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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
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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.
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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
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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
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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
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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.
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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.
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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
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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.
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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
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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
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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
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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
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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.
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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.
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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.
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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
Hydraulic Fracturing Objectives
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Production increaseProduction increase
Hydraulic Fracturing Objectives
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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Hydraulic Fracturing Objectives
Production increase calculations assumptionsProduction increase calculations assumptions
Steady state productionSame drawdown for each production rateSingle phase flowNo skin damage for production before fracture
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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
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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
Hydraulic Fracturing Objectives
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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
Hydraulic Fracturing Objectives
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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
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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
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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
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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
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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
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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
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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
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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
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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)
Can be used in brines.
1-2 % residue.
Good crosslink control.
Excellent thermal stability.
40 lb/Mgal 28 cp
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Fracturing Fluids - Hydroxyethyl Cellulose (HEC)
Can be used in brines.
Residue Free.Not Crosslinkable.
Limited Thermal Stability.
40 lb/Mgal 46 cP
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Bio-polymer and behaves like a power fluid
Can be used in brines.
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)
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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
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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
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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
Fracturing Fluids – Gel breakers
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SeSelection of Breakerlection of Breaker
Fracturing Fluids – Gel breakers
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
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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
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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
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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
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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.
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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
Proppant selection – Fracture Conductivity
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Closure stressClosure stress
The stress applied to the proppant bed when thefracture has closed.
Proppant selection – Fracture Conductivity
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.
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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.
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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
Proppant selection – Fracture Conductivity
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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
Proppant selection – Fracture Conductivity
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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
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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
Proppant selection – Fracture Conductivity
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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
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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
Evolution of Proppant DistributionDuring Pumping
Evolution of Proppant DistributionEvolution of Proppant DistributionDuring PumpingDuring Pumping
Design
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Evolution of Proppant DistributionDuring Pumping
Evolution of Proppant DistributionEvolution of Proppant DistributionDuring PumpingDuring Pumping
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
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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
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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
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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
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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
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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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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
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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.
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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
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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
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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.
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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
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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!
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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
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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
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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
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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
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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..
Sandstone Acidizing – HF reactions
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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
Sandstone Acidizing – HF reactions
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.
Sandstone Acidizing – HF reactions
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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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Sandstone Acidizing – HF reactions
Acid continues to react causing aluminium to precipitate.Aluminium-silicate scale clogs wellbore.
Scales in a pipe.
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Tertiary Reaction:AlFx + mineral + AlFy + silica gel
Sandstone Acidizing – HF reactions
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'sSandstone's -- MineralogyMineralogy
Sandstone Acidizing - design
Illite
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Is ion exchanging, swells infresh water, and frequentlycontains potassium whichcan cause fluosilicateprecipitation from spent HF.
Sandstone'sSandstone's -- MineralogyMineralogy
Sandstone Acidizing - design
Mixed-layer clay
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Sandstone'sSandstone's -- MineralogyMineralogy
Sandstone Acidizing - design
Potassium feldsparFluosilicate precipitation cancreate major problems
ChloriteIs ion exchanging and isunstable in HCl
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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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Sandstone Acidizing – design
Treatment stagesTreatment stages –– Main TreatmentMain Treatment
Dissolves skin damage to improve formationpermeability
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Sandstone Acidizing – design
Treatment stagesTreatment stages –– Over flushOver flush
Secondary precipitation near wellbore bydriving out fluids
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Sandstone Acidizing – design
Treatment stagesTreatment stages –– DisplacementDisplacement
Maximizing by forcing fluids from pipe
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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.
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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
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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
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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
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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
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Foam Diversion Process: Step 2
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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Foam Diversion Process: Step 3
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
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Foam Diversion Process: Step 4
Damaged Zone
2 1 Thief Zone
Shut-in period– Foam dissipates rapidly in damaged
zone
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Foam Diversion Process: Step 5
Damaged Zone
2 1 Thief Zone
Inject treating fluid containing foamer– Acid preferentially flows into low perm
layer
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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
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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
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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.
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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
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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
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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
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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
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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
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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
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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
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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.
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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).
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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
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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
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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
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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
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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
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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
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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
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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.
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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
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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)
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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