creating clarity and certainty for shale gas development
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Creating Clarity and Certainty for Shale Gas Development
A British Columbia ExampleShad Watts – Community Consultation & Regulatory Affairs Nexen NEBC Shale Gas
May 17, 2012
Agenda
Nexen NEBC Shale Gas Overview and Challenges Opportunities to Create Certainty and Clarity
Tenure Acquisition
Fiscal Incentives
Effective & Efficient Regulation
Shale Gas Case Study
Nexen Asset Positioning
2
____________________Resource Potential Estimate Source: Wood Mackenzie.
SAN JOAQUINBASIN
McClure
SANTA MARIABASIN
Monterey
UINTABASINBaxter
MancosPICEANCE
BASIN
PARADOXBASIN
Cane Creek
SAN JUANBASIN
MancosLewis BLACK WARRIOR BASIN
FloydConasuaga
Neal
BIG HORNBASINMowry
WILLISTONBASINBakken
BRITISH COLUMBIA/ALBERTAMontney
MICHIGANBASINAntrim
DELAWARE BASINBarnett
Woodford
BRITISH COLUMBIAHorn River
Muskwa
ARKOMA/ARDMORE BASINFayettevilleWoodford
Caney
Utica
Northeast British Columbia
Potential LNG Facility
North American Unconventional Resource Plays
Marcellus Shale: 197 Tcfe
Haynesville Shale: 140 TcfeEagle Ford Shale: 10 Tcfe
Barnett Shale: 61 Tcfe
Fayetteville Shale: 26 Tcfe
Montney: 55 Tcfe
NEBC Shales (Horn River: 104 Tcfe)
APPALACHIANBASIN
MarcellusHuron
Horn River Basin: Top Quartile Shale Play in North AmericaThird largest resource play in North America
500 net foot interval averages 50% thicker than the Barnett
High silica content shale is very brittle and fracable
10+ year land tenure with minimal drilling required to hold
Attractive tax regime and royalty structure
Competitive resource recovery (EUR) with 6 – 15 Bcf wells
Viable North American LNG export option
Ideally located to supply growing oil sands demand
Cordova Embayment extends platform
Nexen Ownership Summary
~172,000 acres in Horn River and Cordova
~128,000 acres in Liard
60% working interest
100% operated
Ownership in Cabin Gas Plant
Woodford Shale: 12 Tcfe
~128,000 net acres ~90,000 net acres ~82,000 net acres
Nexen Total NEBC Basin Acreage: ~300,000 net acres
Takeaway CapacitySpectra Plant
100 MMcf/dCabin Gas Plant
5% Nexen WI in Phase 1400 MMcf/d gross
processing capacityExpected online mid-
201220% Nexen WI in Phase 2
400 MMcf/d gross processing capacity
Shale Gas Overview
4
Shale Gas Overview
Northeast British Columbia
STAGES OF SHALE GAS EXPLORATION AND DEVELOPMENT
• A stepwise approach through exploration and appraisal… • Technical feasible – defining and characterising the a viable play concept; • Commercial feasiblity – cracking the nut leading to cost effective reservoir
productivity; • Commercial demonstration through pilot programs prior to project sanction
30+
6
Development Requirements NEBC
1. Permanent Roads and year round access.2. Well pads with many (8-20) horizontal wells
• One pad per 3 square miles.• Triple Drill Rigs (5000m); self moving • Surface footprint only 5-10% of traditional equivalent
vertical well development • Innovative application of technology to reduce
development costs.3. Completion (fracing) of Horizontal Wells.
• 16-20 fracs per well. • 3+ fracs per day.• exclusively slick water* fracs .• typically 200-350 tonnes sand per frac (2-4 railcars).
4. Appropriate pipelines to and from the well pads
*Slickwater or slick water fracturing is a method or system of hydro-fracturing which involves pumping water & sand with a friction reducer.
Shale Gas Overview
7
5. In field Facilities / Gas Compression• Dehydrate and compress gas• Formation water filtration & disposal
6. Takeaway pipeline to Area Gas Plant(s)
7. Area Gas Plants that will further process the gas• Remove CO2 and trace H2S• Compress to sales pipeline pressures
8. Sales pipeline to transport gas to market
Development Requirements NEBCShale Gas Overview
Horn River Basin – Drilling (18 well pad)Shale Gas Overview
b-77-H/94-O-8 Pad 2011
Horn River Basin – Completions (9 well pad)
c-1-J/94-O-8 Pad 2011
Shale Gas Overview
• Distance to market
• Undeveloped local service sector / distance to services
• Lack of infrastructure and difficult surface access
• Understanding the reservoir
• Long time before positive return
Shale Gas Overview
Development Challenges NEBC
11
Drilling24%
Completions43%
Pad Construction2%
Pad Facilities & Pipelines9%
Field Infrastructure8%
Site Operations
14%
Shale Gas Overview
Drilling = $127,687/day Completions = $640,693/day
(excluding materials)
Large upfront capital requirements
Development Challenges NEBC
How to get the most gas usingthe least frac water & proppant ?
