1 Shale Fracturing: The Geology And Technology That Sustained The Boom Welcome! The webinar will begin promptly at Noon (CST) Dr. Jon Olson Professor Chairman Petroleum and Geosystems Engineering Department The University of Texas at Austin Dr. MukulSharma Professor "Tex" Moncrief Chair Department of Petroleum and Geosystems Engineering The University of Texas at Austin Dr. Zoya Heidari Assistant Professor Department of Petroleum and Geosystems Engineering The University of Texas at Austin
Transcript
1
Shale Fracturing: The Geology And Technology That Sustained The Boom
Welcome!The webinar will begin promptly at Noon (CST)
Dr. Jon OlsonProfessor ChairmanPetroleum and GeosystemsEngineering DepartmentThe University of Texas at Austin
Dr. Mukul SharmaProfessor "Tex" Moncrief ChairDepartment of Petroleum and Geosystems EngineeringThe University of Texas at Austin
Dr. Zoya HeidariAssistant ProfessorDepartment of Petroleum and Geosystems EngineeringThe University of Texas at Austin
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Shale Fracturing: the geology and technology that led to the boom
Dr. Jon E. OlsonChair and Professor
Petroleum & Geosystems Engineering
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Outline• why is fracturing important• what is a hydraulic fracture• lessons from geology• fracture mechanics tests in the lab• small-‐scale fluid injection experiments to demonstrated hydraulic fracture complexity
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2011 – horizontal well, 15 fracs
1996 – vertical well, single frac
Barnett Shale: Technology Matters
without fracturing
Dr. Jon Olson
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US Natural Gas Productionfrom US Energy Information Agency, through July 2015
Dr. Jon Olson
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What is a hydraulic fracture?
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Rock Failure Modes: dispelling myths
unconfined compressive test
hydraulic fracturing in acrylic
Dr. Jon Olson
8 from slb.com
SHmax,maximum horizontal
stress
Shmin,minimum horizontal
stress
Gross Fracture geometry is systematic & predictable
Dr. Jon Olson
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Hydraulic Fracture Geometry
Horizontal well with multiple transverse fractures
Horizontal well with longitudinal fracture
Vertical well with vertical fracture
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Lessons on fracture propagation and interaction
from geology
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Muddy Gap, WY
S∝H
thick beds 11Jon OlsonUT-‐Austin, FRAC
Systematic natural fractures
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Impact of lithology on fracture growth
• natural fracture spacing in shales often closer than other lithologies
• depends strongly on mineral make-‐up of rock
• ductile clay layers can be fracture arrestors within more brittle shale interbeds
Dr. Jon Olson
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Impact of lithology on fracture growth
• natural fracture spacing in shales often closer than other lithologies
• depends strongly on mineral make-‐up of rock
• ductile clay layers can be fracture arrestors within more brittle shale interbeds
Dr. Jon Olson
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Impact of lithology on fracture growth
ductile claybarrier
Huron Shale, Ohio
fracture arrest
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Fracture Interaction with Bedding Planes
• siliceous mudstone, Miocene Monterrey Fm.
• vertical quartz-filled fracture selectively propagates across gray beds (marly), along white beds (phosphatic)
1 cm
from Portuguese Bend, Palos Verdes, CADr. Jon Olson
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1 cm
from Portuguese Bend, Palos Verdes, CA
• siliceous mudstone, Miocene Monterrey Fm.
