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7/25/2019 Angsi-A Fracture Campaign Summary China Trip__SINOPEC, 2006
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Slide 1
Angsi-A Fracture CampaignSummary
China Trip- SINOPEC
18 – 19 May 2006
Slide 2
Main Objective
• Increase productivity of the wells
• Mitigate the detrimental effect of condensate drop out ongas recovery
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Slide 3
Angsi Overview
• 20 wells for hydraulic fracturing treatment
• Consist of K, L and I – formations
• Permeability ranges from 1 to 10 mD
• Porosity ranges from 15 – 20%
Slide 4
N
SOUTHCHINA
SEA
TAPIS PUMP
AnPG-A - Phase II
GUNTONG-D
ONSHORE SLUGCATCHER
P H A S E I - 3 2 "
, 1 6 6 k m G a s T
r u n k l i n e f r o m
A n g s i
P h
a s e I -
3 2 "
, 5 5 k
m g
a s
p i p
e l i n
e t o
A n g s i
SELIGI-A
2 4 " 8 5 k
m S e A
g a s
p i p
e l i n
e
AnDP-B - Phase II
1 6 " ,
4 8 k m
c r u
d e p i p e l i n
e
Legend
Southern Gas Pipeline
Oil pipeline
AnDP-C - Phase III
AnDP-E - Phase III
AnDR-A - Phase I
Angsi Field Location Map Angsi Field Location Map
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Slide 5
1st Campaign2nd Campaign3rd Campaign
Angs i-A
Platform
P R O B . G O T : - 2
4 4 6
L P G - 2 4 3 2
A-13 A-06
A-12 A-19
A-15
A-02
A-01
A-07
A-03R1L14A
A-05
2 4 6 0
L P G - 2 4 2 0
L P G - 2 4 5 3
P R O B .
G D T : -
- 2 4 5 6 . 5
4 .5 K M
S
2 4 4 0
2 4 2 0
2 4 6 0 2400
2 4 6 0
1
4
2
A-16
A-20
A-18
A-17
A-22
A-10 A-08R1
A-04
A-21
Slide 6
BackgroundBackground……Cross Sectional MapCross Sectional Map
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Slide 7
WESTWESTEASTEAST
3089 M3089 M--TD,TD, GpGp--MMMW 15.0 PPGMW 15.0 PPG
ANGSI ANGSI--11EPMIEPMI19741974
ANGSI ANGSI--22EPMIEPMI19941994
3,398 M3,398 M--TD,TD, GpGp--MM
MW 15.0 PPGMW 15.0 PPG
3,344 M3,344 M--TD,TD, GpGp--MM
MW 14.3 PPGMW 14.3 PPG
ANGSI ANGSI--33EPMIEPMI19951995
ANGSI ANGSI--44EPMIEPMI19951995
2,660 M2,660 M--TD ,TD , GpGp--KKMW 11.2 PPGMW 11.2 PPG
2,232 M2,232 M--TD,TD, GpGp--I/JI/J
MW 10.1 PPGMW 10.1 PPG
ANGSI ANGSI--66CarigaliCarigali
19971997
ANGSI ANGSI--55CarigaliCarigali
19971997
2,230 M2,230 M--TD,TD, GpGp--I/JI/J
MW 10.1 PPGMW 10.1 PPG
ANGSI ANGSI-- A ADRILLINGDRILLING--
RISERRISERPLATFORMPLATFORM(ANDR(ANDR-- A) A)
ANGSI ANGSI--BBDRILLINGDRILLING
PLATFORMPLATFORM(ANDP(ANDP--B)B)
ANGSI ANGSI--77CarigaliCarigali
20002000
2133 M2133 M--TD,TD, GpGp--I/JI/J
MW 10 PPGMW 10 PPG
•• Production Tests:Production Tests:-- M (AngsiM (Angsi--2 & 3): Neglig ible flow, Perm ~ 0.022 & 3): Neglig ible flow, Perm ~ 0.02--0.0050.005 mdmd-- L (AngsiL (Angsi--2): Flowing < 0.5 MMSCFD, Perm ~ 0.022): Flowing < 0.5 MMSCFD, Perm ~ 0.02--0.0050.005 mdmd-- K (AngsiK (Angsi--2): Flowing < 4 MMSCFD, Perm ~ 0.72): Flowing < 4 MMSCFD, Perm ~ 0.7 mdmd
BackgroundBackground……Exploration WellsExploration Wells
•• Angs i Angs i--4 Exploration Well (K4 Exploration Well (K--sstsst), hydraulically fractured/tested:), hydraulically fractured/tested:-- PrePre--frac production yield 4frac production yield 4--5 MMSCFD.5 MMSCFD.-- Relatively shor t frac length, +/Relatively shor t frac length, +/-- 160 ft. maximum.160 ft. maximum.-- PostPost--frac production: 4frac production: 4--5 Fold Of Increase (times), avg.18 MMSCFD.5 Fold Of Increase (times), avg.18 MMSCFD.
Slide 8
FRAC EQPT SPREAD150 Lifts
WORLD LARGEST OFFSHORE PLATFORM FRAC OPN
A-2 K-25L PROD TEST
COIL TUBING UNIT5 Lifts
A-07 Compo site
2375
2400
2425
2450
2475
2500
2525
2550
2575
2600
2625
2650
Shale
K-25U sand
K-25L sand
K-30sand
Mudstone
Rocktype5 00 0 1 00 0 0Stress (psi)
25 50 75 100 125 150 175 200 225 250
2375
2400
2425
2450
2475
2500
2525
2550
2575
2600
2625
0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10
Proppant Concentration(lb/ft²)
K-30/35 206 ft
K-25L 182 ft
K-25U 164 ft
K-22 148 ft
Half-Length
A-07 Compo site
2375
2400
2425
2450
2475
2500
2525
2550
2575
2600
2625
2650
Shale
K-25U sand
K-25L sand
K-30sand
Mudstone
Rocktype5 00 0 1 00 0 0Stress (psi)
25 50 75 100 125 150 175 200 225 250
2375
2400
2425
2450
2475
2500
2525
2550
2575
2600
2625
0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10
Proppant Concentration(lb/ft²)
K-30/35 206 ft
K-25L 182 ft
K-25U 164 ft
K-22 148 ft
Half-Length
MULTI-STAGE FRAC ZONES
K-22
K-25U
K-25L
K-30/35
Per Well :
• Proppant Volume- 200 ~ 400 Tons
• Frac Fluid Volume- 6000 ~ 10,000bbl s
• Pumping Rate- 40 BPM
• Frac Job Pressure- 9,000 psi surface- 13,000 psi downhole
• Frac Zone Isolation- Sand Plugs
Design & Execution...
