Let's put engineering back into fracture stimulation!

              Neil Stegent, P.E.
Pinnacle –a Halliburton Service
1
Let’s put Engineering back into Fracture Stimulation!
Oklahoma Geological Society –Shales Moving Forward
Norman, Oklahoma; 21 July 2011The Company President asking his staff ................ How are we going to “Frac” this well?
What are the other Operators doing on their wells?
How much is it going to cost?
HOW MUCH!!!!!
Why’s it cost so much?
Do we really need to do all that stuff?
What stuff can we leave out?
Do you think it will work if we don’t do all that stuff?
Who’s going to figure it out if it doesn’t work?Fig. 10 - Log kh vs. 6 Month Oil CumulativeR2 = 0.6994020406080100120-5,00010,00015,00020,00025,0006 Month Oil Cumulative, BOLog Derived In-Situ Permeability-Thickness, md-ftTrendline
EngineeredCompletions
Un-EngineeredCompletionsWell Response @ 12 Months - Greater Than 300oF0%10%20%30%40%50%60%70%80%90%100%01,000,0002,000,0003,000,0004,000,0005,000,0006,000,00012-Month Cumulative Production (MCF)Cumulative Frequency (%)OtherHES
•Horsepower
•Fluid
•Proppant
Schedule:
1) Perforate
2) Pump
3) RepeatkXwKFcd ffFig. 10 - Frac Finding Costs for Project Wells$-$0.10$0.20$0.30$0.40$0.50$0.60$0.70$0.80135791113151719212325272931Well ListFrac Finding Costs, $/EUR mcfPre-Reservoir Description UsageAverage = $0.21 STD Dev = $0.18Post-Reservoir Description UsageAverage = $0.10 STD Dev = $0.054
Eagle Ford Shale -Background
OilDry GasGulf of Mexico
•Depth Range: 4,000’ –14,000’
•BHT Range: 150°F -350°F
•PresGrad. Range: 0.55 –0.85 psi/ft
•Can produce Dry gas @ 8000’ andHigh Liquids @ 13,000’ , Oil @ 5000’5180’120’
SPE 136183
Mineralogy
Characterization
Brittleness
Index
TOC and
Kerogen
Rock
Properties
Raw Data
Eagle Ford Shale -Petrophysics6
Frac Design in Horizontal: Run Sensitivities
•Injection Rate
•Fluid Volumes
•Fluid Viscosity
•Prop Volume
•Prop Concentration
•Prop Mesh Size
•OthersNear Wellbore Restriction (tortuosity)
Issues with Proppant Placement
•Transverse fracture initiation in perf cluster that is to long c...can create multiple fractures (SPE 19720).
•Multiple fractures can create tortuosity (SPE 35194).
•Limit perf interval to 4 times the ID of the casing (SPE 86992)
•Use Acid Soluble Cement in Horizontal (SPE 137441)
Image from SPE 19720 by El Rabaa, 1998and SPE 102616 by Soliman, 2006Impact of Perforation on the Formation:Perforation Damage -Crushed, Compacted, “Onion-Skin” ZonePerforation TunnelCementBlue-DyedFractureOnion-SkinUn-fracturedHalo around compaction zonePipe
Work by Norm Warpinski, 1983
FormationCompactionZone (Halo)9
Frac Design Considerations
SPE 136183
20/40
30/50
40/70
700 m
400 m
300 m
Embedment Core Tests
Eagle Ford Shale
0.35 –0.77 mm @ 10,000 psiSPE 136801SPE 135502
40/80 Mesh
Lightweight Ceramic
Haynesville Core Sample10200 cp
50 cp
Bauxite80 md-ftRCP25 md-ftSand5 md-ft
Non-Emulsifiers needed for Oil
Proppant Conductivity
Multi-phase flow
“Hybrid” Frac Fluid
kX KwF fffcd500.001md *ft 500 ft-md 25
Frac Design Considerations
950 cp
35# Polymer
Loading
Dimensionless Conductivity (Fcd)11
Frac Design Considerations: Basic Definitions (SPE 136183)
Water Frac or Slick Water Frac:
•Frac fluid is very low viscosity
•Chemicals or gelling agents are used for friction reduction, not prop transport
•Velocity (not viscosity) used to place proppant
•Injection rates tend to be high
•Typically have alternating stages of proppant followed by fluid “sweeps”
Conventional Frac:
•Frac fluid is high viscosity (from foams to crosslinked fluids)
•Chemicals used to generate viscosity for proppant transport
•Viscosity (not velocity) used to place proppant
•Injection rates can vary greatly (not depending on velocity to place prop).
