Force and Petroleum Economics of IOR/EOR General integrated work - - PowerPoint PPT Presentation

• Force and Petroleum Economics of IOR/EOR

General integrated work process for economic evaluation of IOR/EOR projects

• Reserve reporting and IOR/EOR projects
• Economic models of drilling versus IOR/EOR projects
• Effect of new tax system and possible other changes in the future

Arvid Elvsborg, Managing Director IPRES Norway Tor Andersen, Senior Consultant Xodus Group Lars Rustad, Senior Consultant Xodus Group

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Setting the Scene for IOR/EOR

“Most of the world’s future oil and gas reserves won’t come from new discoveries, but by finding ways to get more oil from regions the industry already has developed. We’ve probably reached the time, amazingly, when there’s as much to be got extra out of the oil fields we have discovered as there is to be found in new fields,”

David Eyton, BP’s Group head of research and technology, said in an interview at the Offshore Technology Conference in Houston 2014.

Setting the Scene for IOR/EOR

“Based on existing technology the industry expects to leave more than half the oil it

discovers in conventional reservoirs. BP, however, has embarked on a number of projects it believes will significantly boost the amount of oil it can extract from its existing wells or oil fields, helped in part by its new super computer in Houston that can make 2,200 trillion calculations in one second The behemoth calculator is designed to create much better images of reservoirs in places like the Gulf of Mexico, where salt canopies had forced oil companies to drill almost blind for decades It’s the lab for seismic we do it in the virtual world. And then when we find out that something works, we can build models and fields and geology. We can go out and try it for real.” .

David Eyton, BP’s Group head of research and technology, said in an interview at the Offshore Technology Conference in Houston 2014.

Setting the Scene for IOR/EOR

“BP’s also planning on expanding a new water-flooding technique across its offshore

• portfolio. One of BP’s big “ah-hah” moments came two decades ago when it discovered that

injecting fresh water into offshore oil fields inexplicably harvested more oil. High-salinity sea water – the kind of water close at hand at offshore drilling sites – doesn’t get the job done as well. When we realized that fresh water in some occasions helps you to get more oil out, we set

• ut almost for 20 years to figure out why is that. That insight and advancements in nano-

scale measurement techniques paved the way for BP to deploy its first low-salinity water- injection technology to an oil field 200 miles north of the UK mainland. The industry is still in the early stages of understanding the full potential of advanced chemistry applied to water-flooding in oil and gas reservoirs. Our focus is on low-cost techniques with water flooding to get more oil out. Low-salination is well known. But actually, all the money we’re now spending on research and development in this area is on things that nobody yet knows about. There’s a lot more going on behind the scenes.”

David Eyton, BP’s Group head of research and technology, said in an interview at the Offshore Technology Conference in Houston 2014.

Status IOR/EOR globally (World Oil Official publ. 2010, page 64)

Number of Projects Worldwide

Thermal Chemical HC Gas CO2 Others

Production (KB/d)

Figure 2. Worldwide EOR Production Rates

Status IOR/EOR globally (World Oil Official publ. 2010, page 68)

SAGD

IOR/EOR Maturity and deployment globally

Gas injection Steam Polymer

Commercial

Microbial

Risks

Surfactant

Smart water flooding Pilots

In situ combustion

Hybrids

R&D Foam

Maturity Technology Deployment

General integrated work process for economic evaluation applied to IOR/EOR projects

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Integrated Development Assessment

Results Natural flow Reserves / Resources – Drilling and Completion plans Chemical Artificial lift Water flooding Thermal Investment/ Cash flow/Value Secondary Recovery Tertiary Recovery Solvent

PROBABILITY RESERVES PRODUCTION TIME Prod.start

Pressure maintenance Gas – Water injection Cash flow CAPEX/OPEX/DRILLEX Other Nitrogen CO2 Air SAGD Bacteria Etc. Primary Recovery

Resource classes NPD Definition SEC SPE/WPC/ AAPG Historical production 1 Reserves in production Developed Reserves Discovered Commercial (Reserves) 2 Reserves with an approved plan for development and production Undeveloped Reserves 3 Reserves which the licensees have decided to recover 4 Resources in the planning phase (approval within 4 years) Technical Resources Discovered Uncertain Commerciality (Contingent Resources) 5 Resources whose recovery is likely, but not clarified 6 Resources whose recovery is not likely 7 Resources that not have been evaluated, i.e. new discovery 8

• Prospect. Not drilled

Undiscovered 9 Lead

Resource Group Classification on NCS

Definitions based on Norwegian Petroleum Directorate (NPD). SPE-PRMS texts can be substituted.