What to put on the books ?
Deliverability and EUR for each well ?
How important are naturalFractures ?
How many frac stages & how far apart ?
Where should laterals be placed ?
What is the best well spacing,length & orientation ?
Best flowback practices to enhance performance ?
Planar bi-wingor complex fracs ?
Is there a sweet spotin the reservoir ?
THE SHALE GAS DEVELOPMENT CHALLENGE
How much infrastructure and when to expand ?
Market contracts and takeaway capacity ?
How to reliably assess to services?
How much free & absorbed gas ?
How much is it going to cost ?
Shale Gas Overview
Key Messages – What It Takes
Quantitative – Below Ground• Positive expected monetary values Cumulative distribution of NPV that
incorporates mitigation decision points and key subsurface risk and uncertainty ranges
• Acceptable risked capital levels • Attractive success case valuationQualitative – Above Ground• Favorable fiscal terms and incentives that promote exploration and risk sharing• Terms of tenure aligned with the “unconventional” timelines for exploration,
appraisal and development • Sanctity of contract• Stable, streamlined, open and transparent regulatory structure• Infrastructure to customer• Liberalized gas market • Political stability• Secure and predictable operating environment• Legitimate government consultation on regulation, terms and policy
Shale Gas Overview
Agenda
Nexen NEBC Shale Gas Overview and Challenges Opportunities to Create Certainty and Clarity
Tenure Acquisition
Fiscal Incentives
Effective & Efficient Regulation
Shale Gas Case Study
Oil & Gas TenureTenure Must Facilitate Responsible Development:
• Should stimulate work activity rather than be viewed as a revenue generation mechanism
• Clear definition of exclusive rights geographically
• Appropriate to resource developed in the term, and geographical extent
• Risk sharing through flexibility in commitments for work or cash in lieu with optionality for staged commitments related to market.
• Maintains competitiveness through market pricing with no minimum bids but don't have to award if less than fair award price
15
Certainty in Subsurface Rights
16
• Exploratory effort is rewarded with the right to produce, delineation of a pool allows the tenure to be held beyond the end of its term
• Longer tenures are granted in areas with poorer infrastructure
• Oil and gas tenure grants the rights to the resource only - permitting of exploration and development activities is managed separately by an independent agency
• Unused rights return to the Crown at the end of the tenure term
Principles of British Columbia’s Tenure System
Oil & Gas TenureCertainty in Subsurface Rights
Tenure Types in BC
Drilling Licences (3, 4, or 5yr term)• Exploration type of tenure• Different terms depending on location• Encourages Development
Leases (5 or 10yr term)• Production form of tenure• Held in perpetuity
17
Certainty in Subsurface Rights
Agenda
Nexen NEBC Shale Gas Overview and Challenges Opportunities to Create Certainty and Clarity
Tenure Acquisition
Fiscal Incentives
Effective & Efficient Regulation
Shale Gas Case Study
A SUCCESSFUL FISCAL REGIME
• Fiscal regime that shares risk / incents activity• Provides long term certainty• Enable accelerated capital cost recovery for capital intensive plays• Facilitate resource development through access cost sharing in
remote areas (roads and pipe)• Incent zone specific production through target credits• Recognize seasonal or operational constraints
Shale Gas Case Study
20
BC’s Targeted Royalty ProgramsFiscal Incentives
Impact of BC Royalty Programs
21
• $1.3 billion in incremental royalties since 2004/05
• 21% increase in BC’s natural gas revenues
Fiscal Incentives
Agenda
Nexen NEBC Shale Gas Overview and Challenges Opportunities to Create Certainty and Clarity
Tenure Acquisition
Fiscal Incentives
Effective & Efficient Regulation
Shale Gas Case Study
Efficient and Effective Regulation
• Considers Operational requirements, risk, and technical considerations• Built collaboratively • Flexible • Approvals received in a timely manner• Incent desired practices • Results based – focus on compliance
Government and Ministries • Set Policy and Legislation
• Award Tenure
Oil and Gas Commission• Provides Permits &
Approvals• Compliance & Enforcement
Industry • Develops
Projects
E.g. Oil and Gas Activities Act
E.g. Drilling and Production Regulation
Provincial Legislative FrameworkEffective & Efficient Regulation
Specified Enactments
Land Act:Section 14 Temporary Occupation of Crown LandSection 39 Licence of OccupationSection 40 Right of Way
Water Act: Section 8 Short Term Use of WaterSection 9 Changes in and About a StreamSection 26 Permits over Crown Land
Forest Act:Section 47 Master Licence to CutSection 117 Road Use Permit
Other Enactments:Section 12 Heritage Conservation ActSections 9, 14 & 15 Environmental Management Act
The BC Oil and Gas Commission serves as a “single window” agency provided with legislative authority for authorizations
under several Acts.
