Introduction to Reservoir Stimulation Kellyville Training Center
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Well Stimulation Stimulation is a chemical or mechanical method of increasing flow capacity to a well. • Dowell Schlumberger is mainly concerned with three methods of stimulation: • 1. Wellbore Clean-up : “ Fluids not injected into formation” • a. Chemical Treatment • b. Perf Wash • 2. Matrix Treatment : “ Injection below frac pressure” • a. Matrix Acidizing • b. Chemical Treatment • 3. Fracturing “ Injection above frac pressure” • a. Acid Frac • b. Propped Frac
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Stimulation Techniques • Restores Flow Capacity: • Wellbore Clean-up • Matrix Treatment These procedures are performed below fracture pressure. • Create New Flow Capacity: • Hydraulic Fracturing (Acid and Sand) These procedures are performed above fracture pressure.
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Areas Where Reduction in Flow Capacity May Occur • 1. Wellbore: • Scale Damage • Sand Fill • Plugged Perforations • Paraffin Plugging • Asphalt Deposits • Etc. • 2. Critical Matrix: • Drilling Mud Damage • Cement Damage • Completion Fluids • Production • Native Clays/Fines
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WELLBORE • Primary Purpose : Restore flow capacity by removing restrictive damage to fluid flow in the wellbore. • Methods : • Mechanical • Chemical Treatment • Acidizing Treatment
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Critical Matrix • What is It? • The area of formation that is 3' to 5' from the wellbore. • Why is it critical? r (Drainage Radius) (Pe)
(Pwf)
2,000 ft 1,000 ft 100 ft 50 ft 20 ft 10 ft 5 ft 3 ft 2 ft 1 ft 0 ft
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P (psi)
∆ P/ft
5,000 4,934 4,719 4,654 4,568 4,503 4,439 4,391 4,000 3,150 2,000
0.07 psi/ft 1.3 psi/ft 6.5 psi/ft 850 psi/ft 1,150 psi/f
% Pressure Drop (Pe - P) (Pe - Pwf) * 100
0 2.5 10.8 13.3 16.6 19.0 21.5 23.3 24.8 27.3 100
Major Goals of Matrix Treatment • 1. Restore Natural Permeability • By Treating the Critical Matrix • 2. Minor Stimulation • 3. Leave Zone Barrier Intact
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Matrix Acidizing • 1. Sandstone: • Major Effects: Dissolves/Disperses Damage Restores Permeability • Minor Effects: Minor Stimulation ■
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• 2. Limestone: • Major Effects: Enlarge Flow Channels/Fractures Disperse Damage by Dissolving Surrounding Rock Creation of Highly Conductive Wormholes ■
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■
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Applications For Matrix Treatment • High Permeability Formation with Damage. • Unproppable Formations. • Treating Limitations. • Thick Zones. • To Supplement Fracturing.
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Low Permeability Reservoir • Increase well productivity by creating a highly conductive path compared to the reservoir permeability. Damage
XL = Fracture half length
XL
• The fracture will extend through the damaged near wellbore area. • The fracture size is limited to two criteria : • Drainage Radius • Cost • Fracturing is : Pumping fluid into the formation above fracture pressure.
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Darcy’s Equation Oil Well :
Gas Well :
kh (P e - P wf) q= e + S) 141.2 β µ (In rrw
kh (Pe 2 - P wf2 ) q= e 1424 µzT (In rrw + S)
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Skin (s) • The total Skin (ST) is the combination of mechanical and pseudo-skins. It is the total skin value that is obtained directly from a well-test analysis. • Mechanical Skin: • Mathematically defined as an infinitely thin zone that creates a steadystate pressure drop at the sand face. • S>0 Damaged Formation • S=0 Neither damaged nor stimulated • S<0 Stimulated formation • Pseudo Skin: • Includes situations such as fractures, partial penetration, turbulence, and fissures. • The Mechanical Skin is the only type that can be removed by stimulation.
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Skin Example • Pseudo Skin: • Producing at high rates --> turbulence • Collapsed tubing, perforations • Partial penetration / Partial perforation • Low Perforation Density (Shots/ft) • Etc. • Formation Damage: • Scales • Organic/Mixed Deposits • Silts & Clays • Emulsions • Water Block • Wettability Change
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Example • An oil well produces 57 B/D under the following reservoir and producing conditions: k = 10 md h = 50 ft ßo = 1.23 res bbl/stb µo = 0.6 cp Pr = 2,000 psi Pwf =
500 psi
rw = .33 ft re = 1,320 ft • What is the Skin Factor? • Is there potential for Stimulation?
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INTRODUCTION TO MATRIX TREATMENT
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Formation Damage
• Damage Definition : • Partial or complete plugging of the near wellbore area
which reduces the original permeability of the formation.
