Transcript TBD AMERICA, INC. by Barry Stevens, PhD.

An Unconventional Bonanza
Enhanced Oil & Gas Recovery
Dr. Barry Stevens
President
TBD America, Inc. a Technology Business Development Consulting Group
Agenda
1. What is EOR
2. Hydrofracturing Process
3. Hydrofracturing Video
4. Casing and Cementing
5. Well Bore Integrity
6. Hydrofracturing Fluid
7. Model Simulation
8. Shale Gas Extraction
9. Fracture Conductivity
10. Slickwater Fracturing Design
11. Fluid Behavior
12. Design Parameters
13. Guidelines for Limited Entry
Treatment
14. Determine Surface Pressure
15. Determine Orifice Flow
16. L.E. Procedure
17. Closing Remarks
Resource Triangle
Formation Candidates
• Sufficient Recoverable Reserves
• Sufficient Reservoir Pressure
• Low Permeability (less than 10 mD)
• Oil-Water & Oil Gas contacts Not Close
• Good Cementation
Criteria for Well Selection
•
•
•
•
•
•
•
•
•
State of depletion of producing formation
Formation composition & consolidation
Formation permeability
Formation thickness
Isolation of the zone to be treated
Condition of well equipment
Production history of the well
Offset production history\
Location of water, O/W and G/O contacts
Hydrofracturing
Hydrofracturing (hydraulic fracturing, fracking) consists of pumping
into the formation very large volumes of fresh water that generally has
been treated with a friction reducer, biocides, scale inhibitor, and
surfactants, and contains sand as the propping agent.
The water treating fluid maximizes the horizontal length of the
fracture while minimizing the vertical fracture height.
The fractures, which are held open by the sand, result in increased
surface area, which further results in increases in the desorption of the
gas from the shale and increases in the mobility of the gas.
The result is more efficient recovery of a larger volume of the gas-inplace.
Fracturing Classifications
• Acid Fracturing
• Non Acid Fluid Fracturing
 Water Based (Slickwater - light sand frac)
 HC Based
 Poly Emulsion
• Non Conventional
 Nuclear
 Explosive
 HEGS (high energy gas stimulation)
Hydrofracturing Flow
Casing and Cementation
Prevent Contamination of Fresh Water Zones
Prevent Unstable Upper Formations from Caving-In
Provides a Strong Upper Foundation to Drill Deeper
Isolates Zones with Different Pressures / Fluids
Seals off High Pressure Zones from the Surface
Prevents Fluid Loss into Production Zones
Provides a Smooth Internal Bore for Equipment
Wellbore Integrity
BAD CEMENT
TO DO’s
 Meeting casing quality and connection
requirements as outlined in API Spec. 5CT.
 During cementing, using the best available mud
displacement method to avoid mud channels.
 Using both top and bottom cementing plugs.
 Providing thin and low permeable filter cake
from the drilling fluid.
 Reducing cement slurry filtration to avoid
“bridging” during cement setting.
 Reducing slurry chemical shrinkage to a
minimum and improving the bonding.
 Using right angle setting slurries reduces the
amount of time in which gas can migrate within
the unset cement.
 Using lightweight cements avoids cement losses in the
WELLBORE
case of weak (surface) formation.
INTEGRITY
 Using inflatable annular casing packers to enhance a
standard cement job by providing specific points of
isolation.
 For surface casing applications, cement should always
come to the surface, without exclusion.
 Pressure testing the integrity of formation strength
below a casing shoe to ensure adequate sealing is
mandatory.
Hydrofracturing Fluid
Model Simulations
• Allows engineers to evaluate
fracture stimulation design in
controlled environment.
• Use data such as porosity,
permeability, lithology, fluid
saturation, fracture character and
stress regimes to determine
optimal fracture locations and
possible fracture propagations.
Shale Gas Extraction
Fracture Conductivity
Maximize Flowback / Long-Term Productivity
Fracture Design
Effective Multi-functional Frac Fluids
Fracture Placement
Fracture Dimensions / Proppant
Conductivity
Conductivity = kfrac*wfrac
Conductivity (Cf)
is a measure of
the fracture’s
ability to
transmit fluids
kf
Determining Realistic Proppant
Conductivity
• Laboratory testing – conducted to include as
many realistic damage factors as feasible
• Well testing – what do we infer from pressure
transient or decline curve analyses?