• vertical quartz-filled fracture selectively propagates across gray beds (marly), along white beds (phosphatic)
• natural veins fluid-‐driven fractures occurring at depth (i.e., good analogy for hy-‐frac)
• bedding planes and pre-‐existing veins can divert fracture propagation (frictional interfaces would do same)
• vein thickness increases chance of diverting propagation
Dr. Jon Olson
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Fracture Mechanics Testing of Cores –
Marcellus Shale
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(a)
Marcellus Core Testing• test vein strength,
fracture interaction with Marcellus Core
• saw and grind samples rather than plug to reduce damage/breakage
• propagate induced fractures using Semi-‐Circular Bending test
fromLee, Olson, Holder, Gale and Myers, 2015, JGRdoi:10.1002/2014JB011358
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(a) (b)
(c)
(d)
• test vein strength, fracture interaction with Marcellus Core
• saw and grind samples rather than plug to reduce damage/breakage
• propagate induced fractures using Semi-‐Circular Bending test
fromLee, Olson, Holder, Gale and Myers, 2015, JGRdoi:10.1002/2014JB011358
Marcellus Core Testing
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(a) (b)
(c)
(d)
(e)
• test vein strength, fracture interaction with Marcellus Core
• saw and grind samples rather than plug to reduce damage/breakage
• propagate induced fractures using Semi-‐Circular Bending test
fromLee, Olson, Holder, Gale and Myers, 2015, JGRdoi:10.1002/2014JB011358
Marcellus Core Testing
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(a) (b)
(c)
(d)
(e)
• test vein strength, fracture interaction with Marcellus Core
• saw and grind samples rather than plug to reduce damage/breakage
• propagate induced fractures using Semi-‐Circular Bending test
fromLee, Olson, Holder, Gale and Myers, 2015, JGRdoi:10.1002/2014JB011358
Marcellus Core Testing
32
(a) (b)
(c)
(d)
(e)
Marcellus Core Testing
fromLee, Olson, Holder, Gale and Myers, 2015, JGRdoi:10.1002/2014JB011358
• test vein strength, fracture interaction with Marcellus Core
• saw and grind samples rather than plug to reduce damage/breakage
• propagate induced fractures using Semi-‐Circular Bending test
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• sample diameter = 2-‐4 in• vein thickness = 0.01-‐0.075 in• failure along flaws in calcite
vein-‐fill (fluid inclusion trails and cleavage)
Failure Occurs Within the Cement
failed SCB sample
thin section of calcite vein fill
plane polarized light crossed nicolsDr. Jon Olson
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Multiple Saw Cuts & GrindingDiameter = 2.5 inThickness of the vein= 0.009 in
(a) (b)
(c) (d)
SCB test Resultscrossing preferred at more orthogonal approach angle
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0.075 in 0.05 in
0.035 in 0.01 in
(a) (b)
(c) (d)
Impact of Vein Thicknesscrossing preferred for thinner veins
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Testing summary
• demonstrated that well-‐cemented veins can provide planes of weakness
• tests at varying approach angles can quantify vein strength• critical energy release rate of veins ~ ¼ shale matrix
• vein toughness, KIc, was estimated to be higher than shale
• failure depends on strength and stiffness of veinsKIC(vein)~0.8 MPa-‐m1/2 KIC(shale)~0.5 MPa-‐m1/2
Dr. Jon Olson
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Small-‐scale Laboratory Hydraulic Fracture
Experiments
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Hydraulic fracturing in fractured reservoirs
Fisher et al 2004 Warpinski & Teufel, 1987
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Physical Experiments: Interaction between cemented flaws and fluid driven cracks
Hydraulic Injection Tube (Wellbore)
hydrostone = gypsum-based cement39
Dr. Jon Olson
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Natural Fractures (glass slides)
Sh,max
Pour Hydrostone Blocks with Embedded Discontinuities
Sh,max Natural Fractures (glass slides)
Dr. Jon Olson
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Load Frame – apply Svert, SHmax, Shmin
Flatjacks
Hydraulic Injection Tube (wellbore)
Flatjack Pressure Lines
Dr. Jon Olson
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Uncovering Hydraulic Fractures
42Dr. Jon Olson
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Complex Interaction – Oblique Case
wellbore
natural fracture
43Dr. Jon Olson
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Complex Fracture propagation/interaction
Bahorich et al., SPE 190197
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Complex Fracture propagation/interaction