• Damage is quantified by the skin factor ( S ).
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Types of Formation Damage • Emulsions • Wettability Change • Water Block • Scale Formation • Organic Deposits • Mixed Deposits • Silt & Clay • Bacterial Slime
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Areas of Damage
Tubing
Gravel Pack
Scales Organic deposits Silicates, Aluminosilicates Emulsion Water block Wettability change
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Perforations
Formation
Emulsions • Definition: • Formed by invasion of filtrates into oil zones or mixing of oil-based filtrates with formation brines. • Any two immiscible fluids • Keys to Diagnosis: • Sharp decline in production • Water breakthrough • Production of solids • Fluid samples • Injection of inhibitors • Treatment: • Surfactants • Mutual solvents
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Wettability Change • Definition: • Oil wetting of rock from hydrocarbon deposits or adsorption of an oleophilic (attracts oil) surfactant from treating fluid. • Keys to Diagnosis: (Normally difficult to diagnose) • Rapid production decline • Casing leak • Water breakthrough • Water coning • Decrease or disappearance of gas • Treatment: • Mutual solvent followed by water-wetting surfactant.
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Water Block • Definition: • Caused by an increase in water saturation near the wellbore which decreases the relative permeability to hydrocarbons. • Keys to Diagnosis: • Rapid oil or gas production decline • Casing leak • Water breakthrough • Water out • Abnormally high water cut through lower perforations • Treatment: • Mutual solvents or surfactants
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Scale Formation • Definition: • Scales are precipitated mineral deposits. Scale deposition occurs during production because of lower temperatures and pressures encountered in or near the wellbore. • Keys to Diagnosis: • Sharp drop in production • Visible scale on rods/tubing • Water breakthrough • Treatment: • Carbonate (Most Common) HCl, Aqueous Acetic • Sulfate ■ Iron EDTA » HCl with various iron control agents NARS ■ Silica • Chloride » Mud Acid 1 - 3% HCl ■
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Keys to Diagnosis of a Sample Floats in H2O
Yes
Organic
2
No Yes
Soluble in H 2O
NaCl (probably)
No Odor of rotten eggs
Yes Soluble in HCl
Yes
No FeS (possible)
CO 2 Evolves
No
FeCO 3 Fe 2 (CO 3 ) 3 CaCO 3 MgCO 3 Ca(SO 4 ) 2 slowly soluble (also soluble in U42)
Soluble in hot HCl Yes
No
Iron Oxide
Yes
Soluble in hot HCl/HF
Silica Base (sand/clay)
No Magnetic Yes Magnetite FeCo 3
Yes SrSO 4 (slow) BaSO 4 (very slow)
Soluble in U42
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Scales : Inorganic Mineral Deposits Types of Scale
Usual Occurrence
Treating Fluids
Carbonates
CaCO3
HCl
Very Common
CaSO4•2H 2 O (gypsum)
EDTA
Common
BaSO 4 /SrSO4
EDTA
Rare
NaCl
H 2 O/HCl
Gas Wells
Fe S
HCl + EDTA
Fe 2 O 3
HCl + Sequestering Agent
CO2 /H 2 S Possible Produced
Sulfates
Chlorides
Iron
Silica
SiO 2
HF
Hydroxides
Mg/Ca(OH) 2
HCl
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Comments
Very Fine
Organic Deposits • Definition: • Organic deposits are precipitated heavy hydrocarbons (parrafins or asphaltenes). They are typically located in the tubing, perforations and/or the formation. • The formation of these deposits are usually associated with a change in temperature or pressure in or near the wellbore during production. • Keys to Diagnosis: • Sharp decline in production • Visual parrafin on rods and pump • Operator is "hot oiling" • Treatment: • Aromatic Solvents (Xylene, Toluene) • Mutual Solvents
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Keys to Diagnosis of Actual Organic Deposit Floats in water
Yes
Organic Deposit
1. Burns evenly with clean flame
Yes
Paraffin/wax
No Black sooty flame 2. Soluble in pentane
Yes
Asphaltene
Yes
Paraffin
No Asphaltene 3. Soluble in Toluene/Xylene
Yes
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Paraffin/ Asphaltene
Silts & Clays • Definition: • Damage from silts and clays includes the invasion of the reservoir permeability by drilling mud and the swelling and/or migration of reservoir fines. • Keys to Diagnosis: • Sharp drop in production • Lost circulation during drilling • Production tests • ARC tests • Treatment: • HCl: Carbonate Reservoirs • HF Systems: Sandstone • Quaternary Amine Polymers (L55) • Cationic Surfactant (M38B) • Fusion (Clay Acid)
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Bacterial Slime • Definition: • Anaerobic bacteria grows downhole without oxygen up to 150°F. Bacteria may chemically reduce sulfate in a reservoir to H2S. • Treatment: • M91 (Bleach+Caustic soda)
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Sources of Formation Damage • Drilling • Cementing • Perforating • Completion and Workover • Gravel Packing • Production • Stimulation • Injection Operations
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Successful Matrix Treatment • REQUIREMENTS : • Enough Treating Fluid Volume • Correct Reactive Chemicals • Low Injection Pressure • Total Zone Coverage
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INTRODUCTION TO FRACTURING
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Applications For Hydraulic Fracturing • If wells natural permeability is low ( Ke < 10 md ) • Natural production is below economic potential • Skin By-Pass “ HyperSTIM “ or higher permeability and soft formations. The injected fluid is pumped at a rate above the fracture pressure of the reservoir to create cracks or fractures within the rock itself.
