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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]
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
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.
Status IOR/EOR globally (World Oil Official publ. 2010, page 64)
Number of Projects Worldwide
Thermal Chemical HC Gas CO2 Others
Pro
du
ctio
n (
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
Te
ch
no
log
y D
ep
loym
en
t
General integrated work process for economic
evaluation applied to IOR/EOR projects
Web Page: www.ipres.com
Product Information: [email protected]
Software Support: [email protected]
Integrated Development Assessment R
es
ult
s
Natural flow
Reserves / Resources – Drilling and Completion plans
Chemical
Artificial lift
Water
flooding
Thermal
Investment/ Cash flow/Value
Secondary
Recovery
Tertiary
Recovery
Solvent
PR
OB
AB
ILIT
Y
RESERVES
PR
OD
UC
TIO
N
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
0 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
vo
lum
etr
ic
un
ce
rta
inty
1. e
xp
lora
tio
n
2.
dis
co
ve
ry
3.
ap
pra
isa
l
4.
ea
rly
de
ve
lop
me
nt
5.
ma
ture
d
eve
lop
me
nt
6.
late
d
eve
lop
me
nt
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 0,00
1,00
2,00
3,00
4,00
5,00
6,00
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
Oil (
MS
m3)
Project
New well
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
Midw ayProb.Disc.[Reserves]
C-structure[Reserves]
MProb.Disc.|Midw ayDisc.[Reserves]
LitProb.Disc.|Midw ayDisc.[Reserves]
Midw ay[Reserves]
LitProb.Disc.|Midw ayDry[Reserves]
Production Profiles C-structurePlateau production
rate[Production]
Lit OP1Drilling start date[Drilling]
Lit[Reserves]
M OP1Duration of 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
PIPELINE
CAPACITIES
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
Oil (
MS
m3)
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
off
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
PR
OB
AB
ILIT
Y
RESERVES
PR
OD
UC
TIO
N
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
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 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
on 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
Web Page: www.ipres.com
Product Information: [email protected]
Software Support: [email protected]
Integrated Development Assessment R
es
ult
s
Natural flow
Reserves / Resources – Drilling and Completion plans
Chemical
Artificial lift
Water
flooding
Thermal
Investment/ Cash flow/Value
Secondary
Recovery
Tertiary
Recovery
Solvent
PR
OB
AB
ILIT
Y
RESERVES
PR
OD
UC
TIO
N
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
PR
OD
UC
TIO
N
RESERVES
PR
OB
AB
ILIT
Y
Cash flow
CAPEX/OPEX/DRILLEX
Well Established DECISION-MAKING PROCESS Primary – Secondary Recovery
DG1 DG2 DG3 DG4 DG5
Economics
oil
gas
oil
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 OPEXDRILLEX TARIFF ABANDM.CAPEX OPEXDRILLEX 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? P
RO
DU
CT
ION
RESERVES
PR
OB
AB
ILIT
Y
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.
TU
BIN
G
FLO
WLIN
E
Pwf
PR
Without
pump
Ps
Pwh
With pump
Booster
pump
PRESSURE
RE
SE
RV
OIR
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?
