treatmenttemperature

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Fluid Placement -

Packers

Ball Sealers

conventionaldensity

ball sealer

buoyantball sealer

Mechanical MethodsMechanical Methods

Development Phase



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Mechanical Placement Techniques

Advantages:

Less sensitive to chemical composition of fluidand temperature.

Disadvantages:

Requires special equipment.

Requires good zonal isolation.

Requires adapted completion (no gravel pack oropen hole).

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Diversion

Bridging agents (solids) External divertersWater SolubleOil solubleViscous plugs Internal diverters

ReactiveVisco-elastic surfactants

Foam

Chemical MethodsChemical Methods

Development Phase



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External Diverting Agents

Advantages– Don’t require rigs or special downhole tools.

Disadvantages– Compatibility between diverter and fluids

SolubilityDispersability

– Careful design required to match rock pore sizedistribution.

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Water Soluble Diverting Agents

Sodium benzoate:

– C6H5COONa + HCl C6H5 COOH +Na+ + Cl- (Benzoic Acid)

It is dissolved by injection water after acting asa diverter and results in easy cleanup.

The benzoic acid is partly soluble in the treatingfluid and can be at used up to 5 Darcy'spermeability. It is designed for treatinginjection wells with up to 150F bottom holeinjection temperature

Development Phase



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Internal Chemical Diverters

Problem– Flow paths that exist or are created behind the

sandface, or behind screens cannot be pluggedwith external diverters.

Solution– Reactive diverting agents (U102)– OilSEEKER– Foam MAT Diversion Service

Benefits– Improves zonal coverage during matrix

stimulation of horizontal and vertical wells– Improves treatment success and production

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OilSEEKER OilSEEKER is based on VES

technology.

– Contains no solids,polymer or nitrogen

– Very easy to mix andpump in the field

Selectively plugs the high-water-saturation zones, causing acid toenter the high-oil-saturationzone.

Compatibility testing must beperformed

VES diverters have thesignificant advantage ofleaving no formationdamage creating residuein the formation.

OilSEEKER

Mw = 450

Development Phase



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OilSEEKER: Features and Benefits

Improve acid placement in high water-cutwells– Vertical– Deviated– Horizontal

Applicable in oil/gas condensate wells– Carbonates– Sandstones

Easy to mix and apply in the fieldDoes not require nitrogen

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Foam Diversion Process: Step 1

Damaged Zone

Thief Zone

Clean the near wellbore area usingbrine

Displace oil or condensate

Development Phase



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Damaged Zone

Thief Zone2 1

Saturate the near wellbore region with foamer Remove damage form the thief zone Saturate the rock with foamer to stabilize the foam

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Damaged Zone

2 1 Thief Zone

Foam injection- Inject HCl or brinecontaining a foaming agent (F101, F78,F52.1, or F75N)– Foam bank is formed in both layers

Development Phase



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Damaged Zone

2 1 Thief Zone

Shut-in period– Foam dissipates rapidly in damaged

zone

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Damaged Zone

2 1 Thief Zone

Inject treating fluid containing foamer– Acid preferentially flows into low perm

layer

Development Phase



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Foaming Agent Selection Guide

For HCI, Mud Acid and Clay Acid treatments

Permeability(md)

100F to 125F38C to 52C

126F to 215F53C to 102C

216F to 250F103C to 121C

251F to 300F122C to 149C

< 10 F75N or F101 F101 F78 F78

10 to 100 F75N or F101 F101 F78 F78

101 to 200 F75N or F101 F101 F78 F78

> 200 F101 F101 F78 F78

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Benefits of Staged Foam Diversion

Effective zone coverage and damage removalDesign is based on specific reservoir

parametersCustomized treatment design is computer

generated and modified on the fly.Non-damaging diverter system is usedVery cost effectiveEasy to apply in the field using standard

products and conventional equipment

Development Phase



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Why Acidizing through Coiled Tubing

Performing the treatment through CT avoids exposing the wellheador completion tubulars to direct contact with corrosive treatmentfluids.

CT movement provides the ability to accurately place small volumesof acid. Spotting the treatment fluid with CT will help to ensurecomplete coverage of the interval.

The CT pressure control equipment configuration allows thetreatment to be performed on a live well. The potential formationdamage associated with well killing operation and the correspondingloss of production time are thereby avoided.

Jetting effect is something that can be effective in smaller cas ingsand provided that a proper purpose built nozzle is used. This cannotbe achieved with conventional techniques.

It is imperative, in many matrix treatments, to perform the wellflow back as soon as possible after the acid job.

Spotting the treatment fluid also avoids the need to bullheadwellbore fluids into the formation ahead of the treatment.