A A A A A A A

A – Additional Resources from IOR/EOR

UN Categories and Classes

F axis categories E axis categories G axis categories

Performance based

Probable

volumetric uncertainty

1.exploration

• 2. discovery
• 3. appraisal
• 4. early

development

• 5. mature

development

• 6. late

development

Project maturation pipeline

Volumetric based

Prospective Resources Contingent Resources Reserves 3P Possible 2P 1P Proved

time

High 3C Best 2C 1C Low

2007 K-2 Drill K-9 D&C K-8 D&C K-5 Interv. P9 D&C P-17AH D&C

RIG B

RIG SCHEDULE

Typical Model Elements and Schedule Challenges

• 0,13

• 0,2
• 0,1

EXISTING WELLS NEW WELLS

FIELD AREA A

• CAPACITIES
• REGULARITY
• SERVICE AVAILABILITY
• ETC

IOR/EOR PROJECTS

PUMP INSTALL.

RIG A

2007 P-7 P&A P-8 D&C P-12 WO P-6 Interv. P-7A D&C P-11AH Drill RIG SCHEDULE

?

PROSPECT

PIPELINE CAPACITIES

EXISTING WELLS NEW WELLS

FIELD AREA B

• CAPACITIES
• REGULARITY
• SERVICE AVAILABILITY
• ETC

IOR/EOR PROJECTS K-2 PROCESS MOD. DISCOVERY

?

PROSPECT

MAX BASE MIN P100 P0 P90 Mean P10

Development Project Uncertainties (offshore example)

Risks Uncertainties Scenarios

Discovery Prospect CAPEX

• Dev. plan

Economics OPEX

Main Project

# production wells? Fault location? Seismic reinterpretation? Cost per well? CAPEX? OPEX? Pipeline capacity? WOC? Communication between layers? GOC? Production rate per well? Drilling rig(s)? Petrophysical Challenges ? Revise reservoir model? Pre-drilled wells? Injection wells? Oil price? Regularity? Cost per template?

Additional Projects

Drill exploration well? Processing capacity/phasing ? # templates? Pipeline cost? Reserves Production Profiles?

Field

Development/ redevelopment solution? Depth conversion? Schedule Appraisal well(s)? New Seismic ?

DISC A IOR A FIELD B EOR A PROS A PROS A

Key elements in mature field development

NEW PROJECTS

2007 2030

NEW WELLS EXISTING WELLS

2007 2030 2007 2030

FIELD A

WELL TRIGGER A WELL TRIGGER B SCHEDULE ITEM B SCHEDULE SCHEDULE ITEM C SCHEDULE ITEM D SCHEDULE ITEM E SCHEDULE ITEM F SCHEDULE ITEM G SCHEDULE ITEM A PROJECT TRIGGER A PROJECT TRIGGER B WELL TRIGGER C FIELD A

UPTIME DEFERMENTS ENVIRONMENTAL RISKS OPERATIONAL RISKS PROCESSING CONSTRAINTS PIPELINE CONSTRAINTS POLITICAL RISKS

CAPEX

• Fast-tracking
• Studies with clear purpose
• Focus on relevant risks
• Integrated teams

Integrated Petroleum Risk Management work approach

RISKS

Sub-Surface Production Drilling OPEX Schedule Commercial terms Fiscal terms Product prices

Integrated Project Development Work Process to screen and rank IOR/EOR alternatives – a consistent approach

Capacity Constraints Facilities & Wells, Schedule Oil and Gas Reserves / Resources Production Profiles CAPEX OPEX Tariff P&A Abandonment Cut

• ff

Cash flow Rock & Fluid Characteristics Rock Volume Parameters Recovery Factor Revenue Fiscal Regime Probability Plots Decision Trees Summary Tables Tornado Plots Time Plots

NPV Cash Flow PROBABILITY RESERVES PRODUCTION TIME Prod.start

Decision tree analyses for structuring

HIGHEST EMV

E E E’ Compare and rank Optimize and update

H G F

B C D E A

Projects

Analyses Compare and rank IOR/EOR alternatives

Drilling Campaign portfolio evaluation necessary to optimise production and recovery

W 1 W 4 W 3 W 6 W 2 W 5 W 2

Screening simulations of all well

• ptions to evaluate data quality –

check for Inconsistencies Well options to include pilot wells for IOR/EOR ? Simulations with several different portfolio scenarios (well projects) to optimise drilling campaign Several scenarios of wells for IOR/EOR projects Needs aggregation capability for each well scenario !