Bahorich et al., SPE 190197
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Complex Fracture propagation/interaction
diverts along natural fracture
mixed mode I-‐II non-‐planar curving
Bahorich et al., SPE 190197
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Complex Fracture propagation/interaction
part of fracture propagates under natural fracture
diverts along natural fracture
mixed mode I-‐II non-‐planar curving
Bahorich et al., SPE 190197
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Summary• shale gas has made energy more affordable and secure in the United States
• much of hydraulic fracture complexity has an analogy in natural fracture examples
• one key to complexity is the interaction of hydraulic fractures with natural fractures
• laboratory testing can be used to quantify pre-‐existing fracture strengths and to run small-‐scale hydraulic fracture tests to illustrate potential geometries
Dr. Jon Olson
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Acknowledgment: FRAC Consortium Sponsors
http://www.beg.utexas.edu/frac
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Well Spacing, Fracture Spacing, Sequencing and Fluid Management in Pad
Fractured Horizontal Wells
Mukul M. SharmaUniversity of Texas at Austin
Dr. Mukul Sharma
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JIP FACT SHEETSponsors for 2014-‐15
•RPSEA / DOE: 2 projects for $2,400,000 for 2013-2016•The State of Texas pays faculty salaries.•Your funds are leveraged about 50:1
Other potential members that have expressed interest:• PTT• Petrobras•ONGC• Chesapeake
Murtadha Al Tammar Haotian WangPrateek Bhardwaj Chu-‐Hsiang WuMichael Brothers Weiwei WuChris Blyton Mingyuan YangEric C. Bryant Shiting YiMichael Carey Jason YorkDeepen Gala Peng ZhangChang Min Jung Junhao ZhouHojung Jung Saud Alquwizani*Emmanouil Karantinos Samarth Agarwal*Ashish Kumar Saptaswa Basu*Dongkeun Lee Stephen A. Bryant*Hisanao Ouchi Jameson P. Gips*Javid Shiriyev Jongsoo Hwang*Igor Shovkun Eric R. Lehman*Kaustubh Shrivastava Lionel Ribeiro*Jeffrey Stewart Roman Shor*Sanjay Surya Do Shin*
Research Staff:§ Yaniv Brick§ Philip Cardiff§ Ajeetha Kamilla§ Jin Lee§ Ripudaman Manchanda§ Anand S. Nagoo§ Rodney T. Russell
Graduate Students:
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Top Five Ideas Worth Trying
1. Treat fracture design as a multi-frac, multi-well problem. This will provide the optimum,– Well spacing, fracture spacing, fracture sequencing– Fracture design
2. Liquids lifting through entire life of well– Wellbore trajectory– Artificial lift design
– New methods to divert fluids during refracturing– Better candidate selection
Dr. Mukul Sharma
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Pad Fracturing: The Big PictureLearning from Experience
• There is no general consensus on most recommendations regarding well spacing, proppants, pumping rates, fluids, flowback…….– Too many variables– Too few wells and too little data– Expensive learning
• There is a real and significant financial benefit to accelerating the learning process (capital efficiency).
• How do we accomplish this?– Learn from existing wells (data analysis)– Physics based models– Combine the two (iterate).
Dr. Mukul Sharma
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Multiple Non-‐Planar Fracture PropagationFracture Stage with 4 Perforation Clusters
Q
q1
q2
q3
q4
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Signatures of Fracture Complexity / Interference
Bakken
Barnett
Eagle Ford
Fracture Trajectory vs. Distance from Stage 1 (ft) Net Closure Pressure vs. Stage Number
Ref: Roussell and Sharma, 2012, ARMA 12-‐633
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Complex Fracture Networks
Ref: Warpinski, N.R. et al, SPE 114173, 2008
In addition to stress shadowing, fracture complexity also arises due to:q Complex rock fabricq Natural fracturesq Bedding planesq Heterogeneity
q Stress anisotropyq Shear failure
Stress interference, natural fractures, heterogeneities, pore pressure depletion, rock fabric can all lead to fracture complexity. Dr. Mukul Sharma
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Bossier TGS, Anadarko (Sharma et al. 2004)
Barnett Shale, Devon
(Fisher et al. 2005)
Fracture Complexity is a Strong Function of Rock Fabric and Local Stress Contrast
Dr. Mukul Sharma
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Effect of Rock Fabric and Stress Anisotropy
Ref: SPE 173374-‐ Arbitrary Fracture Propagation in Heterogeneous Poroelastic Formations Using a Finite Volume-‐Based Cohesive Zone Model • Eric C. Bryant, M. M. Sharma, 2015.