Long intervals can be more effectively treated using techniques andtools that have been developed for use with CT, This is particularlyimportant in horizontal wellbores.

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Dual Inflatable Packer

Coiled Tubing

Connector and releasejoint assembly

Deployment bar

Control section

Upper inflatable packer

Spacer section

Lower inflatable packer

Development Phase



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Downhole Sensor Package (DSP)

Real-time downhole data acquisition system– monitor temperature– pressure– casing collar

Accurate BHP and BHT data for any well profile Evaluate - Treat - Evaluate Optimized diversion

Plasticcoated cableinside CT string

Cable clamp andcheck valve assembly

Mechanicalrelease subassembly

Pressureandtemperature sensors

Treatmentports/nozzle

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Safety Considerations

Flow backUnspent acidMasksPin hole developmentSwivel leaksCommunication devicesGas detectors - H2SLeather gloves/eye wash bottles/eye goggles

Development Phase



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Foam diversion CT Rig Up

Nitrogen /Foamgeneration

package

BOP Kill Port

Pumping teebelow

pressurecontrol

equipment

ProductionTubing

CT Nozzle/tools

Disposal

SamplePoint

Process and Recirculate

ChokeManifold

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Pressure Control Equip. Configuration

BOP kill port - Acid corrosive fluids mustnever be pumped through this portPump-in Tee - Avoid pumpingacid through the swab valveWing Valve - Preferred connectionfor pumping and flowingCasing Valve

Production Tubing

Coiled Tubing

Development Phase



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Carbonate Acidizing

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Wormholes

Matrix Acidizing Fracture Acidizing

Conductiveetch paths

Stimulation of Carbonates

The injection of acids into carbonate reservoirsleads to the formation of highly conductive flowchannels.

Development Phase



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HCl / Carbonate Rocks Rxns

Limestone:– CaCO3 + 2HCl ---> CaCl2 + CO2 + H20

Dolomite:– CaMg(CO3)2 + 4HCl ---> CaCl2 + MgCl2 +2H2O

+ 2CO2

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Alternative Dissolution Patterns

Patterns change depending on:– Temperature– Injection velocity– Surface reaction rate

Increasing Injection Rate

Direction offlow

Development Phase



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Acid

spentacid

Wormhole Pattern from Radial Flow

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Acid Systems

HCl - Primary acid forcarbonates

Organic acids -Formic/Acetic– Less dissolution

capacity– Higher temperatures

Blended acids:– HCl / organic blends– Less expensive than

organic acids

Emulsified acids (SXE)– Retarded kinetics

Non-acid solvents– Low corrosion– Retarded kinetics

Development Phase



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Fracture Acidizing

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Fracture Acidizing

The injected acid non uniformly etches the fracturefaces, resulting in the formation of highly conductiveetched channels that remain open after the fracturecloses.

The success of thetreatment depends ontwo characteristics of theetched fracture:– effective fracture length– effective fracture conductivity Wormholes

Conductiveetched

channels

Development Phase



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Factors Influencing the Success of Fracture AcidizingTreatments:

Effective fracture length– Rate of acid consumption– Acid fluid loss (wormhole formation)– Acid convection along the fracture

Effective fracture conductivity– Etched pattern– Volume of rock dissolved– Roughness of etched surface– Rock strength– Closure stress

Fracture Acidizing

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Fluid-Loss Problems

Carbonates are usually Fissured Acid Destroys most Fluid Loss Additives Fracture Faces are Constantly ErodedWormhole Formation Natural Fractures Enlarged Increased Leakoff Surface Fracture-Pressure Maintenance

Development Phase



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Carbonate Acidizing

Chemistry and Physics

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Carbonate vs. Sandstone

CARBONATE– A large fraction of the

matrix is soluble(>50%)

– Dissolution of rock(wormholes)damage bypassing

– Diversion

SANDSTONE– A small fraction of the

matrix is soluble

– Dissolution of thedamaging mineral

– Precipitations

penetration +coverage

dissolution +precipitations

Development Phase



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Stoichiometry

2HCl + CaCO3 ---> CaCl2 + H2O + CO2

MgCa(CO3)2 + 4HCl ---> CaCl2 + MgCl2 + 2H2O + 2CO2

Stoichiometry refers to the proportions of the variousreactants participating in a chemical reaction. Knowing theseproportions allows one to calculate the amount of acidrequired to dissolve a given quantity of carbonate rock.

Allows determination of acid required

Allows determination of increase

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Key Factors in Carbonate Acidizing

1. Penetration

2. Acid reactivity

3. Injection rates

4. Diversion

Development Phase



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Penetration

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Pore Level Model

One can explain the range of dissolution channels by studying thecompetition between acid reaction and acid transport.