Timing of wells critical for all development economics !

Normally huge range from P10 to P90 estimates of number of wells and effect

• n production profiles

2-jan-12 4-apr-12 19-jun-12 29-aug-12 12-des-12 27-feb-13 25-mai-13 23-jul-13 26-aug-11 26-feb-12 18-jun-12 23-sep-12 28-jan-13 3-jun-13 8-sep-13 23-des-13 8-mar-14 11-mai-12 25-sep-12 20-jan-13 26-jun-13 22-nov-13 20-mar-14 28-jul-14 30-okt-14 22-jul-11 13-nov-11 2-jan-12 8-mar-12 12-mai-12 25-jul-12 25-okt-12 23-nov-12 18-feb-13

A-52A A-26A A-2 A-33A A-46A A-19A A-7A A-21 A-30B 1-apr-11 31-mar-12 31-mar-13 31-mar-14 31-mar-15 A-52A A-7A A-19A A-26A A-30B A-46A A-33A A-2 A-21

P10 Mean P90 Op-2010 plan

W1 W2 W3 W4 W5 W6 W7 W8 W9 W1 W7 W6 W2 W9 W5 W4 W3 W8

Well planning and decision making: Status and future Actual Troll 6 branch well overlain picture of Rio de Janeiro

Multiple reservoir targets defined Single wells, Bi-laterals, Advanced multilateral wells How many branches in the future: 7 now and 25+ in 2030 ?

IOR/EOR Project Challenges to obtain acceptable economic results

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Integrated Development Assessment

Results Natural flow Reserves / Resources – Drilling and Completion plans Chemical Artificial lift Water flooding Thermal Investment/ Cash flow/Value Secondary Recovery Tertiary Recovery Solvent

PROBABILITY RESERVES PRODUCTION TIME Prod.start

Pressure maintenance Gas – Water injection Cash flow CAPEX/OPEX/DRILLEX Other Nitrogen CO2 Air SAGD Bacteria Etc. Primary Recovery

Primary, Secondary and Tertiary recovery

PRODUC TION RESERVES PROBABILITY

Cash flow CAPEX/OPEX/DRILLEX

Well Established DECISION-MAKING PROCESS Primary – Secondary Recovery DG1 DG2 DG3 DG4 DG5

Economics

• il

gas

• il

gas

Rules Regu- lations Tax Market

Cost elements Economic analysis

Integrated work approach

Geology Geophysics Reservoir engineering Drilling engineering Field Development

Commercial premises Production

CAPEX OPEX DRILLEX TARIFF ABANDM. CAPEX OPEX DRILLEX TARIFF ABANDM.

Screening of Subsurface criteria

– Geoscience, petrophysical: rocks, liquids, gases – Reservoir technical: injection of gases & liquids, production delta performance

• STOOIP, RECOVERY FACTOR, RESERVES, PRODUCTION PROFILES

IOR/EOR well planning

– Existing wells, New wells for production and injection

• NUMBER, TYPE OF WELLS, SCHEDULE - DRILLEX

Facility modifications, new technology

– Platform, subsea, pipeline modifications – Process and transport enhancements by new technology

• CAPEX, OPEX

Combination of several fields, area planning

– Synergies between fields with similar possibilities for EOR methodology – Area plan to optimise technical and economic solutions over field life time

• CAPACITY CONSTRAINTS, TARIFFS , LOGISTICS, OTHER SERVICES ?

Qualification of important IOR/EOR data for economic evaluation for one field, group of fields – operational area

Cash flow CAPEX/OPEX/DRILLEX

Stepwise Implementation of Tertiary recovery: Laboratory, Field Pilots, Production in Phases?