•Typically have “pad” fluid followed by continuous proppant-laden fluid.
Hybrid Frac:
•Anything in-between a water frac and a conventional frac.
•Typically, a hybrid frac is a combination of the two.
•They tend to begin with a low-viscosity fluid (at a high rate)
•May have alternating proppant volumes with fluid “sweeps”
•Tail-in (sometimes at a lower injection rate) with proppant high-viscosity fluid.
•Large part of job may be crosslinked or just Tail-in fluid may be crosslinked. 12Production Comparison: Slick Water vs. Hybrid/Conventional1 10 100 1,000 10,000 050100150200250300050100150200250300350400450PressureRateDays on ProductionRate vs TimeOil Rate [bopd]Gas Rate [mcfpd]Water Rate [bwpd]FTP [psi]Migura A#1
1styear production
150,000 bbls oil 1styear
518,000 mscf(0.5 bcf)
(Hybrid Frac/Conventional )
1styear production
5,500 bbls oil 1styear
16,900 mscf(0.017 bcf)
(Slick Water Frac)
1 10 100 1,000 10,000 050100150200250300050100150200250300350400450PressureRateDays on ProductionRate vs TimeOil Rate [bopd]Gas Rate [mcfpd]Water Rate [bwpd]FTP [psi]Migura A#11 10 100 1,000 10,000 05001,0001,5002,0002,5003,0003,5004,000050100150200250300350400450RateDays on ProductionRate vs TimeOil Rate [bopd]Gas Rate [mcfpd]Water Rate [bwpd]FTP [psi]Krause Unit 1 #1Pressure
FTP
Gas
Oil
7000 psi,
3 MMscfd,
1000 bopd
400 psi,
0.15 MMscfd,
25 bopd
Choke Sizes: 10-20 first 140 days13
Frac Mapping: 700’4,000’4,700’TargetAustin ChalkUpper EFLower EFBudaPilot hole
Good Zonal
Coverage
Rosetta Resources –Gates Leases
Well PlanningLateral Placement
Good Well Direction
Good Well Spacing
Monitor
Well
SRV –Stimulated
Reservoir Volume14
Frac Mapping for Frac Model Calibration:
Top
View
Side
ViewFrac Match withMicroseismic EventsInitial Frac DesignDivide 6-160 S2SConc (PPG) - BHConc (PPG)1.02.03.04.05.06.07.08.09.010.0SRate (BPM)10.020.030.040.050.060.070.080.090.0100.0WHTP (psi) - BHTP_C (psi)10002000300040005000600070008000900010000Time (min)10.020.030.040.050.060.015
Post Frac Hydrocarbon Flow Profiling
Information provided by TracerCo
A hydrophobic tracer is added to each frac stage.
Each of the hydrophobic tracers dissolves within reservoir hydrocarbons.
Surface flowback samples are analyzed for the different tracers.
Analysis verification of stage flow and its relative contribution to production.16
Post Frac Hydrocarbon Flow
0510152025Stage 1Stage 2Stage 3Stage 4Stage 5Stage 6Stage 7Stage 8Stage 9Stage 10Stage 11Stage 12Stage 13Stage 14Stage 15Stage 16Relative % of Production FlowStage Production FlowInitial ProductionProduction after Choke ChgProduction during Frac Monitor WellAfter Frac ProductionProduction after restart
No Tracer Pumped
No Tracer Pumped17
Production Analysis -1/Rate vs. Cum Prod
The slope is proportional to the system perm and fracture length
A constant slope indicates “stabilized” fracture conductivity (after clean-up)
First trend: must have a non-negative intercept
Intercept is a qualitative measurement of conductivity of the fracture network
Zero intercept = infinite conductivity Positive intercept = finite conductivity
Second trend: influenced by boundaries
Either drainage boundaries or interference between fractures
SPE 139981 & 142382
Normalized by Length
of Lateral Stimulated
WattenbargerMethod
Dr Jeff Callard,
University of Oklahoma
2500 ft Lateral with11 frac stages300, 000 lbs per stage5000 ft Lateral with14 frac stages300,000 lbs per stage18
The Company President asking his staff ................ How are we going to “Frac” this well?
What are the other Operators doing on their wells?
How much is it going to cost?
HOW MUCH!!!!!
Why’s it cost so much?
Do we really need to do all that stuff?
What stuff can we leave out?
Do you think it will work if we don’t do all that stuff?
Who’s going to figure it out if it doesn’t work?You Are! And you can because you have Data!19
ThankYou
Neil Stegent, P.E.
neil.stegent@pinntech.com
neil.stegent@halliburton.com