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

2. Use FULL SCREEN or SLIDE SHOW for better viewing

3. Proppant Placement Problems

4. 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

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

6. FRACTURE WIDTH DECREASES WHEN FRAC PRESSURE REMOVED
SPE

7. Proppant Plugging With Fines

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

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

10. Small Fines Migrate To Wellbore Blauch,1999 SPE 56833

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

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

13. PROPPANT CRUSHING PROBLEMS

14. SPHERE PACKINGSPH

15. Point Contacts Create High Stresses
(Extremely high stress)

16. HIGH HERTZIAN CONTACT STRESS

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

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

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

20. 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

21. Proppant Embedment Problems

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

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

24. Sandstone Embedment Craters (Weaver, 2005) SPE 94666

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

26. Proppant Chemical Solution Problems

27. 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

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

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

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

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

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

33. Proppant Flowback Can Seal off Fracs

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

35. 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

36. MicroSeismic Technology

37. 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”

38. ”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

39. Barnett Shale Well A Refracing
SPE
SPE

40. Well A Microseismic Events – 2 stage
SPE

41. Well A Microseismic Events Distribution
SPE

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

43. BARNETT SHALE STIMULATION
CIPOLA 2005
SPE

44. Well B Microseismic Events – 3 stage
SPE

45. Barnett Shale Well B Refracing (MicroSeismic)
SPE

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

47. SHALE PROPERTIES

48. Natural Fractures in Shale

49. 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

50. 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 = 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

51. Void Spaces in Shale

52. 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

53. 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

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

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

56. EAGLE FORD SHALE KEROGEN (OIL)

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

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

59. 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

60. 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

61. 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

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