After the Shale-Gas Multi-Stage Frac –Recovering Valuable Operating Information on the Flowback

1. 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 liquidsthat block the micro-cracks • Brittle shales (high Mod., &low Poisson’s ratio) beststimulation 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. 2006 SPE 100434).

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? FCI Reference SPE 115769, 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. 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

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 748674447402736073187276 Stage 2 712470827040699869566914 Stage 3 784878067764772276807638 Stage 1 676267206636667865946552 Stage 4 603859965924591258705828 Stage 6 640063586316627462326190 Stage 5 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 119896) • Shear dilation of the fractures – achieving maximum shear fracturing (SPE 106289) • Perforating clusters and frac initiation (103232) • Microseismic and Rock Mechanics (SPE 125239 & 115771)

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?