0 200 400 600 800 1000
K-30
K-25L
K-25U
K-20/22
I-1
I-85
MAX
MIN
TIP-TO-TIP FRAC LENGTH (ft)
Treatment Size/Length Optimizedbased on :
- Net Pay Thickness- Perm- Fracture Conductivity- Proximity to GWC- Reduce risk of screen-out- Height growth/zonal coverage- Maximum Equipment Capacity
TD 3000 -6000 m MD
‘S’ WELL PROFILE - vertical across K sands
7” Liner
9-5/8” Csg
13-3/8” Csg
18-5/8” Csg
45~79 deg
Reach 2 ~ 5 km
< 5 degvertical fractures
flow connectivity
vertical wellbore
K-sst
I & J-sst
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Slide 9
•26" @ 600 ft-TVD
•18-5/8" @ 2000 ft-TVD
•(Contingency)•13-3/8" @ 3600 ft-TVD
•I, J - sands
•9-5/8" @ 7200 ft-TVD
•K - sands•3-1/2"
•7" L iner @ 8700 ft-TVD
•3-1/2"
Casing Program/Well Profile
• 'S' shape drilling trajectory
• - 9,400-20,000 ft MD
• - <77° max well inclination
•K-sandsto befrac’d
Slide 10
Platform Layout...Platform Layout...
Supply VesselSupply Vessel
•• To offload fracTo offload frac eqpteqpt && matmat ’’ lslsusing the platform crane.using the platform crane.
H H H H
MooringMooringLinesLines
T E N D E R
T E N D E R
Platform Flare BoomPlatform Flare Boom
TemporaryTemporaryBurnerBurner
Boom* for Boom* for
WellWell FlowbackFlowback //Production TestingProduction Testing
PipelinesPipelines
H H H H
FutureFuturePipelinePipeline
Inter Inter --Platform BridgePlatform Bridge
**
Platform CranePlatform Crane
Drilling RigDrilling Rig
Area f or Fr acturi ng , Nit rogen/Well Test Equi pmen t Area f or Fr acturi ng , Nit rogen/Well Test Equi pment
Area f or Coi led Tub in g/Well Test Area f or Coi led Tub in g/Well TestEquipmentEquipment
Tender Barge (T6):Tender Barge (T6):
•• Filtration and Storage of frac water .Filtration and Storage of frac water .
•• Transferring frac water to ANDRTransferring frac water to ANDR-- A A
•• Storage for fracStorage for fracmaterials/chemicals.materials/chemicals.
•• Accommod ations Accommod ations
Angsi Dr il ling Riser Angs i Dril ling RiserPlatformPlatform -- A(ANDR A(ANDR-- A) A)
Tender CraneTender Crane
ANGSI ANGSI-- A A Central ProcessingCentral Processing
Platform (ANPGPlatform (ANPG-- A) A)
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Slide 11
Fluid & Proppant
• PrimeFRAC Fluid – Temperature activated, zirconium-crosslinked water based fl uids
– Design for low polymer application for mini mum gel damage
– Compatible with Angsi fo rmation temperature – 300 F
– Recipe designed to be stable for about 1 ½ hour in 320 F environment
- still having viscosity >200 cp
• 16/20 Carbolite Opticoat Resin Coated ISP – Resin coated for proppant flowback control
– Provide high conductivity
– hold 5,000 to 14,000 psi press ure
Slide 12
Design Consideration• Rock Mechanic:
• Stress prof ile
Previous DataFRAC* (Frac on 1995) give estimate of sand frac gradient 0.71 – 0.72
psi/ft. ELOT test g ive estimate of shale frac gradient 0.81 – 0.85 psi/ft. Linearinterpolation of gamma ray reading based on the value above to build the stressprofile
• Young modulusTri-axial test give sand young modulus of 2.5E+6 to 3.0E+6 psi and shale young
modulus of 1.8E+6 psi.
• Poisson ratio
Tri-axial test estimate Poisson ratio range from 0.13 to 0.06
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Slide 13
Design Consideration
• Pumping Parameter Pumping rate at 40 bpm wil l maintain the frac from unwanted heightgrowth and provide the higher net presssure to create suffic ientconductivity
PAD Volume ratio (PAD Volume/total treatment volume) of 35% issuffi cient to create design half length and Tip Screen Out effectbased on assumed leak off coefficient
Proppant ramping from 1 to 8 PPA will provide sufficient proppantconcentration (lb/sqft) and will provide good conductivity.
