1. SPE Horizontal Well Stimulation Workshop
After the Shale-Gas Multi-Stage Frac –Recovering Valuable Operating Information on the Flowback
George E. King
17 November 2009
SPE Horizontal Well Stimulation Workshop

2. Why Bother with Flowback Analysis?
Information Available for Frac Design
Well Spacing and Orientation
Perf Cluster Spacing, Offset, Shot Density
Optimum Injection Rates, Max Pressures
Sand Size and Schedule
Production
Make a 50% Difference in Stable Production?
Reduce Produced Water by 50 to 90%
Warning Signs

3. Scope of the talk
Limited to gas shales stimulated by slick water fracs
Touching lightly on:
Frac Pressure / Rate / Loading response,
Chemical and RA Tracers,
Microseismic (near real time),
Flowback Volume & Salinity Measurements
Production Logs
Production Rate and EUR
The information available from a frac, its flowback and the ensuing production is often confusing, because so many variables are in play.

4. Primary & Secondary Frac Directions
Natural fractures & stresses along wellbore are critical to developing large frac-to-formation contact areas.
Natural fractures (even mineralized) can open at ~60% of pressure needed to create a new fracture. This allows frac complexity to develop.
The problem is keeping them open – not only propped, but free of liquids that block the micro-cracks
Brittle shales (high Mod., & low Poisson’s ratio) best stimulation targets.
Schlumberger

5. Not all the formation is the same…..

6. Pore Micro-Fracture Passages
Opening natural fractures takes ~ 60% of the stress to break the rock.

7. Look at the Pieces Why does flowback matter?
Shale wells that recover frac load water too rapidly strand water in the microfractures – permeability to gas is reduced.
At least one cause is capillary pressure – a control on water movement in the smallest fractures.

8. Capillary Forces – in fractures?
Note that capillary pressure is increasing as initial load is recovered & saturation of water in the pore (or micro- fracture) is decreasing.
Capillary pressure increases sharply in smaller pores (and smaller fractures).
Effects of capillary forces will be less for fractures than pores but will still be a factor limiting recovery of water from a highly fractured flow system.
From Penny, et. al., 2006

9. Threshold Pressure -
Capillary pressure threshold (press to overcome cap. force & initiate flow), shown for three orders of magnitude.
Water molecule diameter slightly smaller than CH4 molecule diameter (4.3 A) but in same relative size range.
Methane is lower viscosity than water, thus slippage & fingering of gas through water during recovery is expected.

10. Moving liquids out of the fractures
Gas flow rate through a proppant packed fracture impacts liquid recovery.
Authors showed water expulsion from a fracture increased with increasing gas velocity.
Small amounts of surfactant or micro-emulsion can sharply increase the recovery at very low gas rates.
(Penny, et. al SPE ).

11. T-2H – Pressure, Rate and Prop Loading

12. Balancing the pressure increase……
In western Barnett, declining net pressures during fracs often have frac breakouts to Ellenberger (wet).
Rates of net pressure increase that are too high may lead to screenouts or poor complexity development.
If frac rate is too low, little formation is accessed by the frac and the load water may not be recovered.
If frac rate is too high, frac width increases and fracs are often long with little frac complexity.
Some ideas?
Increase the complexity…….

13. What’s the Fracture Complexity Index?
Xf (frac half ln)
Width of flow path
W/Xf
800
500
0.63
FCI Reference SPE , Cipolla, et.al.
500/800 = 0.63
FCI ratio is an indicator of spread.
Use to design well spacing on pads
No right or wrong
Target here was FCI > 1

14. > 20% of M-S events below pay 500 BWPD
Starting Point…..
Initial – high rate, tracers & micro-seismic. Follow up? Next – shorten the frac and make it wider…….
> 20% of M-S events below pay 500 BWPD
W/Xf = 0.3

15. Next Step – Optimize the Rate
Sequential Fracs, rate by M-S activity,
Xf not yet modified by sand slugs
<5% of points below Barnett
Well made ~ <50 bwpd
W/Xf = 1

