WELLS RANCH SEC. 25: OBSERVATIONS FROM A UNDERGROUND IN-SITU - - PowerPoint PPT Presentation
WELLS RANCH SEC. 25: OBSERVATIONS FROM A UNDERGROUND IN-SITU - - PowerPoint PPT Presentation
WELLS RANCH SEC. 25: OBSERVATIONS FROM A UNDERGROUND IN-SITU LABORATORY Dave Koskella Bob Parney David brock January 21, 2015 Slide 2 Forward-looking Statements and Other Matters This presentation contains certain forward - looking
Forward-looking Statements and Other Matters
Slide 2
This presentation contains certain “forward-looking statements” within the meaning of the federal securities law. Words such as “anticipates,” “believes,” “expects,” “intends,” “will,” “should,” “may,” and similar expressions may be used to identify forward-looking statements. Forward- looking statements are not statements of historical fact and reflect Noble Energy’s current views about future events. They include estimates of
- il and natural gas reserves and resources, estimates of future production, assumptions regarding future oil and natural gas pricing, planned
drilling activity, future results of operations, projected cash flow and liquidity, business strategy and other plans and objectives for future
- perations. No assurances can be given that the forward-looking statements contained in this presentation will occur as projected, and actual
results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks include, without limitation, the volatility in commodity prices for crude oil and natural gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, competition, government regulation or
- ther actions, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy’s business that are
discussed in its most recent Form 10-K and in other reports on file with the Securities and Exchange Commission. These reports are also available from Noble Energy’s offices or website, http://www.nobleenergyinc.com. Forward-looking statements are based on the estimates and
- pinions of management at the time the statements are made. Noble Energy does not assume any obligation to update forward-looking
statements should circumstances or management's estimates or opinions change. This presentation also contains certain historical and forward-looking non-GAAP measures of financial performance that management believes are good tools for internal use and the investment community in evaluating Noble Energy’s overall financial performance. These non-GAAP measures are broadly used to value and compare companies in the crude oil and natural gas industry. Please also see Noble Energy’s website at http://www.nobleenergyinc.com under “Investors” for reconciliations of the differences between any historical non-GAAP measures used in this presentation and the most directly comparable GAAP financial measures. The GAAP measures most comparable to the forward-looking non-GAAP financial measures are not accessible on a forward-looking basis and reconciling information is not available without unreasonable effort. The Securities and Exchange Commission requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The SEC permits the optional disclosure of probable and possible reserves, however, we have not disclosed our probable and possible reserves in our filings with the SEC. We use certain terms in this presentation, such as “discovered unbooked resources”, “resources”, “risked resources”, “recoverable resources”, “unrisked resources”, “unrisked exploration prospectivity” and “estimated ultimate recovery” (EUR). These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosures and risk factors in our most recent Form 10-K and in other reports on file with the SEC, available from Noble Energy’s offices or website, http://www.nobleenergyinc.com.
Life Cycle of a Resource Play
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Demonstrate Economic Productivity Minimize Cost Structure Optimize Well Spacing Demonstrate Productivity Economically Develop Reserves Current State Confirm Resource/OOIP
Greater Wattenberg Area
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WY CO NE
B Chalk
Smokey Hill Member
Niobrara Formation
Ft Hays Ls
Carlile
Pierre Shale
Sharon Springs
A Chalk C Chalk A Marl B Marl C Marl D Chalk Codell Ss
Tur. Coniacian Santonian Cam.
275’ - 350’ Niobrara Stratigraphy
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Fort Hayes Limestone C Chalk C Marl D Chalk Cemex Limestone Quarry, Lyons, CO
150’
Niobrara Characteristics
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OOIP 70 MMBOE/Section TVD 6,700’ H 300’ Phi 9% K 0.81 uD P* 0.49 psi/ft API 40 GOR 5,000 scf/bbl Sh min 0.75 psi/ft Sh max > 0.75 psi/ft
Frac Grad 0.85 psi/ft
Sv 1.06 psi/ft
Permeability (Micro Darcy) P10 1.48 Pmean 0.81 P90 0.32
In-Situ Underground Laboratory Technologies Employed
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- Multi-Array Down Hole Micro
Seismic (Six Wells)
- Ten Down Hole Pressure Gauges
- Ten Down Hole Temperature
Gauges
- Two wells with Fiber Optic:
DTS Stimulation DTS Production Logging DAS
- RA Proppant Tracers
Three Wells Traced Five Wells Logged
- Liquid Tracers (Nine Wells):
Water Based Oil based
- FMI’s (Nine Wells)
- Core (Two Wells)
- Core Laboratory Testing
- DFITS (Nine Wells)
- VSP
- Geochemistry
Core Extracts Produced Oil
- 3-D Seismic
In-Situ Underground Laboratory
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One Section (One Square Mile)
Vertical well Vertical well: microseismic monitor Vertical well: downhole pressure Pressure gauge in horizontal DTS well Horizontal well Horizontal DTS well P
P m P P P P P P
P P P P
m m m m
140’ 180’ 480’ 290’ 430’ 270’ 410’ 320’ 290’ 170’ 480’ 510’
1400’ microseismic listening radius
B Chalk B Marl C Chalk
DTS Well Construction
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Laser source and detector Fiber-optic cable in wellbore formation packers Fiber-optic cable
- Approximately 4000’ lateral:
20 stages, ~200’ per stage
- Open-hole, packer-isolation
- Ball-drop w/ sliding-sleeves
