Frac Plugging And Shale Properties DR. WILLIAM MAURER Maurer Engineering Inc Austin, TX January 1, 2016

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Proppant Placement Problems

Is this ribbon laterally Uniform Packing Arrangement? Pinch out, proppant pillars, irregular distribution? Is this ribbon laterally extensive and continuous for hundreds of meters as we model? VINCENT 2010A

THREE POSSIBLE PROPPANT ARRANGEMENTS IN FRACTURES LONG CONTCT WITH WELLBORE FLOW CONTROLLED PRIMARILY BY POOREST SECTION OF FRACTURE SPE 119143

FRACTURE WIDTH DECREASES WHEN FRAC PRESSURE REMOVED SPE 119143

Proppant Plugging With Fines

Mixed size fines are most effective for plugging Fracture Plugging (Mixed Size) Mixed size fines are most effective for plugging

ASSUMING GOOD FRACTURE CONDUCTIIVITY CAN BE MISLEADING Vincent 2010 THIN SECTION FROM STIM-LAB SPE 119143

Small Fines Migrate To Wellbore Blauch,1999 SPE 56833

Smaller Fines Produce Tighter Packing (Blauch, 1999) SPE 56833

Pore Plugging Major Fracing Problem (Blauch, 1999) SPE 56833 MOST OF THE FRAC PERMEABILITY REDUCTION IS DUE TO PORE BRIDGING

PROPPANT CRUSHING PROBLEMS

SPHERE PACKINGSPH

Point Contacts Create High Stresses (Extremely high stress)

HIGH HERTZIAN CONTACT STRESS

herheHERTZIAN FRACTURE INITIATION High Contact Stress Creates Crushed Zone and High Tensile Stress Below

SPHERE SHATTERING SMALL FINES WILL PROPAGATE ALONG FRAC AND PLUG CONSTRICION ZONE NEAR WELLBORE

Crushed Proppants Create Fines (Terracina, 2010) SPE 135502 404X Ceramic Proppants 10,000 psi 404X PROPANT CRUSHING CREATES FINES THAT PLUG FRACS

Percent Fines vs. Closure Stress (Terracina, 2010) SPE 135502 6,000 psi closure stress crushes 9.5% of the proppants, producing a large volume of fines to plug fracs

Proppant Embedment Problems

Proppant Embedment Creates Fines that Plug Fracs (Terracina, 2010) SPE 135502 craters Embedment reduces frac width and creates craters and formation fines

Embedment Craters with 20/40 mesh Proppants(Weaver, 2005) SPE 94666

Sandstone Embedment Craters (Weaver, 2005) SPE 94666

Proppant Embedment (Terracina, 2010) SPE 135502 514x EMBEDMENT CREATES FORMATION FINES THAT PLUG FRACS

Proppant Chemical Solution Problems

Proppant Dissolving Mechanism (Weaver, 2005) SPE 94666 Proppants dissolve into the frac fluid at high stress points and precipitate out at low stress points, reducing frac width and plugging fracs

Frac Closure due to Proppant Solution (Weaver, 2005) SPE 94666

Proppant Solubility Increases with Temperature Weaver, 2005 SPE 94666 TEMPERATURE INCREASES FRAC SOLUBILITY SIGNIFICANTLY

Proppant Solubility Increases With Fluid Pressure (Weaver, 2005) SPE 94666 50 Mpa = 7251 psi PRESSURE INCREASES PROPANT SOLUBILITY CONSIDERABLY

Proppants Undergo Considerable Solution in 3 Days (WEAVER, 2005) SPE 94666

Precipitated Proppant Material (Terracina, 2010) SPE 135502 HIGH TEMPERATURES DISSOLVE SAND PROPPANTS AND THEN THE SILICA PRECIPITATES OUT AND PLUGS THE FRACS

Proppant Flowback Can Seal off Fracs

Proppant Flowback (Terracina, 2010) SPE 135502 AT THE FLOWBACK CAN ALLOW FRACS TO CLOSE NEAR THE WELLBORE

BP BEST REFRACING CANDIDATES (WOODFORD SHALE) (Kari Johnson, K , World Oil, October 2015) 500 foot frac spacing Minimal proppant placement Un-perforated pay at the “heel” Significant gas in place Convenient water availability They recommend pumping a trace material to show where the proppant is located