Slide 14
Fracturing Equipment
• 8 Frac Pumps ( around 1200 HHP each)
• 1 Pod Blender
• 1 PCM – 150 bbls
• 4 Frac Tanks – 4 x 250 bbls & 1 Header Tank – 1 x
250 bbls• 4 Liquid Additives Tank
• 4 Proppant Silo (each silo 64000 lbs capacity)
• 1 Sand Belt Conveyor
• 1 FracCAT container (for monitor ing and acquisi tion)
• 1 Lab container (for QA/QC)
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Angsi-A: T-6, Drilling Platform, Production PlatformFlowing A-22L (13-July-03)
Slide 16
Fracturing SequenceFracturing Sequence……Current operationCurrent operation
•• Perforate#Perforate#11 (4(4--1/21/2”” WCP)/WCP)/RIH FracRIH Frac--stringstring/Mini/Mini--frac/Main Stage/frac/Main Stage/Sand plugSand plug
•• Perforate#Perforate#22 (2(2--1/81/8”” ThruThru’’ Tubing Gun)/MiniTubing Gun)/Mini--frac/Main Stage/frac/Main Stage/Sand plugSand plug
•• Pickup Frac BHA :Pickup Frac BHA : To frac I or J sand (if any)To frac I or J sand (if any)•• RIH Frac BHA/cleanRIH Frac BHA/clean--out sand plugs/Kill wellout sand plugs/Kill well•• POOH Frac BHAPOOH Frac BHA/Complete well/Complete well
……withoutwithoutPacker Packer
No TestingNo Testing(2nd well(2nd wellonwards)onwards)
•• Perforate#Perforate#33 (2(2--1/81/8”” ThruThru’’ Tubing Gun)/MiniTubing Gun)/Mini--frac/Main Stage/frac/Main Stage/Sand plugSand plug
I/J SandsI/J Sands
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Slide 17
Treatment Statist ics• 596 Days from First to Last Fracture Treatment (7-Dec-01 to
26-Jul-03) 85 Weeks or 20 Months• 20 Different Wellbores
• 79 Fracture Treatments – 67 K-Sands
• 18 K-28/30/35
• 17 K-25L
• 12 K-25U
• 20 K-20/22
– 8 I-Sands
– 4 L-Sands• 13,800,000 Pounds of Proppant (70 Boat Loads)
• 217,500 Barrels of Water (110 Boat Loads)
Slide 18
0
50000
100000
150000
200000
250000
300000
350000
A - 0 2
A - 0 4
A - 0 6
A - 0 7
A - 0 3 R
1 A - 0 1
A - 0 5
A - 0 8 R
1 A - 1 0
A - 1 2
A - 1 3
A - 1 5
A - 1 6
A - 1 7
A - 2 1
A - 2 0
A - 2 2
A - 1 9
A - 1 8
Well Sequenc e
A v e r a g e P r o p p a
n t V o l u m e p e r W e l l ( l b s )
0
10
20
30
40
50
60
70
80
90
100
P a d S i z e
( % )
Design Volume
Actual Volume
Pad Size
Avera ge o f al l
K-Sands Stages per Well
Proppant Volume Per Well
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Slide 19
0
50
100
150
200
250
300
350
400
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
A
v e r a g e F r a c t u r e H a l f - L e n g t h ( f t )
0
2
4
6
8
10
12
14
16
P r o p p an t C on c .i nP a y Z on e ( l b / s qf t )
Averag e of al lK-Sands Stages per Well
A - 0 2
A - 0 4
A - 0 6
A - 0 7
A - 0 3 R 1
A - 0 1
A - 0 5
A - 0 8 R 1
A - 1 0
A - 1 2
A - 1 3
A - 1 5
A - 1 6
A - 1 7
A - 2 1
A - 2 0
A - 2 2
A - 1 9
A - 1 8
Average Frac Half-Length
Slide 20
Stimulation Time Per Well (days)
0
5
10
15
20
25
30
A - 0 2
A - 0 4
A - 0 6
A - 0 7
A - 0 3
R 1
A - 0 1
A - 0 5
A - 0 8
R 1
A - 1 0
A - 1 2
A - 1 3
A - 1 5
A - 1 6
A - 1 7
A - 2 1
A - 2 0
A - 2 2
A - 1 9
A - 1 8
S t i m u l a
t i o n T i m e ( d a y s )
A-15
L-Sands
A-18
L-Sands
3.3 Days Average
Not Including L-SandsStarted "Live" Annulus
(No Packer)
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Slide 21
Stimulation Time Per Stage (days/stage)
0
1
2
3
4
5
6
7
A - 0 2
A - 0 4
A - 0 6
A - 0 7
A - 0 3 R
1 A - 0 1
A - 0 5
A - 0 8 R
1 A - 1 0
A - 1 2
A - 1 3
A - 1 5
A - 1 6
A - 1 7
A - 2 1
A - 2 0
A - 2 2
A - 1 9
A - 1 8
S t i m u l a t i o n T i m e p e r S t a g e ( d a y / s t a g e )
0
1
2
3
4
5
6
7
N o of S t a g e s P er W el l
Slide 22
Results• 34% of Gas Production from K-Sands
– 104 MMscf/d out of 303 MMscf/d (July 2003)
• 22% of Liquids (Oil & Condensate) from K-Sands
– 14,000 bopd out of 67,000 bodp (July 2003)
• $ 660,000 USD Cash Flow From K-Sands
– $3.00 per Mscf
– $25.00 per bb l
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Slide 23
“ Typical” Mini-Frac Procedures
• Pump 100 bbls Linear Gel or 2% KCl at 30 bpm
• Shut-Down for 15 to 30 Minutes
– Analyze Pressure Decl ine
• Pump 250 bbls XL Gel & Displace to Top Perf with Linear Gel (AverageFlush 175 bbls)
• Perform Rate Step-Down Test
– Analyze Step-Down Data
• Shut-Down for 30 to 90 Minutes
– Analyze Pressure Decl ine
Slide 24
Mini-Frac Analysis Procedure(performed in “ real-time” )
• Review Injection History
• Determine Instantaneous Shut-In Pressure (ISIP)
• Analyze G-Funct ion Graph
– Closure Pressure, Net Pressure, Fluid Effic iency, Pressure DependentLeakoff, and Height Recession
• Analysis Log-Log Graph
– Closure Pressure, Net Pressure, Fluid Effic iency• Analyze Square-Root-of-Time Graph
– Closure Pressure, Net Pressure, Fluid Effic iency
• Review Results for A ll Analysis Techniques and Determine ClosurePressure & Fluid Efficiency
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Slide 25
BackgroundBackground…….Conceptual to Implementation.Conceptual to Implementation
(cont.)(cont.)
Conceptual:Conceptual: 16/30 Intermediate Strength16/30 Intermediate Strength ProppantProppant (ISP)(ISP)Implement:Implement: 16/20 ISP16/20 ISPBetter conductiv ity, avoidBetter conductivi ty, avoid proppant flowbackproppant flowback
•• ProppantProppant Size:Size:
Conceptual:Conceptual: sand plug + mechanical bridge plugssand plug + mechanical bridge plugsImplement:Implement: sand plugssand plugsSaves rig timeSaves rig time
•• Zonal Isolation:Zonal Isolation:
Conceptual:Conceptual: Coil tub ing (CT) with 16/30 + 20/40 sandCoil tub ing (CT) with 16/30 + 20/40 sandImplement:Implement: mixmix ‘‘on the flyon the fly’’ with breakers (16/20+100mesh)with breakers (16/20+100mesh)Saves rig time, better pressure integrity with 100 meshSaves rig time, better pressure integrity with 100 mesh
•• Sand Plug Placement Method:Sand Plug Placement Method:
Slide 26
BackgroundBackground…….Conceptual to Implementation.Conceptual to Implementation
•• Perforation Guns:Perforation Guns:
Conceptual:Conceptual: hydraulic + mechanical retrievable packer hydraulic + mechanical retrievable packer
Implement:Implement: ‘‘ live annuluslive annulus’’ i.e.i.e. packerlesspackerless (2nd well onwards)(2nd well onwards) Avoid packer leaks/stuck, saves rig t ime Avoid packer leaks/stuck, saves rig t ime
•• Downhole Equipment (packer):Downhole Equipment (packer):
Conceptual:Conceptual: CT + ThruCT + Thru’’ tubing wireline guns (1tubing wireline guns (1--11/1611/16”” ))
Saves rig time on pipe trippingSaves rig time on pipe tripping
Implement:Implement: Wireline Casing guns + ThruWireline Casing guns + Thru ’’ tubing (2tubing (2--1/81/8”” ) +) +‘‘ tractor tractor ’’ for wells > 70 deg.for wells > 70 deg.