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We Can Control Fracture Complexity, To Some Degree
Wellbore
Fracture 1
Stress Reversal Region
Reoriented σhmaxdirection
Region of Low Stress Contrast
σhmax – σhmin(psi)
Wellbore
Stress Reversal Region
Decreasing σhmin
away from the fracture
σhmin(psi)
Fracture 1
σhmin is increased close to the propped-‐open fracture and exceeds the original σhmax value causing reorientation of the σhmax direction.
Fractures that propagate in regions of low stress contrast are likely to show more fracture complexity.
Estimating Optimum Well Spacing and Fracture Spacing (Lf = 160 ft)
Dr. Mukul Sharma
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• There are many reasons to treat the fracture design problem on a pad scale (a multi-‐well, multi-‐fracproblem):– Interference between fractures – Fracture complexity / reservoir heterogeneity– Some ability to control fracture complexity
• Computing pore pressure, stress and failure maps is important for:– Establishing well spacing – Selecting locations for infill or step-‐out wells – Selecting fracture spacing in the new well– Fracture designs in new wells– The feasibility of an infill well
Summary
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Top Five Ideas Worth Trying
1. Treat fracture design as a multi-frac, multi-well problem. This will provide the optimum,– Well spacing, fracture spacing, fracture sequencing– Fracture design
2. Liquids lifting through entire life of well– Wellbore trajectory– Artificial lift design
– New methods to divert fluids during refracturing– Better candidate selection
Dr. Mukul Sharma
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Wellbore Liquids Management
q Well productivity is a strong function of wellbore liquids loading and wellbore trajectory
q Every unconventional well will be on artificial lift for 90% of its life.
q To properly manage wellbore fluids we must:
q Unload liquids from fractures and the wellbore
q Unload liquids from the reservoir matrix
q Integrate wellbore models with reservoir inflow
q Properly design and manage artificial lift.
q Obtain good estimates of BHP from THP
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How Good Are Our Wellbore Models?
Cousins, Denton and Hewitt (1965) – Exp. # 49, data also in Table 12.1 of Wallis’s One Dimensional Flow textbook
Dr. Mukul Sharma
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Run numbers 7.02 to 7.09 in the reference: Hewitt, G. F., King, I., Lovegrove, P. C.: Holdup and pressure drop measurements in the two-‐phase annular flow of air-‐water mixtures, UK AERE Report R3764, June (1961)
Run numbers FHOPI-‐46 to FHOPI-‐49 in the reference: Crowley, C. J., Sam, R. G., Rothe, P. H.: Investigation of two-‐phase flow in horizontal and inclined pipes at large pipe size and high gas density, Project PR-‐172-‐507, Pipeline Research Committee, AGA, February (1986)
How Good Are Our Wellbore Models?
Dr. Mukul Sharma
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Owen, D. G.: An experimental and theoretical analysis of equilibrium annular flows, Ph.D. Dissertation, Dept. of Chem. Eng., U. of Birmingham (1986)
Also available from Theofanous, T. G., Amarasooriya, W. H.: Dataset no. 1 -‐pressure drop and entrained fraction in fully developed flow, Multiphase Sci. and Tech., v. 6, part 1, pp. 5-‐13 (1992)
How Good Are Our Wellbore Models?
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Kumar, N.: Improvements for flow correlations for gas wells experiencing liquid loading, Soc. of Petroleum Engineers, Paper No. 92049 (2005)
Chierici, G. L., Ciucci, G. M., Sclocchi, G.: Two-‐phase vertical flow in oil wells -‐prediction of pressure drop, Soc. of Petroleum Engineers, Paper No. 4316, August (1974)
How Good Are Our Wellbore Models?