PRODUCTION RESERVES PROBABILITY

Cash flow CAPEX/OPEX/DRILLEX

Pilots Phase 2 (full field) Phase 1(part of field) Stepwise implementation and integration of R&D, technology, staff to move projects from laboratory scale tests, single well tests, pilot tests and on to full –field scale implementation reduces risks, but add time and complexity to decision process and reduce NPV.

TUBING FLOWLINE

Pwf PR

Without pump

Ps Pwh

With pump Booster pump PRESSURE

RESERVOIR

MPC

Typical IOR/EOR evaluation applied on Booster Pump Case

Pressure profile with and without booster pump.

Expected project NPV: 5,55 mill USD

Technical recov. Res (10^6 Sm3) Service intervent. - Pump module (Mill USD) Power consumption (Mill USD/year) Service intervent - SCM/PVR (mill USD) Hydrate prevention/ Auxiliary fluids (mill USD/Y)

Typical IOR/EOR evaluation applied on Booster Pump Case

Development of Discovery with IOR/EOR ( Project)

Oil production – Mean profiles

P10 Mode P90

STOIIP 14 MSm3 20 MSm3 40 MSm3 Recovery factor Rf 21 % 30 % 45 % Additional EOR Rf * 3 % 10 % 15 %

* Negative correlated

Effect of Fiscal Regime

Net cash flow after tax for Project; before tax for Discovery/EOR

New 2013 NCS tax rates vs. Pre 2013 tax rates

NPV distribution with full uncertainty

Mean Mode P10 P90 Unit Tax consolidation post 2013 5655 4095 2683 9242 10^6 NOK Tax consolidation pre 2013 5826 4704 2863 9372 10^6 NOK

< 2013 2013 Company tax 28 % 27 % Special tax 50 % 51 % Allowance 130 % 122 %

Tax changes and EOR projects

• New tax rates and reduced uplift increase downside risk in general
• EOR projects, will normally have higher uncertainty than initial

development phase

• Low return on capital combined with higher risk will not be an

incentive to invest in EOR projects on a stand alone basis

• If the oil company goes out of tax position during the initial

development phase, this increases the downside risk of the EOR project

DPIR: Discounted Profit to Investment Ratio Tax calculated on Discovery and EOR project

– Overview of total project portfolio economics NPV, EMV for ranking of all projects – Resource/ reserve/production/revenue/CAPEX/OPEX for long term forecasting scenarios – Ranking of IOR/EOR projects within the portfolio – Area plan to optimise technical and economic solutions of IOR/EOR over field life time – Initial field development planning of IOR/EOR projects for Stepwise decisions from laboratory tests, pilots in field to full field deployment to establish realistic project implementation schedule – Comparison between IOR/EOR projects within different fiscal regimes – Comparison with NPV, EMV on conventional projects including drilling of new, more advanced development wells and exploration/appraisal wells for tie in of new satellites

Corporate Project portfolio

Rank IOR/EOR projects and compare with conventional projects

EOR investment projects are complex and challenging:  Decision process require high level of expertise in a large number of technical, economic

and management professions to perform an integrated economic modelling with advanced uncertainty/risk handling to satisfy management. Stepwise implementation and integration of R&D, technology, staff to move projects from laboratory scale tests, single well tests, pilot tests and on to full –field scale implementation reduces risks, but add time and complexity to decision process and reduces NPV.

 EOR compete with Primary development and IOR

• Improved reservoir modelling combined with infill drilling, improved injection of gas

and water, and upgrade of process ( capacity, pumps, compressor) adds “easy” reserves.

• Several new discoveries for tie back on most fields at the NCS.

 Effects of fiscal regime

• So far no special incentives regarding IOR/EOR in the fiscal regime for NCS.
• Latest changes in fiscal regime has a negative effect.

Summary

• To achieve more EOR projects it is necessary to plan these projects in an early

phase, when developing the Primary – Secondary recovery. With simultaneous maturation of EOR knowledge from reservoir, drilling, process, transport and logistics can be directly applied.

• Coordination of field operations can probably increase EOR projects, in

particular in business areas where it is similar drainage strategies and technical infrastructure solutions.

• Companies need to specialise in building capabilities on certain types of EOR

projects to be able to successfully implement EOR projects economically. This will require both technical, economic and management top expertise.

• Selective Fiscal incentives can probably boost the activity / production from

EOR.

Future changes?

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