ipres force eor presentation 26th may 2014

8/17/2019 IPRES Force EOR Presentation 26th May 2014

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• 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

Web Page: www.ipres.com

Product Information: [email protected]

Software Support: [email protected]


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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.


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“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.


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“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

out 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.


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

Number of Projects Worldwide

Thermal Chemical HC Gas CO2 Others

P r o d u c t i o n ( K B / d )

Figure 2. Worldwide EOR Production Rates


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

SAGD

IOR/EOR Maturity and deployment globally

Gas injection

Steam

Polymer Commercia l

Microbial

Risks

Surfactant

Smart water

flooding

Pi lots

In situ

combustion

Hybrids

R& D

Foam

Maturity

T e c h n o l o g y D e p l o y m e n t


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General integrated work process for economic

evaluation applied to IOR/EOR projects





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Integrated Development Assessment

R e s u l t s

Natural flow

Reserves / Resources – Drilling and Completion plans

Chemical

Artificial lift

Water

flooding

Thermal

Investment/ Cash flow/Value

Secondary

Recovery

Tertiary

Recovery

Solvent

P R O B A B

I L I T Y

RESERVES

P R O D U C T I O N

TIME

Prod.start

Pressure

maintenance

Gas – Water

injection

Cash flow

CAPEX/OPEX/DRILLEX

Other

Nitrogen

CO2Air

SAGD

Bacteria

Etc.

Primary

Recovery


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Resource

classes

NPD

Definition SEC SPE/WPC/AAPG

0 Historical production

1 Reserves in productionDeveloped

ReservesDiscovered

Commercial

(Reserves)

2 Reserves with an approved plan for development and productionUndeveloped

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 drilledUndiscovered

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


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UN Categories and Classes

F axis

categories

E axis

categories

G axi s

categories


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Performance based

Probable v o l u m e t r i c

u n c e r t a i n t y

1 . e x p l o r a t i o n

2 .

d i s c o v e r y

3 . a p p r a i s a l

4 .

e a r l y

d e

v e l o p m e n t

5 . m a t u r e

d e v e

l o p m e n t

6 .

l a t e

d e v e l o

p m e n t

Project maturation pipeline

Volumetric based

ProspectiveResources

ContingentResources Reserves

3P

Possible

2P

1PProved

time

High

3C

Best 2C

1C

Low


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2007

K-2 Drill

K-9 D&C

K-8 D&C

K-5 Interv.

P9 D&C

P-17AH D&CRIG B

RIG SCHEDULE

Typical Model Elements

and Schedule Challenges 0,001,002,00

3,00

4,00

5,00

6,00

200720082009201020112012201320142015201620172018201920202021202220232024202520262027202820292030

Year

O i l ( M Project

Newwell

Existing

0,72

0,44

0,40

0,13

0,13

-0,13

0,11

0,10

0,10

0,10

-0,2 -0,1 0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8

MidwayProb.D isc.[Reserves]

C-structure[ Reserves]

MProb.Disc.|Midwa yDisc.[Reserves]

LitProb.Disc.|Mid wayDisc.[R eserves]

Midway[ Reserves]

LitProb.Disc.|Mid wayDry [Reserves]

ProductionProfilesC-stru cturePlateauprodu ction

rate[Production]

Lit OP1Drillingstartdate[Drilling]

Lit[Reserves]

M OP1Durationof drilling[Drilling]

Sensitivity Coefficients

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

PIPELINECAPACITIES

EXISTING WELLS

NEW WELLS

FIELD AREA B-CAPACITIES-REGULARITY

-SERVICE AVAILABILITY-ETC

IOR/EOR PROJECTS

K-2

PROCESS MOD.

DISCOVERY

?

PROSPECT

0,00

0,50

1,00

1,50

2,00

2,50

3,00

3,50

4,00

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Year

O i l ( M S m 3

MAX

BASE

MIN

P100

P0

P90

Mean

P10


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Development Project Uncertainties (offshore example)

Risks Uncertainties Scenarios

DiscoveryProspect CAPEXDev. plan EconomicsOPEX

Main Project

# production

wells?

Faultlocation?

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 ?