• Field results – how does well production change
when fracture width or proppant quality is altered?
Effective conductivities can be less
than 1% of API/ISO test values
5720
Effective Conductivity (md-ft)
6000
4310
5000
Jordan Sand
Lightweight
Ceramic
4000
98%
reduction
3000
1540
1410
2000
547
685
1000
120
167
225
85
25
7
0
ISO 13503-5 Test
"Inertial Flow" with
Non-Darcy Effects
Multiphase Flow
Lower Achieved Width
(1 lb/sq ft)
Gel Damage
Fines Migration /
Cyclic Stress
Slickwater Frac Design
• Stimulate the Formation
• Enhance the Return, or “Flowback” of the
Slickwater Solution Following Well
Stimulation
• Increase the Production of Gas from the
Reservoir
Desired Fluid Behavior
•
•
•
•
•
•
•
Low Leak-off Rate
Ability to Carry the Propping Agent
Low Pumping Friction Loss
Easy to Remove from the Formation
Compatible with the Natural Formation Fluids
Minimum Damage to the Formation Permeability
Break Back to a Low Viscosity Fluid for Clean Up
After the Treatment
Design Parameters
•
•
•
•
•
•
•
•
Fluid Type
Viscosity Requirements
Fluid Rheology
Economics of Fluid
Experience With Local Formations
Laboratory Data on the Formation
Material Availability
Proppant Selection
Turbulent and Laminar Flow
 The turbulent flow frictional loss in the wellbore and
perforations is important to design and perform a
fracturing treatment.
 The frictional losses are used to predict the surface
treating pressure and injection rate.
 The Laminar Flow Behavior of the Fluid is Critical to
the Design of Proppant Transport and Fracture Flow
Geometry.
Limited Entry Treatment
• Excellent means of diverting fracturing
treatments over several zones of interest at a
given injection rate.
• Effectiveness depends directly upon “back
pressure” or perforation friction.
• Pre-determined rate/perforation relationship.
Perforation Placement
•
•
•
•
•
Number of Perforations
Perforation Spacing
Near Wellbore Effects
Fracture Pressures
Stresses, etc.
Surface Pressure Components
Psurface = BHTP + ΔPfriction + Δ Pperf + ΔPnet - ΔPhydrostatic
where:
 BHTP = bottomhole treating pressure (frac gradient x
depth), psi
 ΔPfriction = treating pipe friction pressure (psi)
@ injection rate (psi)
 Δ Pperf = friction pressure through perforations (psi)
 ΔPhydrostatic = hydrostatic pressure, psi
Orifice Flow Equation
ΔPperf =
0.237 ρ Q2 / D4 C2
Where:
 Q = flow rate through each perforation (BPM/perf)
 D = Diameter of perforation (in.)
 C = Perforation coefficient
(0.95. for round perforation)
 ρ = Fluid density, lbs/gal
L.E. Treatment Procedure
1. Determine the value of ΔPperf - Limited Entry back
pressure.
2. Determine the rate/perf (Q):
Q = D2 C √ΔP/ρ / 0.487
Using 280 psi:
D = 0.42 in. (average diameter of perforations)
C = 0.95 (coefficient of roundness of jet perforation)
ΔPperf = 250 psi; ρ = 8.33 lb/gal
Then, Q = 2.0 BPM/perf
3. Determine the injection rate.
4. Specify pay zones and desirable distribution for the
Limited Entry hydrofracturing treatment.
Using:
•
•
•
•
•
Injection Rate: 40 BPM
Total Number of Perforations: 20
Perforation Friction Pressure: 280 psi
Perforation Diameter: 0.42 inches
Perforation Phasing: 180o (Wireline
Conveyed)
Closing
Success Factors
• Achieving a Low-risk, Safe and Productive
Operation
• Integrating Various Services into a
Seamless Operation
• Up-front Planning
• Designing Multi-Functional Frac Fluids
• Understanding Baseline Conditions
• Adjusting for Realistic Conditions
Dr. Barry Stevens
President
TBD America, Inc.
[email protected]
http://www.tbdamericainc.com