Conceptual:Conceptual: CT and NitrogenCT and NitrogenImplement:Implement: ‘‘gas from adjacent wells (2nd well onwards)gas from adjacent wells (2nd well onwards)Saves rig time and costSaves rig time and cost
•• Well Unloading:Well Unloading:
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Slide 27
Key Lessons Learnt...Key Lessons Learnt...
• Batch Drill sui table for Batch Drill sui table for fracingfracing::
sufficient time for better f rac design (actual formations).sufficient time for better f rac design (actual formations).
•• ‘‘Live AnnulusLive Annulus”” Fracturing Technique:Fracturing Technique:
reduces rig time and overall NPT (simpler operations).reduces rig time and overall NPT (simpler operations).
•• PostPost--frac testing after completion through productionfrac testing after completion through productionsystem:system:
significantly saves rig time.significantly saves rig time.
•• Use of Resin CoatedUse of Resin Coated ProppantProppant::successful in mitigatingsuccessful in mitigating proppant flowbackproppant flowback at high rates.at high rates.
•• Extensive planning on equipment design, inspection,Extensive planning on equipment design, inspection,
onshore preonshore pre--commissioning and maintenance:commissioning and maintenance:
resulted in negligible equipment downtime.resulted in negligible equipment downtime.
Slide 28
Continuous Performance Improvement ...Continuous Performance Improvement ...
• Utilizing wirelineUtilizing wireline ““ tractor tractor ”” perforation technique for wellperforation technique for well
deviation > 70 deg:deviation > 70 deg:
saves rig time on pipe tripping for TCP perforation.saves rig time on pipe tripping for TCP perforation.
• Conducted fracturing the poorerConducted fracturing the poorer ““ II-- reservoirsreservoirs”” ::
To improve productivi ty.To improve productivi ty.
• Understanding actual formation stresses and fractureUnderstanding actual formation stresses and fracture
height growth:height growth:
optimize the frac design, save cost.optimize the frac design, save cost.
• Managing space constraint due to logistics, liquidManaging space constraint due to logistics, liquid
storage, supply vessels,storage, supply vessels, personnelspersonnels on board (POB).on board (POB).Have simpler, safe and cost effective operations.Have simpler, safe and cost effective operations.
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Slide 29
TOPICTOPIC PrePre--Drill DesignDrill Design Best PracticeBest Practice Do DifferentDo Different
GeomechanicalGeomechanical Reservoir CharacterizationReservoir CharacterizationPressure fall-off,E-LOT at csgshoe, DSI logs
DSI in appraisal well was used to estimatestress profiles & rock properties, calibratedwith core triaxial mech properties, leak-off testin shales at csg shoe & mini-frac data.
- Run in correctmode for rockmechanicalproperties
- Run one DSI login each faultblock & calibrateDSI logs
Post-fracevaluation
Do post-frac diagnostic& integrate withfracture & reservoirmodelling to analyse
resulting fracture.
Diagnostics for post-frac evaluation is criticalto improve futu re designs. Use wirelinegauges for real-time BHP, measurementsduring diagnostic injection, BHP memory
gauges (with wireline interrogation ),temperature logs, radioactive tracer logs, andflow test (to evaluate frac performance).
Perform diagnostic(Injection test) toanalyze in-situformation stresses,barrier competency &fluid leak-off, and dobase-design. Data onin-situ stresses can beused with logs duringdrilling to refine stressprofile.
Full density logs Full density log in appraisal well used toestimate overburden/vertical stress. Stresscontrast btw min sand stress & vertical stresssuggest frac orientation is vertical.
UBI logs Borehole image log is not a primary indicatorof frac azimuth, but was used to show nowellbore breakout/ellipci ty in K-sand. (Notcritical for Angsi due to its large well spacingand modest frac length)
Best Practices & Lesson Learnt...Best Practices & Lesson Learnt...
Slide 30
TOPICTOPIC PrePre--Drill DesignDrill Design Best PracticeBest Practice Do DifferentDo Different
FracFrac FluidsFluidsGelled Frac FluidSystemPrimeFrac(CMHPG-Zir) vsothers
Guar or its derivatives(HPG/CHMPG) with delayed cross-linking of gel structure
Freshwater Zirconium crosslinked(CHMPG-Zir) with 35lb/kgalpolymer loading provided thedesired fluid viscosity &minimized frac conductivityimpairment (concern on scalingetc)
Freshwater vsseawater
Use freshwater filtered to 2 miconswith 2% KCl by weight of water.Seawater can minimize logist icissue & less expensive, but wasnot selected due to its lower
viscosity (or higher polymerconcentration required), and fluidstability issue at high temperature.
2% KCl was used to stabilizeformation c lays.Tender ballast andlarger capacity boat critical tofresh water deliv ery. Had alternatefluid (flexability) - 55lb/kgal
seatwater based fluid system(same materials as freshwatersystem) as backup in casefreshwater supply interrupted.
Review fracturefluid with blendedwater (fresh andseawater)
Fluid rheology /lab testing
Conducted extensive lab rheology(Fann-50) and retainedconductivity test.
CrossLink Increased crosslink delay agenton long er reach wells
Fluid formulationshould considerspecific wellbores(crosslink time onextended reachwells)
Best Practices & Lesson LearntBest Practices & Lesson Learnt……
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Slide 31
TOPICTOPIC PrePre--Drill DesignDrill Design Best PracticeBest Practice Do DifferentDo Different
ProppantProppant16/20 resin coatedCarbolite (premiumlightweight ceramicproppants)
16/30 Mesh IntermediateStrength Proppant (ISP)
Curable resin coatedproppant (RCP) was requireddue to high gas productionrates & inability to handleproppant flow-back. Workwith production to minimizecyclic loading of proppant byimplementing bean-upprocedure for each well.