Dr. Mukul Sharma
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Slightly-‐Inclined Flow: Horizontal Wells
Ø In long laterals, segmentation is important because of the need to Ø Capture the local multiphase
flow developmentØ Different wellbore regions and
reservoir zonesØDifferent well inflow from multiple entry points with productivity indices (PIs)
ØDifferent lithologies, rock qualities, stress gradients
Ajayi et al.: Stimulation Design for Unconventional Resources, Schlumberger Oilfield Review, Summer (2013) Dr. Mukul Sharma
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Toe-‐Up WellborePFF Simulator
Dr. Mukul Sharma
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Correct trend is captured for both pressure and gas
holdup
Toe-‐Up Wellbore: PFF SimulatorComparison with Well Data
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Undulating WellborePFF Simulator
Dr. Mukul Sharma
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Undulating WellborePFF Simulator
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Liquids Unloading
q Obtaining good estimates of BHP from THP
q Effect of wellbore trajectory on well productivityq Unloading of liquids from fractures
q Integrating wellbore models with reservoir inflow
q Unloading of liquids from the reservoir matrixq Design of artificial lift.
Dr. Mukul Sharma
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• Competing forces : drawdown vs. gravity vs. capillary
• Capillary forces inhibiting flow of water
• Gravity pulling liquid to the bottom
• Turner’s critical velocity for vertical gas wells:
Water flowing upward at high gas rates and downward at
low gas rates
Loading in fracture?? High Sw, Low gas rel perm
Liquid Loading Inside Fracture
Dr. Mukul Sharma
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Can the Gas Lift the Liquid in the Fracture?
Dr. Mukul Sharma
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Integrating Wellbore Flow with Reservoir Inflow
Ø To model the impact of wellbore trajectory on hydraulically-‐fractured horizontal well productivity it is important to account for the effect of water unloading in the wellbore the fracture and the rock matrix
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Integrating Wellbore Flow with Reservoir Inflow
Dr. Mukul Sharma
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Liquids Removal Takes Time
Property Value
Matrix Permeability 1 µD
Fracture Permeability 2 D
Drawdown 2000 psi
Variation of water saturation inside Fracture Variation of water saturation in matrix near fracture
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Water and Condensate BlockingØ Water /condensate blocking can cause a severe reduction in gas and condensate relative perms.
Ø Chemical treatment using a non-ionic fluorinated surfactant increases gas and condensate relative permeability by a factor of 2.
Ø Proppant can be treated as well to improve proppant-pack conductivity.
Ø 6 field trials conducted. More underway.
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References• “Flow-‐Through Drying of Porous Media”, AIChE Journal, July, 2006, J.
Mahadevan, M. M. Sharma and Y.C. Yortsos.• “Water Removal from Porous Media by Gas Injection: Experiments and
Simulation” Transport in Porous Media Journal, 2007, J. Mahadevan, M. M. Sharma, and Y. Yortsos.
• “Evaporative Clean-‐up of Water-‐Blocks in Gas Wells”, Journal of Petroleum Technology, pp 46-‐68, October 2005, J. Mahadevan, M. M. Sharma and Y.C. Yortsos.
• “Factors Affecting Clean-‐up of Water Blocks: A Laboratory Investigation,” SPE Journal, September 2005, J. Mahadevan, M.M. Sharma.
• “Evaporative Clean-‐up of Water-‐Blocks in Gas Wells”, SPE 94215, presented at the 2005 SPE Production and Operations Symposium held in Oklahoma City, OK, April 17-‐19, 2005, J. Mahadevan and M.M. Sharma
• “Cleanup of Water Blocks in Depleted Low-‐Permeability Reservoirs”, SPE 89837 presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 26–29 September 2004, B. Parekh, and M.M. Sharma.
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Top Five Ideas Worth Trying
1. Treat fracture design as a multi-frac, multi-well problem. This will provide the optimum,– Well spacing, fracture spacing, fracture sequencing– Fracture design
2. Liquids lifting through entire life of well– Wellbore trajectory– Artificial lift design
– New methods to divert fluids during refracturing– Better candidate selection
Dr. Mukul Sharma
85
Shale Fracturing: The Geology And Technology That Sustained The Boom
Q&APlease enter your questions in the chat box on the left.
Dr. Jon OlsonProfessor ChairmanPetroleum and GeosystemsEngineering DepartmentThe University of Texas at Austin
Dr. Mukul SharmaProfessor "Tex" Moncrief ChairDepartment of Petroleum and Geosystems EngineeringThe University of Texas at Austin
Dr. Zoya HeidariAssistant ProfessorDepartment of Petroleum and Geosystems EngineeringThe University of Texas at Austin
86
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