MicroSeismic Technology

Refracs Stimulate only 50% of Fracs (Kashikar and Jbeil) June 2015 World Oil On these two wells using diverters to isolate stages, less than 50% of the stages closest to the “heel” were stimulated. “This is a common occurrence where operators must rely on diverters to isolate perf clusters”

”HYBRID WELL” - Combined Refracing and Drainholes “ Drainhole (Proposed) In well 2, a proposed drainhole could be used to stimulate the fracs in the last half of the horizontal well This type of “Hybrid Well” may be a good way to combine the best features of refracing and drainholes to maximize production and minimize fracing costs

Barnett Shale Well A Refracing SPE 119636 SPE 119636

Well A Microseismic Events – 2 stage SPE 119636

Well A Microseismic Events Distribution SPE 119636

BARNETT SHALE WELL REFRAC - Microseismic 11ST FRAC - GELL (1000 MCF/D) 2ND FRAC - SLICK WATER (1500 MCF/D) CIPOLA 2005 SPE 134330

BARNETT SHALE STIMULATION CIPOLA 2005 SPE 134330

Well B Microseismic Events – 3 stage SPE 119636

Barnett Shale Well B Refracing (MicroSeismic) SPE 119636

MIMPLEMENTATION TEAM Maurer Engineering – Drainhole Concepts and Patents Drilling Engineering Firm – Field Engineering and Drainhole Designs Microseismic – Field Instrumentation and Candidate Well Selection

SHALE PROPERTIES

Natural Fractures in Shale

Lateral Heterogeneity (macro scale)? • If natural fissures are a significant component of fluid flow in the formation… How are they distributed? Can we avoid damaging them? Single Plane HC expulsion fissures lacking well-developed conjugate set (Leigh Price, Bakken) Conjugate like we envision in CBM (face and butt cleats) or Barnett Shale Swarms SPE82212 James Lime VINCENT 2010A

Oil is Produced Through Voids in the Shale Not Natural Fractures 10,000 PSI 4,000 PSI PSI NATURAL FRACTURES VOID SPACE At 10,000 feet depth, the vertical rock stress = 10,000 psi and the horizontal stress = 4000 psi These high rock stresses close all natural fractures in shale The natural fractures cannot be propped open because of their small width and proppant embedment Oil is therefore produced through voids which remain open under high stresses

Void Spaces in Shale

Albany, Ingrain Inc Eagle Ford, Ingrain Inc Flow is through large pore spaces as shown in four different commercial shales Pearsall Shale, S. TX (Loucks, 2010) Haynesville, Loucks, 2010 Eagle Ford From Loucks, et al, GCAGS, April 2010 Haynesville, E.TX (Ingrain) Eagle Ford, Ingrain Inc

EAGLE FORD SHALE (WALLS AND SINCLAIR, 2011) 1000m nD = 1 mD EAGLE FORD SHALE POROSITY IS UP TO 12 PERCENT AND PERMEABILITY IS UP TO 100 mD

EAGLE FORD SHALE This shows the relative size of oil molecules to the pore size EAGLE FORD SHALE

Shale Oriented Core For Measuring Horizontal Permeability (Soeder,1988) SPE 15213

EAGLE FORD SHALE KEROGEN (OIL)

(Note high calcite content) This shows distributions of minerals and organics In Devonian Shale (Note high calcite content) Shale Properties

EAGLE FORD SHALE CORE Note the small natural fractures filled with silica and other minerals

Woodford Shale Outcrop Some reservoirs pose challenges to effectively breach and prop through all laminations Our understanding of frac barriers and kv should influence everything from lateral depth to frac fluid type, to implementation THIS SHALE HAS GOOD HORIZONTAL AND POOR VERTICAL CONTINUITY SHOWING THE NEED FOR HYDRAUIC FRACING VINCENT 2010A

OIL FLOW IN SHALE The pressure to push oil though the shale into the frac comes from an expanding gas cap or water drive. Oil flow rate is proportional to the shale permeability and the pressure drop between the fluid in the shale and in the frac (drawdown pressure) .As fracs plug, the pressure in the frac away from the damaged decreases rapidly, causing the rapid decline in shale wells (50% first year, and 70% the second year) Drain holes should never plug (due to their large flow area) so they should completely eliminate the rapid decline due to frac plugging

Eagle Ford Shale Outcrop (35 feet) Eagle Ford fracs are typically 50 to 200 feet high This shows layering that provides horizontal permeability The tall cliff shows the high strength of Eagle Ford shale

THE END wcmaurer@aol.com 512-263-4614