Surface facilitiesshould b e able tohandle some solidsproduction (sand filter,cyclone, strainer, etc.)
20/40 & 100 meshsand
Having different proppanttypes/sizes on locationallowed flexibility in proppantslug design to reduce nearwellbore pressure
Proppant Quantity& Concentration
400k lbs for 600 ft fracheight/length ( K-22, K-25,K28/30 in a s ingle stage jo b). 1
to 8 ppg mixed in stages withgelled frac fluid
As per j ob
Best Practices & Lesson Learnt...Best Practices & Lesson Learnt...
Slide 32
TOPICTOPIC PrePre--Drill DesignDrill Design Best PracticeBest Practice Do DifferentDo Different
Formation Damage TestingFormation Damage TestingCore flow tests (I &K-sands) andCompatibility /emulsion
Conducted formationdamage & fluid compatibilitytests using K-sand core,reservoir, completion &stimulation fluids, addingfree-ions/fines to simulateactual field conditions.
- Obtain more coresamples (ran out ofcore)
- Obtain formationwater sample (used labsimulated sample fortesting)
Work stringWork string4-1/2", 15.1lb/ft, P-110, PH6 tubing
- Industrial best practice - 4-1/2"tubing frac string used inside 7"liner in deviated wellbore
Use DP instead of regularwork string (makes-upquicker)
5" & 5-1/2"Drillpipe
"Live Annulus" workstring -use of 5" DP in 9-5/8" casing ,and 4-1/2" DP in 7" linerwitho ut packer. Proven ascost-saving, simpler stringwith fewer problems & littledown-time
Start with drillpipe?Condition of DP afterfracture treatments?
Best Practices & Lesson Learnt...Best Practices & Lesson Learnt...
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Slide 33
TOPICTOPIC PrePre--Drill DesignDrill Design Best PracticeBest Practice Do DifferentDo Different
PerforationPerforation2-1/8" & 4-1/2" perfgun phasing /charges/decentralization
90-120 deg phasing, 2-6 spf,average perf diameter 0.21"/shot
-Zero phasing not a problem
- Limit p erf interval (6 meters)
- No problem running down 2-1/8” guns up to 70 deg(pumping down with rollers).
- Overbalance perforating (4000psi) helped breakdowns
Start with Safety perfsystem (no need forradio silence)
Tagging sandplugs
Have at least 5 meters frombottom perf to top of sand plug
When changingfrom multiple stageto single stage job
Use limited entry perf technique "Lim ited entry" per hasadvantage over "ball sealers"technique for h igh temp (>300deg F).
LoggingLoggingGamma ray/perfguns
Alw ays run GammaRay with perf guns
Best Practices & Lesson Learnt...Best Practices & Lesson Learnt...
Slide 34
TOPICTOPIC PrePre--DrillDrillDesignDesign
Best PracticeBest Practice Do DifferentDo Different
Completion EquipmentCompletion EquipmentHi-Performancepacker, PTV,DGA, TFTV,BPCV, Linc
Use field proven hardware with adocumented track record andpersonnel experienced withhardware (HPP)
Flex Packer - Hanging weight below packer workedwell on the A-15 L-Sand
-Hanging workstring in tubing hangaradded extra level of protectio n (A-18 L-Sand)
-Set isolation packer on top of L-Sandbefore moving up to K-sand (A018)
-Consider having packer in workstring(unset) so it could be set if required tobreakdown, saving a trip
Coiled Tubing & NitrogenCoiled Tubing & NitrogenCleanup/Logistics
- Avoid using nitrogen to clean outwell (mess up plugs or flow backsand plugs requiring pre-settingsand plugs)
- Review logistics of nitrogenstorage (on location/delivery/supply)
- Larger ID CTU for washing 7” liner.
- Locate CTU to reach ALL slo ts
Best Practices & Lesson Learnt...Best Practices & Lesson Learnt...
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Slide 35
TOPICTOPIC PrePre--Drill DesignDrill Design Best PracticeBest Practice Do DifferentDo Different
Surface EquipmentSurface EquipmentTreating i ron,measurementequipment (flowmeters, densitymeters, etc.)
- Max Surface TreatingPressure of 7000 psi at 35bpm
- Flexibility in treating ironis required to allowexpansion caused by flowvelocity & heat. Minimizeno. of bend/sharp turns toreduce erosion risk due toabrasive flow.
- Max Surface TreatingPressure up to 10,000 psiat 40 bpm
- Consider need for high pressuredensometer with low pressuredensometer
- Consider 4” high pressuretreating line (compared to two 3 inlines)
Well test &coiled tubing
- Eliminated use of h eaterin testing equipment
- Alw ays use targ etelbows when flowingafter fracture treatment
- 4" water supply lineworked well (no valve at
the end)
- Position CTU relative to V-door,hi-line, and well sl ot position
- Have two sacrifical lines (one toeach flair)
- Capture proppant from sand filterto measure volume of proppant
- Consider permanent flow lines
for extended testing programs (nohammer unions)
Flow head, frachead, E-Z valve
Valving must be properlyinstalled to avoidbackflow, isolateequipment sectors.
- Minimal erosion on fl owhead and frac head (14million lbs of proppant)
- Review wellhead/frac valveconfiguration during planningphase (reduce rig-up time andheight)
- Consider backup flowhead onlocation (or located close by)
Best Practices & Lesson Learnt...Best Practices & Lesson Learnt...
Slide 36
TOPICTOPIC PrePre--Drill DesignDrill Design Best PracticeBest Practice Do DifferentDo Different
Surface Equipment (cont.)Surface Equipment (cont.)Safety reliefdevices (GORV,pop-offs, pumptrips, annulustrips)
- Set GORV below maxpressure to account foractivation time
- Pump kickout based onboth annulus and tubingpressures
Emergency shut-down on wellheadduring cleanup via productionwellhead (eliminate manuallyclosing valve on wellhead)
BOPs Tubing ram closed tocreate pressurizedannulus.Install automatedoverpressure reliefmechanism (lined up toannulus).Need heavy dut ytubing ram to encounterrepeated tubin gmovement.
Best Practices & Lesson Learnt...Best Practices & Lesson Learnt...
