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The following discussions contain certain “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995 including, without limitation, estimates, expectations, plans and goals regarding Apache’s production, reserves, financings, acquisitions, exploration and exploitation prospects, energy prices, operating costs, and results of operations. Such forward-looking statements involve estimates, assumptions and uncertainties. No assurance can be given that Apache’s expectations or goals will be realized, and actual results may differ materially from those expressed in the forward-looking statements.
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After the Shale-Gas Multi-Stage Frac –Recovering
Valuable Operating Information on the Flowback
After the Shale-Gas Multi-Stage Frac –Recovering
Valuable Operating Information on the Flowback
George E. King17 November 2009
SPE Horizontal Well Stimulation Workshop
George E. King17 November 2009
SPE Horizontal Well Stimulation Workshop
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Why Bother with Flowback Analysis?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
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
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CORPORATIONCORPORATIONScope of the talkScope 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.
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.
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Primary & Secondary Frac DirectionsPrimary & 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.
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
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Not all the formation is the same…..Not all the formation is the same…..
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CORPORATIONCORPORATIONPore Micro-Fracture PassagesPore Micro-Fracture PassagesOpening natural fractures takes ~ 60% of the stress to break the rock.
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CORPORATIONCORPORATIONLook at the PiecesLook 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.
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.
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CORPORATIONCORPORATIONCapillary Forces – in fractures?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
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CORPORATIONCORPORATIONThreshold Pressure - 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.
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Moving liquids out of the fracturesMoving 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).
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T-2H – Pressure, Rate and Prop LoadingT-2H – Pressure, Rate and Prop Loading
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Balancing the pressure increase……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…….
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…….
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Xf (frac half ln)
Width of flow path
W/Xf
800 500 0.63
0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
100.0
Rate, bpm
& Loading, ppa
0 20 40 60 80 100 120 140 160 180 200 2200
1.0K
2.0K
3.0K
4.0K
5.0K
Elapsed Time, min.
Tandy 2-H Stg 7 RTM
Pre
ssur
es, p
si
BHP STP Qslr Loading
What’s the Fracture Complexity Index?What’s the Fracture Complexity Index?
FCI Reference SPE 115769, Cipolla, et.al.
FCI ratio is an indicator of spread.
Use to design well spacing on pads
No right or wrong
Target here was FCI > 1
500/800 = 0.63
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CORPORATIONCORPORATIONStarting Point…..Starting Point…..
> 20% of M-S events below pay
500 BWPDW/Xf = 0.3
Initial – high rate, tracers & micro-seismic. Follow up?Next – shorten the frac and make it wider…….
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Sequential Fracs, rate by M-S activity, Xf not yet modified by sand slugs
<5% of points below BarnettWell made ~ <50 bwpd
Next Step – Optimize the RateNext Step – Optimize the Rate
W/Xf = 1
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CORPORATIONCORPORATIONSingle Fracs – Reaching too Far?Single Fracs – Reaching too Far?
W/Xf = 0.7
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Zipper Frac - generally
good complex fracture
coverage.
Sequential Fracs – Barnett, Western Parker Co.Sequential Fracs – Barnett, Western Parker Co.