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Hydraulic Fracturing Treatment • Primary Purpose : • To increase the effective wellbore area by creating a fracture of length XL whose conductivity is greater than that of the formation. Dimensionless Conductivity ( Fcd ) = Kf Wf / Ke Xf • Two Methods : • Sand Frac • Acid Frac
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Propped Frac & Acid Frac open fracture during job
fracture tends to close once the pressure has been released
1/2"
sand used to prop the frac open
acid etched frac walls
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Propped Fracture Optimization • Optimize the reservoir deliverability by balancing fracture characteristics and reservoir properties • Analyze the effect of production systems : • Perform => Nodal Analysis • Determine the pumping parameters : • DataFRAC • Tailor the fracturing fluid and proppant to the reservoir • Determine treatment size (Fluid & proppant amount) Calculate XLand FCD • • Calculate the benefit of the treatment => $ • FracNPV
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Acid Fracture
• Bottom hole pressure above fracturing pressure • Acid reacts with the formation • Fracture is etched • Formation must retain integrity without fracture collapse
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Hydraulic Fracturing Accomplishes: Creates Deep Penetrating Fractures to : • • • • •
Improve productivity Interconnect formation permeability Improve ultimate recovery Aid in secondary recovery Increase ease of injectivity • A hydraulic Fracture has to be cost effective to the
customer.
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Fracture Penetration is influenced by: • FORMATION CHARACTERISTICS : • Type • Hardness • Permeability • Zone Height “ Presence of Barriers “ • Drainage Radius • FRAC FLUID CHARACTERISTICS : • Base Fluid • Viscosity • Volume • Pump Rate • Fluid Loss
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Orientation Of The Fracture • The fracture will extend perpendicular to the axis of the least stress. Overburden Pressure • X - Y - Z Coordinate : Favored Fracture Direction
Least Principal Stress (i.e. Vertical Fracture)
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Vertical Or Horizontal Fracture
Vertical fracture plane is perpendicular to earth’s surface due to overburden stress being too great to overcome
Horizontal fracture with a pancake like geometry. Usually associated with shallow wells of less than 3,000 ft. depth
• Rule-Of-thumb : • Frac Gradient < 0.8 psi / ft --------> Vertical Fracture • Frac Gradient > 1.0 psi / ft --------> Horizontal Fracture
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Fracture Propagation Models • KGD • XL < h
• PKN • XL > h
• Radial • XL = h/2
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Rock Mechanical Behavior • Young’s Modulus : • E=δ / ε
• Poisson’s Ratio : ∀ υ = ε 2 /ε 1 ε 1 = L1 - L2 / L1 ε 2 = d1 - d2 / d1 D1
D2
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Rock Mechanical Behavior • Young’s Modulus : • E=δ / ε
• Poisson’s Ratio : ∀ υ = ε 2 /ε 1 ε 1 = L1 - L2 / L1 ε 2 = d1 - d2 / d1
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Fracture Width • W = ( µ Q L) E
1/4
• W = (µ QL2)1/4 EH
KGD
−µ
PKN
= Viscosity of fluid
• Q = Injection Rate • H = Gross Height • L = Xf • E = Young’s Modulus
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Net Present Value
FracNPV
• BENEFITS : • Design lowest cost job • Realize full production rate potential • Forecast post treatment decline • Study impact of treatment variables • APPLICATION : • Select optimum XL, W & proppant type • Aid in determining whether or not to fracture a new well • Determine size of production equipment • Evaluation of the fracture treatment based on well performance