16. Single Fracs – Reaching too Far?
W/Xf = 0.7

17. Sequential Fracs – Barnett, Western Parker Co.
Zipper Frac - generally good complex fracture coverage.
W/Xf = 2

18. Comparison of Frac Spread and Fracture Direction
Well /Stage
Width of Flow Path Cloud
Xf (frac half length)
H (total height events)
Frac Complexity Index W/Xf
Primary frac
Second frac
Cluster Direction
T1 stage 1
1370
930
301
1.5
N 42 E
S 38 E
N 16 E
T1 stage 2
1374
659
425
2.1
N 61 E
S 39 E
N 5 E
T1 stage 3
1056
555
338
1.9
N 56 E
N 83 E
N 9 E
T1 stage 4
1129
636
501
1.8
N 17 E
S 48 E
N 7 E
T1 stage 5
1016
735
422
1.4
N 46 E
T1 stage 6
1211
577
523
N 45 E
N 59 E
T1 stage 7
755
571
509
1.3
N 53 E
S 36 E
S 89 E
T1 stage 8
1025
549
364
S 44 E
N 78 E
T2 stage 1
1615
767
288
S 43 E
N 47 E
T2 stage 2
1845
1014
306
S 45 E
N 89 E
T2 stage 3
1175
913
340
S 54 E
S 74 E
T2 stage 4
1228
763
448
1.6
N 51 E
S 42 E
N 67 E
T2 stage 5
866
662
492
S 64 E
N 6 E
T2 stage 6
855
668
499
N 36 E
S 35 E
T2 stage 7
621
665
314
0.9
N 48 E
S 52 E
N 38 E
T2 stage 8
1040
980
273
1.1
N 58 E
S 51 E
N 55 E
T2 stage 9
1110
681
252
S 40 E
S 80 E
T2 stage 10
971
677
254
N 43 E

19. Tracers – What broke down, what produced back?
Tracer tagged sands are used periodically to analyze proppant breakdown points and near well communications.
Tracer tagged pad & frac waters determine:
which intervals are broken down in each of the perf clusters
which intervals are flowing back first;
which continue to flow with time;
which stay open compared to prod log. ?

20. Flowback Efficiencies & Interference

21. Flowback Efficiencies & Interference
2nd MR = 2200 mcf/d
2nd MR = 2000 mcf/d

22. Flowback Efficiencies and Interference

23. Flowback Efficiencies and Interference
2nd MR = 1400 mcf/d
2nd MR = 800 mcf/d

24. Traditional Flowback – vol. and salinity
Sequential fraced pair of wells,
T-1H 3000 ft, 8 stages
T-2H 3200 ft 10 stages
750 ft apart.
BBLs water or ppm Cl-
Now, why did one well produce 2.3 mmcf/d and the other only 1 mmcf/d?
Days on Flowback

25. Sequential Fracs – Barnett, Western Parker Co.
Zipper Frac - generally good complex fracture coverage.
W/Xf = 2

26. But, compare the rate of water recovery….
% Load Water Recovered
Days on Flowback
T1 recovered 40% of its load in 5 days
T2 recovered 20% of its load in 5 days
Days on Flowback

27. Water Inflow From a Fault - PLT

28. PLT and Microseismic
Stage 6
Stage 5
Stage 4
Stage 3
Stage 2
Stage 1
6000’
6500’
7000’
7500’
8000’
Production log & micro-seismic – hard to see connection w/o treating pressure
75% W
45% Gas
25% W
10% Gas
5% Gas
10% Gas
10% Gas
10% Gas
10% Gas
Stage 5

29. Other Items
Mud log shows and 3D seismic overlays with frac microseismic and tracers – where are flow paths?
Optimum wellbore spacing and offset of perf clusters are often missed opportunities.
Slugs of sand and mixed slugs to control frac length or downward growth (SPE )
Shear dilation of the fractures – achieving maximum shear fracturing (SPE )
Perforating clusters and frac initiation (103232)
Microseismic and Rock Mechanics (SPE & )

30. Conclusions
Flow back and post job analysis provide very valuable information to every element of the well construction and operation in a shale gas well.
Tracers – frac entry, water influx, active zones, min frac rates, wellbore isolation, well-to-well communication
Microseismic – complexity, height, max & min rates, effect of sand and slugs, missed zones, breakout.
PLT – fluid entry, type, rate
Salinity and ions – frac breakout, mixing
% recovery and time – Recovery max.

31. Questions?