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Slide 37
TOPICTOPIC PrePre--Drill DesignDrill Design Best PracticeBest Practice Do DifferentDo Different
Fracture Treatment OptimizationFracture Treatment OptimizationMissing data(productionlogs, well tests,etc.)
Consider PBU, additionalsingle zone testing,production logs early inthe program
Proppantflowback
Operate wells as per procedure tominimize proppant flowback
- Review all materials(Resin Coating / PropNet/ Sand Wedge / Flex Prop)
- Compare initial wellcleanup information tosensitivity of sandproduction on w ells thatmake proppant, also fracdata and reservoir fluidproperties
Sand plug zoneisolation
Either use sand plugs ordrillable bridge plugs for
zonal isolation in deviatedwell. Bridge plugshowever need CTU &good debris clean-out toavoid sticking problemsduring completions. Sanddumping only works invertical well.
- Sand plug is the preferredmethod over setting bridgeplugs
for multiple zones- Sand plugs should be set on thefly
- Use 100 mesh on top
- 5 meter minimum height aboveperfs
Best Practices & Lesson Learnt...Best Practices & Lesson Learnt...
Slide 38
TOPICTOPIC PrePre--DrillDrill
DesignDesignBest PracticeBest Practice Do DifferentDo Different
Fracture Treatment Optimization (cont)Fracture Treatment Optimization (cont)Fluid mixing,preparation, & transfer
Base fluid (2% KCl, additives) was mixedon tender barge and transferred before andduring each treatment. Combinatio n offluid storage on patform & fluid transferduring treatments allowed treatments aslarge as 2500 bbls of clean fluid.
Physically clean commonmanifolds (circulating notsufficient)
Mini-fracs and stepdown rate tests
Highly recommended
Clean-out after
fracture treatment
Gun debris and 100 mesh was difficul t to
wash-out (some wells)
Flow-back & clean-up(e.g., bean-upprocedures)
Clean-up tim e limited after fracturetreatment by rig moving to next slot
-Better job of clean-upbefore handover toproduction (minimizechlorides contact withtubing and productionfacilities)
-Speed up flow line rig-up(reduce time from frac toflowback)
- Do better job ofsimultaneous operations(continuous flowing ofwell for clean-up)
Best Practices & Lesson Learnt...Best Practices & Lesson Learnt...
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Slide 39
TOPICTOPIC PrePre--Drill DesignDrill Design Best PracticeBest Practice Do DifferentDo Different
Wellbore ConfigurationWellbore ConfigurationTrajectory S shape profile. Sufficient
rathole needed below lowermostfrac zone to allow TD logging,room for settling sediments,crushed fines, and residualproppants.
S shape (up to 20000 ft MD and75 deg) to minimize fraccomplexity (multiple frac &tortuosity)
Casing Ensure good primary cementingbtw casing & formation(precautions against highpressure pumping acrossperforation)
Consider designingwellbore (casing andsurface equipment) for liveannulus
Packers,accessories, etc.
Use hydraulic retrievable packer& slip joints.
Pressurized
annulus (tocounteract tubingmovement &detecttubing/packerleaks)
Use overbalanced brine ( KCl for
up to 10.9 ppg, and CaCl2 forabove 11.0 ppg Angsi K wells).
Best Practices & Lesson Learnt...Best Practices & Lesson Learnt...
A-020 300Gamma ...
0 40Resistivit...
2 3Bulk Den...
0 0.5Neutron ...
8000
8100
8200
8300
8400
8500
8600
8700
8800
Shale
K-20/...
Muds...
Muds...
Siltst...
K-25...
Muds...
Sand...
Muds...
R o. .. S tr .. .
100 200 300 400 500 600 700 800
0 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.0
Proppant Concentration (lb/ft²)
Treatment Design A-02
87 Klbs
139 Klbs
106 Klbs
27 Klbs
Total 359 Klbs
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Treatment Design A-18 A-18 K-sand Composite Geometry
7800
7900
8000
8100
8200
8300
8400
8500
8600
8700
A... R... N... GR
D e p t h ,
T V D ( f t )
Shale
K-25U sand
K-25L sand
K-25L sand
K-30 sand
Mudstone
L shale
Rocktype
D e p t h ,
T V D ( f t )
100 200 300 400 500
7800
7900
8000
8100
8200
8300
8400
8500
8600
8700
0 0.20 0.40 0.60 0.80 1.0
Proppant Concentration (lb/ft²)
Width Profil...
0
7800
7900
8000
8100
8200
8300
8400
8500
8600
8700
289 Klbs
153 Klbs
301 Klbs
295 Klbs
Total 1038 Klbs
Slide 42
Back Up
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Slide 43
Lesson Learned
Fluid QA/QC – Fluid Contamination during transferring from T-6 toPlatform
The Ca++ is higher than the specification that reduce fluid performance. Flush the
line before transferring the base fluid.
Live Annulus Frac Vs Packer Reduce the execution time significantly
Spotting Sand Plug (On the fly -part of flush ,Cut X-linker, Increase
the breaker concentration).
Reduce time to spot sand plug using CTU and No bridging issue.
Reduce The Gel Loading
Stop pumping PrimeFRAC 55 and plan to pump PrimeFRAC 40.
Increase the sand concentration and Reduce the Pad volume
Improve the frac conductivity
Wellhead Deck December 2001
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Wellhead Deck July 2003
Slide 46
ECONOMICS ...