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FracNPV
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Design Execution Evaluation DEE
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Design
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Design 1400
1200
1000
Pressure, psig
800
600
A 400
1 200
0
2 0
In flow @ S andface (1 ) In flow (1 ) C a se 2 (2) C a se 3 (3) N o t U sed N o t U sed N o t U sed N o t U sed
1 100 N ot U sed O utflow (A) C ase 2 (B ) C ase 3 (C ) N ot U sed N ot U sed N ot U sed
2 00
3
300
400
50 0
L iq u id R a te, B b l/D In flo w R e s e rvo ir S kin
R eg: S chlu m berge r - C o m panies
Identify The Potential 51
600
In flo w (1 ) 0 .0 0 0 (2 ) 1 0 .0 0 0 (3 ) -2 .0 0 0
700
Design FracCADE*
W ell XXXX 1235.5//1249.5 08-26-1997
Ne t Pres e nt Va lue 6 00 000
N e t P re s e n t Va lu e - $ (U S )
5 00 000
4 00 000
3 00 000
2 00 000
Fluid Type
1 00 000
YF120LG 0
-10 0 00 0
ClearFRAC (3 0
10 0
20 0
3 00
H yd ra ulic H a lf-L e ng th - ft Production tim e 1 year
*Mark o f Sch lu mb erger
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4 00
50 0
Design FracCADE*
W ell XXXX Logs 08-26-1997
ACL Fra cture Profile and Proppa nt Conce ntra tion 1220
W ell D ept h - m
1230
1240
1250
< 0.0 lb/ft2 0.0 - 0.2 lb/ft2 0.2 - 0.4 lb/ft2 0.4 - 0.6 lb/ft2 0.6 - 0.8 lb/ft2
1260
0.8 - 0.9 lb/ft2 0.9 - 1.1 lb/ft2 1.1 - 1.3 lb/ft2 1.3 - 1.5 lb/ft2 > 1.5 lb/ft2
1270 0
2500 Stres s - psi
5000
-0.3
-0.1
-0.0
0.1
0.2
0.3
0
AC L W idth at W ellbore - in
10
20
30
40
50
60
F rac ture H alf-Length - m
*Mark of Sch lu mb er g er
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70
80
90
100
DataFRAC* Service Closure Test
Calibration Test
Fracture extension pressure
Net pressure ISIP
Closure
Closure pressure
BHP
Rebound pressure
Increasing rate
Constant Constant rate flowback
Constant rate
Shut-in
Time
*Mark of Schlumberger
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Falloff
Execution
PE22
4000
25
20 3000
Pressure ( PSI )
2500
15
2000 10
1500
Treating_Pressure BHP-CADE Slurry_Rate Proppant_Conc
1000
500
0 22:26
22:33
22:40
22:48 Time
55
22:55
23:02
5
0 23:09
Rate ( BPM ) - Proppant Concentration ( PPA)
3500
Evaluation
FracCADE*
Well XXXX Logs 08-26-1997
ACL Fracture Profile and Proppant Concentration 1220
• Realdata fracture simulation, to adjust leak off and Young Modulus.
W ell D ept h - m
1230
1240
1250
< 0.0 lb/ft2 0.0 - 0.2 lb/ft2 0.2 - 0.4 lb/ft2 0.4 - 0.6 lb/ft2 0.6 - 0.8 lb/ft2
1260
0.8 - 0.9 lb/ft2 0.9 - 1.1 lb/ft2 1.1 - 1.3 lb/ft2 1.3 - 1.5 lb/ft2 > 1.5 lb/ft2
1270 0
2500
5000
-0.3
Stress - psi
-0.0
0.1
0.2
0.3
0
10
20
30
ACL Width at Wellbore - in
40
50
60
70
80
90
100
Fracture Half-Length - m
FracCADE*
PE22 1235.5//1249.5 mts Real Job 08-26-1997
ACL Fracture Profile and Proppant Concentration *Mark of Schlumberger 1220
1230
W ell D ept h - m
• It can be performed in Real Time.
-0.1
1240
1250
< 0.0 lb/ft2 0.0 - 0.2 lb/ft2 0.2 - 0.3 lb/ft2 0.3 - 0.5 lb/ft2 0.5 - 0.7 lb/ft2
1260
0.7 - 0.9 lb/ft2 0.9 - 1.0 lb/ft2 1.0 - 1.2 lb/ft2 1.2 - 1.4 lb/ft2 > 1.4 lb/ft2
1270 0
2500 Stress - psi
*Mark of Schlumberger
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5000
-0.3
-0.1
-0.0
0.1
0.2
ACL Width at Wellbore - in
0.3
0
10
20
30
40
50
60
Fracture Half-Length - m
70
80
90
100
Evaluation PE22 Production 700
Pe22 Forecast PE22 Bbl/d
600
BOPD
500
400
300
200
100
0 0
Forecast vs Actual Production
50
100
150
Days
57
200
250
Conclusion • Three Types of Stimulation : • Wellbore Clean-up • Matrix Treatment • Hydraulic Fracturing • Well Candidate Selection : • What is it ? • How does Dowell Schlumberger use it ? • What are some of the tools associated with it ? • NPV • What is it ? • How can it be used to design a treatment ? • How does the output benefit our customers and us ?
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