Acid Convection

Acid Surface Reaction

Mass Transferto Surface

Simple representation of a pore or wormhole.

Mass Transferto Bulk of acid

Development Phase



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Damköhler Number, Da *

The three parameters can be combined intoone dimensionless group:

Net Rate of Mineral Dissolution by Acid

Rate of Acid ConvectionDa =

Da =DL

Q

*Fredd and Fogler, AIChE J., 1998.

k is the overall dissolution rate constantD is the wormhole diameterL is the wormhole lengthQ is the flow rate in the wormhole

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Wormhole Collision: pore-level stimulation

H+

H+carbonate

Acid invades porous matrix where it reacts withthe pore walls.

Development Phase



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Acid attack reduces pore wall thickness

Wormhole Collision

H+

carbonate

Ever widening pore channels cancollide

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Effect of Da on Stimulation Efficiency*

1

10

100

1000

0.1 1.0 10 100 1000

Pore Volumesto Breakthrough

(Inverse of AcidEfficiency)

1 / Damköhler Number

The graph shown here depicts the relationship between the acid efficiency (indicated by porevolumes of acid required to breakthrough) and the Damköhler number. The x-axis is thereciprocal of the Damköhler number, which is proportional to the flow rate. In fact, all otherthings being constant, 1/Da is Q. The y -axis shows pore volumes to breakthrough, I.e., volumeof acid required to propagate a wormhole that extends from the inlet to the exit of the core.The shape of the curve is universal for all fluid/mineral system s. The implication is that onewants to operate an acidizing treatment to the right of the minimum (optimum).

Development Phase



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Basic Reaction:– Fe + 2HCl Fe++ + H2 + 2Cl-

At Anode: Fe Fe++ + 2e-

Oxidation At Cathode: 2H+ + 2e- H2 Reduction

Cl - H 2

+H+H

+H +H+H

+H Fe++Cl -

Cl - Cl - Cl -

Cl -

e- e-e- e-

CATHODE ANODE

Attack of Hydrochloric Acid on Iron

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+H Fe++

e-

+H

Barrier at cathodic surface (-).

A corrosion inhibitor (Organic N2,Arsenic)forms a barrier at acathodic surface or anodic surface whichinterferes with electrochemical reactions.

Barrier at anodic surface (-)At Anodic sites, electrons fromanionic inhibitor moleculesattach themselves and form afilm at the anodic sites.At Cathodic sites, electrons fromcationic inhibitor moleculesattach themselves and form afilm at the cathodic sites.

H+ H+Fe++

e - e-

Mechanisms of Inhibition

Development Phase



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Inhibitor Effectiveness

Concentration of InhibitorTemperatureMetal TypeConcentration & Type of AcidConcentration & Type of AdditivesPressureFlow VelocityVolume/Area Ratio

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Definition

Surfactants, or surface active agents, are used inacidizing to break undesirable emulsions, reduce surfaceand /or interfacial tension, alter wettability, speedcleanup, disperse additives, and prevent sludgeformation.

Chemical containing both oil and water soluble groups

M+

X-

(pH)

-

+

+-

Hydrophilic Hydrophobic (Lipophillic)

Anionic

Cationic

Non-Ionic

Amphoteric

Development Phase



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Some Surfactants

F100 AmphotericF103 Non ionicF104 AnionicW060 BlendW62 Blend

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Reasons for Using Surfactants

Control wettability Prevent/break water blocks Disperse/suspend fines Reduce capillary force Sludge prevention Asphaltene treatment Prevent/break emulsions

– Reduce surface or interfacial tension Enhance emulsions

Development Phase



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water wet oil wet

Water and Oil Wet Rock

ionic for sandstone; cationic for carbonate

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Foaming Agents

Diversion, cleanupDo not mix with hydrocarbons, mutual solvents,

alcohols

F100

– Used with Nitrogen

F52

– Used with Carbon Dioxide or Nitrogen

Non-ionic not for T > 250 oF

Development Phase



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Dispersed and stable Flocculated, precipitated

Fe

Fe

Ca+

+++

+ +

+• pH

• Multivalentcations

• Poorsolvents

Sludge and Asphaltenes

•Asphaltenes are the heaviest, most polar component of crude oil. Theyare naturally dispersed by resins (maltenes).

•Poor solvents, Hydrogen ions, and multivalent metal ions (particularlyFe[III]) will cause flocculation and precipitation. HCl with Ferric iron(Fe[III]) will generally precipitate asphaltenes if present in the crude oil.

•The resulting asphaltene sludge is very difficult to remove even withstrong aromatic solvents.•The asphaltene sludge contains many other materials (such as paraffin ,or Iron Sulfide, fines, etc.)