ECONOMIC EVALUATION K-SAND STIMULATIONTYPE WELL
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
0 10 20 30 40 50 60
Production Time, days
R e v e n u
e ,
$ U S D
27 Days to Payout
37 Days to Payout
Total Cash Flow
Gas Cash Flow
Condensate Cash Flow
$1,120,000
Stimulation Cost
(incl. Rig Time)
Cash Flow Based on
20 MMscf/day (Gas Rate)
1040 bbl/day (Condensate Rate)
$1.50 per MMscf of Gas
$10 per bbl o f Condensate
Excl. well clean-up period
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Slide 47
•• PERFORATION CRITERIAPERFORATION CRITERIA
•• SPFSPF : 2: 2 -- 6 spf 6 spf •• DIAMETERDIAMETER : 0.2: 0.2”” -- 0.40.4””
•• PHASINGPHASING : 90: 90°° –– 120120°° / / 180180°°
•• PERFORATION TECHNIQUEPERFORATION TECHNIQUE
•• Thru Casing : Wireline/TCP (orientation possible)Thru Casing : Wireline/TCP (orientation possible)
•• Thru Tubing : Wireline/CT (nonThru Tubing : Wireline/CT (non--orientation)orientation)
•• CURRENT PERFORATION GUNS UTILIZESCURRENT PERFORATION GUNS UTILIZES
•• 1st Stage (bottom most stage)1st Stage (bottom most stage)
•• Gun TypeGun Type : 4: 4--1/21/2” ” HMX PJ4505 WCP HMX PJ4505 WCP
•• Diameter Diameter : 0.41: 0.41” ” (average)(average)
•• SPFSPF : 5: 5
•• Phasing Phasing : 72: 72°°
•• Subsequent Stages (ThruSubsequent Stages (Thru’’ Tubing Wireline Guns)Tubing Wireline Guns)•• Gun TypeGun Type : 2: 2--1/81/8” ” Enerjet HMX BH Enerjet HMX BH
•• Diameter Diameter : 0.45: 0.45” ” (average)(average)
•• SPFSPF : 4: 4
•• PHASING PHASING : 0: 0°°
Perforation Strategy...Perforation Strategy...
Slide 48
Angsi A-07 K-25U Mini-Frac
Injection SummaryMeas'd Btmh (psi) Slurry Flow Rate (bpm)
40.00 50.00 60.00 70.00 80.00 90.00 0
1600
3200
4800
6400
8000
0.0
25.0
50.0
75.0
100.0
125.0
1:Start Minifrac (44.1 min)
2:Stop Minifrac (56.2 min)
3:End of Shut-in (86.2 min)
Total injection test volume: 443.7 bbls
Average slurry rate: 36.4 bpm
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Slide 49
Angsi A-07 K-25U Mini-Frac AnalysisG-function Graph
Meas'd Btmh (psi) (d/dG) Surf Press [Ann] (psi)(G·d/dG) Surf Press [Ann] (psi)
0.000 0.540 1.080 1.620 2.160 2.700 4500
4900
5300
5700
6100
6500
0
800
1600
2400
3200
4000
0
400
800
1200
1600
2000
BH Closure Pressure: 5613 psi
Closure Stress Gradient: 0.693 psi/ft
Closure Time: 3.1 min
Pump Time: 12.2 min
Implied Slurry Efficiency: 17.1 %
Estimated Net Pressure: 632 psi
Slide 50
Angsi A-07 K-25U Mini-Frac Analysis
Log-Log GraphDelta Pressure (psi) (d/dt) Delta Pressure (psi)
0.100 1.000 10.000 100.00 10
100
1000
10000
BH Closure Pressure: 5604 psi
Closure Stress Gradient: 0.692 psi/ft
Closure Time: 3.2 min
Pump Time: 12.2 min
Implied Slurry Efficiency: 17.5 %
Estimated Net Pressure: 640 psi
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Slide 51
Angsi A-07 K-25U Mini-Frac AnalysisSqrt Graph
Meas'd Btmh (psi) (d/dt) Surf Press [Ann] (psi)
5000
5400
5800
6200
6600
7000
-750
-600
-450
-300
-150
0
0.0 6.0 12.0 18.0 24.0 30.0
BH Closure Pressure: 5631 psi
Closure Stress Gradient: 0.695 psi/ft
Closure Time: 2.9 min
Pump Time: 12.2 min
Implied Slurry Efficiency: 16.5 %
Estimated Net Pressure: 613 psi
Slide 52
Mini-Frac Applications
• Closure Stress
– Fracture Modeling
– Net Pressure (Complexity)
• Fluid Efficiency
– Optimize Pad Size
– Estimate Permeability (Some Cases) – Ad just Proppant Schedule
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Slide 53
WHAT IS TORTUOSITY? WIDTHRESTRICTION CLOSE TO WELLBORE
Slide 54
WIDTH RESTRICTION INCREASESNECESSARY WELLBORE PRESSURE
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Slide 55
FRACTURES GROW PERPENDICULAR TO THE LEAST PRINCIPLE STRESS
-- BUT WHAT HAPPENS AT THE WELLBORE ?
Slide 56
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Slide 57
STEPDOWN TEST
Source: “SPE paper 29989 by C.A. Wright et al.
• Perforation friction dominated regime
Slide 58
STEPDOWN TEST
• Tortuosity friction dominated regime
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Slide 59
Angsi A-07 K-25U Mini-FracStep-down Test
Meas'd Btmh (psi) Btm Slry Rate (bpm)
55.00 55.40 55.80 56.20 56.60 57.00 6000
6200
6400
6600
6800
7000
0.0
20.0
40.0
60.0
80.0
100.0
Step 1Step 2
Step 3
Step 4
Rate is reduced by simply shutting down pumps
Slide 60
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Slide 61
Remedial Measures Depend on Proper Diagnosis
High entry friction
High perf friction Severe fracture tortuosity
Re-perforate Use proppant slugs
Initiate with high viscosity fluid
Increase gel loading
Increase rate
Future wells may have alteredcompletion strategy such as
FEWER perfs
Slide 62
Mini-Frac Analysis
• Analysis Performed on Every Fracture Treatment
– Graphs In Lessons Learnt IV
– Values In Lessons Learnt IV and DataBase
• Analysis A lso Performed by Schlumberger Using FracCade