Effective & Efficient Regulation
One Window Approach
25
26
Oil and Gas Activities Act (OGAA)• More efficient approvals for multiple related activities• Increased compliance and enforcement mechanisms• Increased landowner/stakeholder support• Increased environmental protections• New appeal provisions• Maintains specified enactments
Drilling & Production Regulation
Environmental Protection & Mgmt RegulationReg
ulat
ory
Fram
ewor
k
Geophysical Exploration Regulation
Administrative Penalties Regulation
Consultation and Notification Regulation
Reg
ulat
ory
Fram
ewor
k
Pipeline Regulation
Structure of OGAAEffective & Efficient Regulation
Project Lifecycle – What the Commission Regulates
6. Operations• Risk based
inspections• Compliance
Programs and Audits
2. Application • First Nations
Consultations• Application Review
7. Abandonment / Reclamation• Certificate of Restoration Process• Orphan Fund
1. Pre-Application• Consultation/Engagement by
Industry with landowners, other stakeholders/First Nations and Government/Commission
3. Decision (21 days)• Permit issued or declined
with reasons• Conditions attached as
appropriate4. Construction
• Inspections and Enforcement
5. Leave to Open/Production • Review project to ensure it is
compliant and ready to commence operations
One Window ApproachEffective & Efficient Regulation
27
28
WELL PERMIT APPLICATION FORM
OGC, 100 10003 110 AVE Fort St. John, B.C. V1J 6M7
Phone: (250) 794-5200
Date Received
THIS IS AN AUDITABLE DOCUMENT FOR INSTRUCTIONS REFER TO THE WELL PERMIT APPLICATION MANUAL
COMMISSION USE ONLY A Commission File No.: WA No.: Document : Application Category: Routine Non-Routine Application Fee: $
Well Classification: Objective Field: Objective Field Code:
ADMINISTRATION B Applicant Name:
Address: City, Province, Postal Code: Contact: Email: Phone: Referral Company: Email: Phone: Agent Name: Internal File No.:
APPLICATION INFORMATION C ePASS No.: Surface location (NTS/DLS):
Well Name: New Permit Holder Application Fee Applicable Yes No
Primary Well Application Subsequent Well Application with new area
If this is a subsequent well application, enter the primary WA No.: _____________ and Commission File No.: _______________ Revision to Commission File No. : Re-entry COR/WA No.:
Water Source Well Is the water source well designed to operate at a rate greater or equal to 75 litres/second? Yes No
Disposal Well Injection Well Cross Reference to other Commission File No. (if applicable): Is this well within an area designated as a special project using innovative technology under section 75(1)(b)? Yes – Approval No.: _____________ No
LAND STATUS D Area Of Activity: North Central South MKMA ALR SYD
Forest District(s): Master Licence To Cut (MLTC) No.: Crown Land Private Land
Is there a Timber Reservation charged against the title? Yes No
Review Corridor applied for Cross reference to existing review corridor, OGC file no.: Total woodlot licence area ha Total area private land ha Total area Crown land ha Total new Crown land area disturbance ha Total application area proposed ha Area of Crown land for wellsite only ha
FIRST NATIONS CONSULTATION / ABORIGINAL COMMUNITY NOTICE PACKAGE N/A E Ensure the following are attached to the application for First Nations consultation purposes:
Aboriginal Community Notice Consultation Attachments
KLCN BRFN MLIB Cover letter (2 copies for each consultation and notification area affected) KLFN DENE
THA PRFN Application Form
KLMSS DRFN SFN Mapping requirements
FLFN FNFN WMFN Archaeological Assessment Information Form Other HRFN Archaeological Reports, if available
Other: Fibre Utilization Plan
Other Documents
PETROLEUM & NATURAL GAS TENURE RIGHTS F Permit, Drilling Licence or Lease Number(s) (for bottom hole location(s), plus heel to toe locations): __________________________ _________________________ _________________________ _______________________ Is the applicant the registered holder of the petroleum and natural gas rights? Yes No
WELL SPECIFICATIONS G Directionally drilled Vertically drilled Horizontally drilled
Well Centre Coordinates (UTM) Zone: N: E:
Surface Coordinates: N/ S (m) E/ W (m) from corner of Ground Elevation (m): Proposed Bottom Hole
Location(s) & Heel Location (s)
Objective Formation(s)
Objective Fluid (oil, gas or water)
Objective Depth(s) (m TVD)
Core (Y/N)
Expected TD Formation at: TD
BOP Class
( m TVD) (m MD)
PROPOSED CASING PROGRAM H Bit Size (mm)
Casing Size (mm O.D.)