- Fiber optic cable fixed to
- utside of casing
- Electric Pressure gauges at
toe and heel
Hybrid Design (Single Stage):
- SLW & XL Pad at 50 bpm
- 28 lb HPG at 50 bpm ramping to 4 ppg
- 140,000 gallons
- 200,000 lbs proppant
DTS During Completion
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DTS During Completion: Fluid Movement and Warmback
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2 3 4
Overall, both wells: Heelward bias: 37% of stages Toeward bias: 13% of stages No bias: 50% of stages
DTS During Completion: Packer Leak/Bypass
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7 8 9 6
Both Wells, By Stage: Toe Leak/Bypass: 17 of 38 stages (45%) Heel Leak/Bypass: 4 of 38 stages (11%) By Packer: 19 of 37 packers (51%)
DTS During Completion: Multiple Packer Leaks/Bypass
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14 15 16 13
DTS During Completion: Operations Diagnostic Example
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Harmonic Debris
Fracture Statistics from DTS
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Two wells, 38 stages total Fractures: 135 (avg 3.5 fracs/stage)
0% 20% 40% 60% 80% 100% 5 10 15 20 25 30 Cumulative Frequency Frequency (count)
Inter-Fracture Spacing (ft)
Fracture Spacing Histogram Feature # stages (of 38) % of stages “Dominant” Frac (one frac >> others) 18 47% “Significant” Frac (long lasting DTS warmback) 12 32% Frac at toe packer 6 16% Frac at heel packer 15 39% Fluid bias: toe 5 13% Fluid bias: heel 14 37% Packer Leak/Bypass: toe 17 45% Packer Leak/Bypass: heel 4 11% Leak/Bypass by Packer: 19 of 37 packers = 51%
Proppant Tracer Inter-Well Transport
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0% 5% 10% 15% 20% 25% 10 20 30 40 50 60 70 80 90 RA Tracer Lateral Coverage (%) Angle from Horizontal (°)
Down Hole Pressure Monitoring in Vertical Wells During Stimulation (178 Frac Stages)
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Vertical well monitoring distances: 140-510’
Pressure Response During Completion of One Well
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1000 2000 3000 4000 5000 6000 7000 0:00 6:00 12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00 12:00 BHP (psi) 3000 6000 9000 0:00 6:00 12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00 12:00 Treating P Time 1000 2000 3000 4000 5000 6000 7000 0:00 6:00 12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00 12:00 BHP (psi)
Prock face ~6200 Pfrac ext ~5400 Shmin ~5000 Pres ~3300
Drainage Network Geometry
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Lognormal Elliptical Analysis of Micro-Seismic Events
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End on view of well bore
Lognormal Elliptical Analysis
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Microseismic Overview
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Microseismic & Pressure Correlation?
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2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 1000 1500 2000 2500 3000 3500 4000 1/29/2012 9:36:00 1/29/2012 14:24:00 Treating Pressure (psi) BHP (psi) Time 67-01HN HEEL 25-06DH 25-08DH 66-01HN Treating Pressure
- Microseismic events along path from frac stage #2 toward and around
vertical monitoring well
- Pressure responses observed in nearby observation wells not correlated
with microseismic events
Inter Well Behavior: Intergrating Pressure & Microseismic?
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- Micro seismic events along path from frac well toward
and around vertical monitoring well
- No pressure response observed in nearby vertical well
DTS Analysis for Production Logging: A History-Match Process
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Measured Depth Temperature
Formation Temperature DTS (Well) Temperature
inflow
inflow inflow
- DTS: Early-Time
(Formation)
- DTS: Analysis
Timepoint
- Surface Flow Rates
PLATO
- Energy, momentum, mass
balances
- Iterates on flow profile,
reservoir pressure
- Seeks best fit on
temperature
- Reservoir Properties
- Fluid Properties
Production Log
Oil Production (4 months into production)
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- By stage oil production
- (Average stage would have 5% flow)
- Best stage: 6.9%
- Poorest stage: 1.4%
- Production profiles do not correlate
to FMI artifacts
- Pmean oil rate 32% better in Toe Stages
Heel Stages
Oil Production through Producing Life
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- By-stage oil production results
0% 2% 4% 6% 8% 10% 12% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Percent of Well Total Stage Oil, Prod+11mo Oil, Prod+8mo Oil, Prod+4mo
(toe) (heel)
Summary
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Stage Perspective:
- Fracture Initiation: Average 3.5 fractures per 200 foot stage
- “Stress Shadowing”? Heelward fluid bias vs. toeward bias (37% vs.
13%) Well Perspective:
- More instances of packer leaks/bypass in the heelward half of wells
(78% heel stages vs. 30% toe stages)
- DTS production logging shows all stages producing with no large
redistributions over time. Toeward stages 32% more productive than heelward stages.
Summary (cont.)
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Inter-Well Perspective:
- RA Proppant Tracer:
– Horizontally not observed, 0-15 degrees, 0% coverage – Diagonally observed, 15-50 degrees, 8% coverage – Vertically observed, 90 degrees, 20% coverage
- Pressure responses << Shmin observed up to 1,520’
- Pressure responses > Shmin rarely seen at distances of 140-510 feet,
7 events out of 178 frac stages
- Dynamic inter-well hydraulic connectivity, shrinking drainage radius
- Microseismic responses seen 1,400’ away
- Inferred drainage ellipse orientation:
– Microsiesmic (horizontal) vs. other data sets (vertical)?
- Pressure and microseismic event correlation is not obvious
- No consistent temperature response seen in offset DTS wells
- Much still to learn….
Acknowledgements
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