W/Xf = 2
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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 ET1 stage 2 1374 659 425 2.1 N 61 E S 39 E N 5 ET1 stage 3 1056 555 338 1.9 N 56 E N 83 E N 9 ET1 stage 4 1129 636 501 1.8 N 17 E S 48 E N 7 ET1 stage 5 1016 735 422 1.4 N 46 E S 38 E N 83 ET1 stage 6 1211 577 523 2.1 N 45 E S 39 E N 59 ET1 stage 7 755 571 509 1.3 N 53 E S 36 E S 89 ET1 stage 8 1025 549 364 1.9 N 42 E S 44 E N 78 E
T2 stage 1 1615 767 288 2.1 N 45 E S 43 E N 47 ET2 stage 2 1845 1014 306 1.8 N 45 E S 45 E N 89 ET2 stage 3 1175 913 340 1.3 N 45 E S 54 E S 74 ET2 stage 4 1228 763 448 1.6 N 51 E S 42 E N 67 ET2 stage 5 866 662 492 1.3 N 51 E S 64 E N 6 ET2 stage 6 855 668 499 1.3 N 36 E S 35 E N 9 ET2 stage 7 621 665 314 0.9 N 48 E S 52 E N 38 ET2 stage 8 1040 980 273 1.1 N 58 E S 51 E N 55 ET2 stage 9 1110 681 252 1.6 N 78 E S 40 E S 80 ET2 stage 10 971 677 254 1.4 N 45 E S 39 E N 43 E
Comparison of Frac Spread and Fracture Direction
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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;
41
598
0
1480
1935
2295
2620
3490
not g
iven
0
200
400
600
800
1000
1200
1400
Stage 1Stage 4
Stage 7
Stage 1
Stage 2
Stage 3
Stage 4
Stage 5
Stage 6
Stage 7
Stage 8
?
• which continue to flow with time;
• which stay open compared to prod
log.
Tracers – What broke down, what produced back?Tracers – What broke down, what produced back?
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Flowback Efficiencies & InterferenceFlowback Efficiencies & Interference
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Flowback Efficiencies & InterferenceFlowback Efficiencies & Interference
2nd MR = 2200 mcf/d
2nd MR = 2000 mcf/d
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Flowback Efficiencies and InterferenceFlowback Efficiencies and Interference
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Flowback Efficiencies and InterferenceFlowback Efficiencies and Interference
2nd MR = 1400 mcf/d
2nd MR = 800 mcf/d
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Traditional Flowback – vol. and salinityTraditional Flowback – vol. and salinity
0 5 10 15 20 250
10000
20000
30000
40000
50000
60000
70000
T-1H Salinity
T-2H Salinity
T-1H Cum water
T-2H Cum water
Days on Flowback
BB
Ls
wat
er o
r p
pm
Cl-
Now, why did one well produce 2.3 mmcf/d and
the other only 1 mmcf/d?
Sequential fraced pair of wells,
T-1H 3000 ft, 8 stages
T-2H 3200 ft 10 stages
750 ft apart.
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Zipper Frac - generally
good complex fracture
coverage.
Sequential Fracs – Barnett, Western Parker Co.Sequential Fracs – Barnett, Western Parker Co.
W/Xf = 2
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But, compare the rate of water recovery….But, compare the rate of water recovery….
0 5 10 15 20 250
10
20
30
40
50
60
70 T-1H Cumulative as % of load
T-2H Cumulative as % of load
Days on Flowback
% L
oad
Wat
er R
eco
vere
d
16 16.5 17 17.5 18 18.5 19 19.5 20 20.5 210
500
1000
1500
2000
2500
3000
3500
T-1H Gas mcf
T-2H Gas mcf
Days on Flowback
T1 recovered 40% of its load in 5 days
T2 recovered 20% of its load in 5 days
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CORPORATIONCORPORATIONWater Inflow From a Fault - PLTWater Inflow From a Fault - PLT
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80
00
’
75
00
’
70
00
’
65
00
’
60
00
’784878067764772276807638
Stage 1
748674447402736073187276
Stage 2
712470827040699869566914
Stage 3
676267206636667865946552
Stage 4
640063586316627462326190
Stage 5
603859965924591258705828
Stage 6
25% W75% W
10% Gas
45% Gas
10% Gas
10% Gas10% Gas5% Gas10% Gas
Stage 5
Production log & micro-
seismic – hard to see connection
w/o treating pressure
PLT and MicroseismicPLT and Microseismic
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CORPORATIONCORPORATIONOther ItemsOther 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)
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)
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CORPORATIONCORPORATIONConclusionsConclusions
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.
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.
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Questions?