Linear Density (kg/m) Grade New or Used Setting Depth
(If directional, enter m TVD and in MD)
DRILLING INFORMATION I Drilling fluid type: Gelchem KCI Air Hydrocarbon Based:
Other – Specify Type:
Underbalanced drilling? Yes No Managed pressure drilling? Yes No Is a remote sump being applied for with this application?
Yes No If yes, remote sump must be shown on the construction plan.
SOUR WELL INFORMATION (H2S RELEASE RATE > 0.01 m3/s) N/A J List expected sour zones and their corresponding maximum H2S content (%):
Cumulative H2S release rate (m3/s): Drilling: Completion:
Emergency Planning Zone radius (km): Drilling: Completion:
Distance to nearest occupied dwelling (km): Distance to nearest Urban Center (km): Are there any occupied dwellings, public facilities, numbered or named highways, rivers and lakes, recreation areas, places of business and/or egress inside the calculated Emergency Planning Zone? Yes No
Effective & Efficient Regulation
Streamlined Application
29
Horizontal Wells
Environmental Protection
• 20 Horizontal wells from one 260x175m pad• Each frac stage in hz well is equivalent to a vert. well
• Would need 320 vertical wells • Vertical wells each on a separate 100m x 100m pad
• Same amount reservoir contacted in both scenarios• 85% less surface disturbance
Vertical Wells
Effective & Efficient Regulation
Environmental Protection
Small Lake Complexes
• Collaborative effort bw industry and government
• Calf mortality decreases when selected
• Calf recruitment success increases
• Predators are avoiding/don’t select
Lakes 1 ha – 10 ha within 200m proximity of each other250m buffer applied
2000 meters
Effective & Efficient Regulation
30
What is Water Used For?
Road and well pad
construction
Drilling
Well completions
Transportation/pipelines 31
Oil and Gas
Water uses – Shale GasEffective & Efficient Regulation
32
Water requirements
Nexen Horn River Basin:• 1 pad per year • 16-18 frac stages per well, 20 wells per pad• Frac design:
• 3300 m3 per frac stage and drill-outs• 60,000 m3 per well x 20 wells per pad• 200-350 tonnes frac sand per frac
• Total annual requirement of ~1,200,000 m3 of water & 80,000 – 140,000 tonnes of sand
Effective & Efficient Regulation
Approximately2500 metres below surface
Potable Water Wells: <150-300 metres
Surface casing
Additional steelcasing andcement toprotect groundwater
Protective Steel Casing
Potable Groundwater Aquifers
Hydraulically fractured shales
Water Protection - Well Construction
33
Effective & Efficient Regulation
34
Licensed Withdrawal
• Variable withdrawal rates are designed to mimic seasonal variations in flow
Flow ConditionInstream
Flow Range (2011)
Withdrawal Parameter
Flood Stage: 80% > inferred median > 1.652 m3/s
25% of mean daily discharge
High Flow: > inferred median
0.918 – 1.651 m3/s
15% of mean daily discharge
Normal Flow: < inferred median
0.918 – 0.352 m3/s
10% of mean daily discharge
Zero Withdrawal Limit < 0.351 m3/s (30% of mean
annual flow - ice free period)
0
Maximum Withdrawal Limit 2 500 000 m3/year
0.00
1.00
2.00
3.00
4.00
5.00
6.00
22-Apr-10 12-May-10 1-Jun-10 21-Jun-10 11-Jul-10 31-Jul-10 20-Aug-10 9-Sep-10 29-Sep-10 19-Oct-10
Mea
n Da
ily D
ischa
rge
(m3/s
)
Tsea River at W7 - 2010 Discharge Tsea River at W7 - 2010 Allowable WithdrawalInferred Median Flood StageZero Withdrawal Limit 2010 Used
Total Discharge (April to October): 17 600 000 m3
Total Allowable Withdrawal: 3 400 000 m3 (19% of total)Current use capacity: 2 000 000 m3 (12% of total)
25% of MDF
15% of MDF
10% of MDF
0 Withdrawal
34
Effective & Efficient Regulation
Conclusions
Capital Intensive Development
Governments and industry need to work together
Different phases of development need to be recognized
Focus on results based regulatory framework to enhance efficiency and flexibility
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