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Factors Affecting Sludge

Crude typeAcid typeFerric ironBHSTAntisludge agents:

– W60 (MISCA)– W59– B53– B60

Development Phase



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Flow Back

Acid-Oil Mixing

Need for preflushes

Mixing of acid and the formation fluids will occur unless a large pad is injectedbefore the acid.

The mixing of live acid and oil during injection, and the mixing of spent acidand oil during flow back (depicted above) can lead to the following problems:1) Formation of stable emulsions2) Change the formation wettability to oil wet (due to sludge precipitation)3) Creation of Asphaltene sludge

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Anti-Sludge Strategy

Minimize Fe concentration Remove scales and rust

from equipment andtubular surfaces

Reduce dissolution rate ofFe ions from surfaces incontact with acid

Reduce ferric ions toferrous ions

Enhance oil/acid break-out

vendor’s qualitycontrol

tubing picklelined equipment

corrosion inhibitor

iron reducer

oil samplesurfactant

Development Phase



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Surfactants to Control Acid Sludge

Use highly dispersible chemicals.

L58, L63, A179, U42Control iron

B53, W53, W54, W59Demulsifiers

B53, B60, W60, W58Dispersants to stabilizeAsphaltene fraction

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Emulsions

Treating fluid + crude oil + emulsifying agent= emulsion

Emulsion = reduced production

Emulsion-stabilizer agents include:– Asphaltenes– Formation fines

Development Phase



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Types of Emulsion

Inverse or oil-outsideemulsions– oil is the continuous phase

with the water dropletsdispersed

Direct or water-outsideemulsions

-water-external emulsionhas an aqueous externalphase with oil dropletsdistributed throughout

external phase

internal phase

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Emulsion Blocking

Crudes contain naturally occurring surfactants thatreduce the surface tension between oil and formationwater, and thus promote the development of emulsions

A critical pressure drop must be imposed across porethroats to mobilize interfacial films that stabilize foamsand emulsions.

Development Phase



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Prevent/Break Emulsions

Clean Sweep I

Clean Sweep II

Paran Eco

U066U98U100

K46, F3Clean Sweep III

Oil-outside PhaseWater-outsidePhase

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Mutual Solvent

– Mutual Solvents are multifunctional, non ionicagents soluble in oil, water, acid and brines.

– They contain strong ether and alcohol groups,which provide a wide range of solvent properties.

–– The functions of Mutual Solvents are:

1. Wetting Agents2. Non Emulsifiers3. Surface/Interfacial Tension Reducer

Commonly used mutual solvents Ethylene glycol monobutyl ether (EGMBE) Ether/surfactant/alcohol blends

Development Phase



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Sour Wells-Fe Control

– Fe (OH)3 pH > 2 (pH > 6 in presenceof F -)

– Fe (OH)2 pH > 7

– Fe3+ + H2S Sulfur + Fe2+

– Fe2+ + H2S FeS pH > 2

Need to control Fe2+ too

When appreciable quantities of iron in the form of Fe3+ (ferric ions), ratherthan the usual Fe2+ (ferrous ions), are dissolved by the acid, ironprecipitation and permeability reductions can occur after acidizing

The presence of H2S changes the iron precipitation problem. Sulfurprecipitates in this reaction. At the same time, if the iron is reduced from +3to +2, at a pH of about 2, Ferrous Sulfide, which is an insoluble precipitatewill form

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Iron Control Practices

Remove iron in tubing prior to stimulationtreatment (Pickle or use protected work-string)

The acid must not contain high levels of Fe3+ -Avoid contamination (Clean/lined equipment)

Combinations of reducing agents and chelatingagents provide cost-effective solutions (L63,U42)

Utilize effective corrosion inhibitors (A260)

Development Phase



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Clay Control

Clays: below 4m– illite, smectite, chlorite, zeolite, kaolinite

Silts: 4 – 64 m– feldspar, mica, chert

Sands: over 64 m

clays cause 2 major problems:– 1. Swelling– 2. Migration

KCl is temporary clay control agentL55 is a permanent clay stabilizer that work by

adsorbing on the clay surface

fines

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Friction Reducers Used during matrix acidizing through CT Suppress turbulence of the fluid

Action of friction reducers(at a given flow rate)

•Natural polymers like guar gum, gum karaya and cellulose derivat ives, aswell as synthetic polyacrylamides, have long been used as friction reducers.

•Each of these polymers can have different properties, depending onmolecular weight, chemical composition, cross linking, branching, etc.

•Some polyacrylamides (i.e., Friction-Reducing Agent J120) are excellentfriction reducers for acid and can greatly reduce the friction pressure drop intubulars

Development Phase



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Thank You

Date post:	30-Aug-2014
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Sonatrach's Stimulation

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