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Slide 63
Mini-Frac AnalysisK-28/30/35 Sands
K-28/30/35 Sand
Fault Closure Fluid Net Perf O pen % PerfsWell Block Pressure Eff. Pressure Tortuosity Friction Perfs Open
(psi/ft) (%) (psi) (psi) (psi) (each) (%)
A-02 1 0.70 49 1210 100 240 26 24
A-04 1 0.73 61 883 190 400 22 25
A-06 1 0.74 58 600 40 40 68 99
A-12 1 0.72 44 529 0 170 37 36
A-13 1 0.71 64 650 57 75 60 36
A-15 1 0.74 47 685 150 595 14 9
A-16 1 0.74 52 730 20 200 29 35
A-17 1 0.73 43 620 0 140 35 35
A-19 1 0.74 58 710 150 160 33 41 A-21 1 0.78 35 420 0 230 21 25
A-08R1 2 0.74 67 730 93 130 45 37
A-10 2 0.74 56 620 60 340 20 26
A-22 2 0.73 53 530 116 54 54 68
A-01 4 0.72 43 600 50 30 93 38
A-07 4 0.72 42 665 40 215 29 35
A-18 4 0.73 70 620 80 60 54 45 A-20 4 0.75 72 560 114 76 48 48
Average 0.73 54 668 74 186 41 39
Minimum 0.70 35 420 0 30 14 9Maximum 0.78 72 1210 190 595 93 99
-Sorted by Fault Block-Screen-Outs shown in Bold and Italic
Slide 64
Mini-Frac AnalysisK-25L Sand
K-25L SandsFault Closure Fluid Net Perf Open % Perfs
Well Block Pressure Eff. Pressure Tortuosity Friction Perfs Open
(psi/ft) (%) (psi) (psi) (psi) (each) (%)
A-02 1 0.67 9 860 600 400 26 18
A-04 1 0.74 20 450 220 330 24 11
A-06 1 0.74 26 450 120 60 56 38
A-12 1 0.71 30 350 78 32 76 47
A-13 1 0.70 74 653 46 130 38 29
A-15 1 0.72 34 580 88 197 25 31
A-16 1 0.75 58 520 20 180 31 29
A-17 1 0.69 6 500 90 180 30 38 A-19 1 0.75 15 290 120 30 74 70
A-21 1 0.73 22 600 160 150 25 24
A-08R1 2 0.71 19 680 525 380 23 24
A-10 2 0.75 50 440 210 300 21 23
A-22 2 0.74 24 340 50 330 23 29
A-07 4 0.75 36 350 57 23 90 55
A-18 4 0.72 15 460 90 210 12 11
A-20 4 0.74 54 617 124 86 45 56
Average 0.73 31 509 162 189 39 33
Minimum 0.67 6 290 20 23 12 11Maximum 0.75 74 860 600 400 90 70
-Sorted by Fault Block-Screen-Outs shown in Bold and Italic
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Slide 65
Mini-Frac AnalysisK-25U Sand
K-25U SandsFault Closure Fluid Net Perf Open % Perfs
Well Block Pressure Eff. Pressure Tortuosity Friction Perfs Open
(psi/ft) (%) (psi) (psi) (psi) (each) (%)
A-02 1 0.75 38 680 140 920 14 20
A-04 1 0.75 41 659 144 65 53 92
A-06 1 0.76 48 490 290 710 16 33
A-13 1 0.73 38 540 105 30 79 72
A-15 1 0.73 53 785 67 43 43 54
A-16 1 0.75 39 620 10 160 33 41
A-17 1 0.73 33 650 140 130 36 45
A-01 4 0.73 17 425 233 118 40 37
A-05 4 0.76 27 430 110 40 82 77
A-07 4 0.70 18 550 210 30 79 49
A-18 4 0.68 20 400 10 500 18 17
Average 0.73 34 566 133 250 45 49
Minimum 0.68 17 400 10 30 14 17Maximum 0.76 53 785 290 920 82 92
-Sorted by Fault Block-Screen-Outs shown in Bold and Italic
Slide 66
Mini-Frac AnalysisK-20/22 SandsK-20/22 Sands
Fault Closure Fluid Net Perf Open % Perfs
Well Block Pressure Eff. Pressure Tortuosity Friction Perfs Open
(psi/ft) (%) (psi) (psi) (psi) (each) (%)
A-02 1 0.71 36 804 90 425 21 21
A-04 1 0.74 32 537 167 58 57 50
A-06 1 0.78 31 510 60 140 36 42
A-12 1 0.74 14 402 24 80 48 44
A-13 1 0.72 54 859 55 96 44 54
A-15 1 0.73 47 780 66 64 43 54
A-16 1 0.77 56 620 80 360 21 36
A-17 1 0.76 47 520 60 140 34 43
A-19 1 0.75 81 1000 80 30 86 81
A-21 1 0.76 41 660 60 210 30 45
A-08R1 2 0.75 22 505 140 475 20 24
A-10 (1) 2 0.70 49 1100 50 400 19 17
A-10 (2) 2 0.72 36 1210 600 450 19 17
A-22 2 0.72 20 470 90 50 56 70
A-01 4 0.71 43 1020 565 370 22 33
A-03R1 4 0.76 35 530 93 127 38 46
A-05 4 0.75 56 750 40 240 28 41
A-07 4 0.75 51 485 269 766 16 23
A-18 4 0.74 36 570 20 350 13 16
A-20 4 0.73 37 629 100 100 42 53
Averag e 0.74 41 698 135 247 35 40
Minimum 0.70 14 402 20 30 13 16Maximum 0.78 81 1210 600 766 86 81
-Sorted by Fault Block-Screen-Outs shown in Bold and Italic
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Slide 67
Mini-Frac AnalysisI-Sands
I-SandsClosure Fluid Net Perf Open % Perfs
Well Interval Pressure Eff. Pressure Tortuosity Friction Perfs Open
(psi/ft) (%) (psi) (psi) (psi) (each) (%)
A-11 I-1 0.63 15 360 780 1180 9 40
A-20 I-15 0.67 34 705 638 2112 5 18
A-05 I-85 0.69 19 320 990 1400 12 40
A-08R1 I-85 0.63 35 800 550 1675 6 18
A-10 I-85 0.69 22 430 600 550 17 70
A-16 I-85 0.69 56 430 0 200 22 81
A-19 I-85 0.63 62 970 690 1550 12 44 A-21 I-85 0.63 54 640 1210 1470 7 26
Average 0.66 37 582 682 1267 11 42
Minimum 0.63 15 320 0 200 5 18Maximum 0.69 62 970 1210 2112 22 81
-Sorted by Formation-Screen-Outs shown in Bold and Italic
Slide 68
Mini-Frac AnalysisL-SandsL-Sands
Closure Fluid Net Perf Open % Perfs
Well Interval Pressure Eff. Pressure Tortuosity Friction Perfs Open
(psi/ft) (%) (psi) (psi) (psi) (each) (%)
A-15 L-10 0.78 77 850 101 424 17 26
A-18 L-10 0.77 84 950 80 160 34 43
A-15 L-30 0.75 59 1165 532 978 10 6
A-18 L-30 0.78 60 1200 90 60 50 63
Average 0.77 70 1041 201 406 28 34
Minimum 0.75 59 850 80 60 10 6
Maximum 0.78 84 1200 532 978 50 63