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DISC A

IOR A

FIELD B

EOR A

PROS A

PROS A

Key elements in mature field development

NEW PROJECTS

2007 2030

NEW WELLSEXISTING 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 APROJECT TRIGGER A

PROJECT TRIGGER B

WELL TRIGGER C

FIELD A

UPTIME

DEFERMENTS

ENVIRONMENTAL RISKS

OPERATIONAL RISKS

PROCESSING CONSTRAINTS

PIPELINE CONSTRAINTS

POLITICAL RISKS


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CAPEX

- Fast-tracking

- Studies with clear purpose

- Focus on relevant risks

- Integrated teams

Integrated Petroleum Risk Management work approach

RISKSSub-Surface

Production

Drilling

OPEX

Schedule

Commercial

terms

Fiscal

termsProduct

prices


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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

off

Cash flow

Rock & FluidCharacteristics

Rock VolumeParameters

RecoveryFactor

Revenue

Fiscal

Regime

Probability

Plots

Decision

Trees

Summary

Tables

Tornado

Plots

Time

Plots NPV

Cash Flow

P R O B A B I L I T Y

RESERVES

P R O D U C T I O N

TIME

Prod.start


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Decision tree analyses

for structuring

HIGHEST

EMV

E E

E’

Compare

and rank

Optimize and

update

H

GF

B

C

D E

A

Projects

Analyses

Compare and rank

IOR/EOR alternatives


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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

options 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 eachwell scenario !


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Timing of wells critical for all development economics !Normally huge range from P10 to P90 estimates of number of wells and effect

on production profiles

02.jan.12

04.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

03.jun.13

08.sep.13

23.des.13

08.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.1102.jan.12

08.mar.12

12.mai.12

25.jul.12

25.okt.1223.nov.12

18.feb.13

A-52A A-26A A-2 A-33A A-46A A-19A A-7A A-21 A-30B

01.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


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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 wellsHow many branches in the future: 7 now and 25+ in 2030 ?


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IOR/EOR Project Challenges to obtain

acceptable economic results





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Integrated Development Assessment

R e s u l t s

Natural flow

Reserves / Resources – Drilling and Completion plans

Chemical

Artificial lift

Water

flooding

Thermal

Investment/ Cash flow/Value

Secondary

Recovery

Tertiary

Recovery

Solvent

P R O B A

B I L I T Y

RESERVES

P R O D U C T I O N

TIME

Prod.start

Pressuremaintenance

Gas – Water

injection

Cash flow

CAPEX/OPEX/DRILLEX

Other

Nitrogen

CO2Air

SAGD

Bacteria

Etc.

Primary

Recovery


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Primary, Secondary and Tertiary recovery

P R O D U C

T I O N

RESERVES

P R

O B A B I L I T Y

Cash flow

CAPEX/OPEX/DRILLEX

Well Established DECISION-MAKING PROCESS Primary – Secondary Recovery

DG1 DG2 DG3 DG4 DG5


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Economics

oil

gas

oil

gas

Rules

Regu-

lations

Tax

Market

Cost elements

Economic analysis

Integrated work approach

Geology

Geophysics

Reservoir

engineering

Drillingengineering

Field

Development

Commercial

premisesProduction


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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


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Stepwise Implementation of Tertiary recovery:

Laboratory, Field Pilots, Production in Phases?

P R O D U C T I O N

RESERVES

P R O B A B I L I T Y

Cash flow

CAPEX/OPEX/DRILLEX

PilotsPhase 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.


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T UB I N G

F L OWL I NE

Pwf

PR

Withoutpump

Ps

Pwh

With pump

Booster

pump

PRESSURE

RE

S E RV OI R

MPC

Typical IOR/EOR evaluation applied on Booster Pump Case

Pressure profile

with and without

booster pump.


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Expected project NPV: 5,55 mill USD

Technical recov.

Res (10^6 Sm3)

Service intervent. -

Pump module (MillUSD)

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


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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


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Effect of Fiscal RegimeNet cash flow after tax for Project; before tax for Discovery/EOR


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New 2013 NCS tax rates vs. Pre 2013 tax ratesNPV 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 %


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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


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– 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 portfolioRank IOR/EOR projects and compare with conventional projects


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EOR investment projects are complex and challenging:

Decision process require high level of expertise in a large number of technical, economicand 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


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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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ipres force eor presentation 26th may 2014

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