eor and co2 disposal – economic and capacity potential in

1SINTEF Petroleum Research

EOR and CO2 disposal – economic and capacity potential in the North Sea

Torleif Holt and Erik LindebergSINTEF Petroleum Research, Trondheim Norway

The 4th Trondheim Conference on CO2 Capture, Transport and Storage

October 16 - 17 2007, Trondheim Norway

Acknowledgements: This work forms a part of the BIGCO2 project, performed under the strategic Norwegian research program Climit.

The authors acknowledge the partners: StatoilHydro, GE Global Research, Statkraft, Aker Kværner, Shell, TOTAL, ConocoPhillips, ALSTOM, the Research Council of

Norway and Gassnova for their support


Contents

Field experience from tertiary CO2 injection projectsPredictions of CO2 EOR and storage in the North Sea (N and UK)

technical economical modelinput parameters scenariosmain results

Conclusions


Results extracted from SINTEF’s data base with 120 CO2 EOR projects (pilots and full field flooding)

mostly located in the Permian Basin

Field experience from tertiary CO2 injection


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72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99

Year

Num

ber o

f pro

j sta

rted

Start-up of CO2 injection projects


Incremental oil recovery vs. permeability and porosity

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1 10 100 1000 10000

Permeability (md)

Incr

emen

tal r

ecov

ery

(% O

OIP

)

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60

70

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Porosity (% PV)In

crem

enta

l rec

over

y (%

HC

PV)


Incremental oil recovery vs. temperature and oil gravity

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0 50 100 150

Reservoir temperature

Incr

emen

tal r

ecov

ery

(% O

OIP

)

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Oil gravity (deg API)

Incr

emen

tal r

ecov

ery

(% O

OIP

)


Incremental oil recovery vs. slug size

R2 = 0.11

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0 50 100 150 200Slug size, % HCPV

Incr

emen

tal o

il, %

of O

OIP

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0.3 1.1 1.9 2.6 3.4 More

Net efficiency of CO2 utilisation, tonne CO2/Sm3 oil

Freq

uenc

y


Summary of literature study

Average quantity Sandstone reservoirs Carbonate reservoirsIncremental oil (% OOIP) 12.3 17.3

Gross CO2 util.(tonne/Sm3) 3.1 4.0

Net CO2 utilisation (tonne/Sm3) 1.9 2.0

Temperature (°C) 67 51

Reservoir depth (m) 1844 1705

Pressure (bar) 194 173

Porosity (% PV) 23 12

Permeability (md) 570 22

Oil density (°API) 35.2 34.6

CO2 density 641 730


Predictions of CO2 EOR in the North Sea

technical economical modelpipeline transport modelEOR modeleconomic model

scenarios19 Norwegian and 30 UK oil fields in the database

will be expanded with Danish fields


Features of the EOR model

A simple model to predict the incremental oil production due to CO2-injection after water flooding depending on the state of the reservoirBased on a large number of reservoir simulations with varying process- and geological parametersDeveloped for continuous CO2 injection onlyAssumes that water and CO2 are injected at the same and constant flow ratesCO2 displaces oil miscibleRequires a few reservoir specific input parameters Calculates functions for oil, incremental oil, water and gas production during CO2 injection for each field


Example of production profiles calculated by the EOR module

The predicted oil recovery profile is matched to historic values by use of the two geological fit parameters (heterogeneity exponent, vertical permeability multiplicator)

Brage

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Years of production

Prod

uctio

n ra

tes

Oil (mill. Sm3/year)EOR oil (mill. Sm3/year)Water (mill. Sm3/year)Gas (bill. Sm3/year)field data




Ula

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Years of production

Prod

uctio

n ra

tes

Oil (mill. Sm3/year)

EOR oil (mill. Sm3/year)

Water (mill. Sm3/year)

Gas (bill. Sm3/year)Field data




Murchison

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Years of production

Prod

uctio

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tes

Oil (mill. Sm3/year)EOR oil (mill. Sm3/year)Water (mill. Sm3/year)Gas (bill. Sm3/year)Field data




Ninian

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Years of production

Prod

uctio

n ra

tes

Oil (mill. Sm3/year)

EOR oil (mill. Sm3/year)

Water (mill. Sm3/year)

Gas (bill. Sm3/year)

Field data


The technical- economical model

CO2

Oil reservoirs

Aquifers

Export terminalMain pipeline infrastructure

CO2 from industrial point sources is collected, compressed and fed into main pipeline.

CO2 is transported through the main pipeline and distributed to oil reservoirs and aquifers

CO2 is transported to the deposition sites through branch lines. The oil producers buy CO2 according their needs. Excess CO2 is deposited in aquifers

Branch pipelines


The technical- economical model

The model can be used to construct specific deposition scenarios for fields in the North SeaA constant amount of CO2 is deposited during the lifetime of a scenario, excess CO2 is injected into unspecified aquifersBreak through CO2 is re-injected into the reservoirsThe model calculates incremental oil recovery and stored CO2 in the oil reservoirs and aquifersEach EOR project in the scenario runs as long as the net cash flow is positive

incomes: EOR oil (the incremental oil only)costs: CO2, investments, operating costs

In the figures presented here calculates a value for CO2 that gives a zero NPV for all the EOR projects and aquifer deposition at the specified rate of return


Parameters used for economic modelling

Variable economic parameters value unitWell cost 30

510

25

25

3

5

0.07

7

0

variable

CO2 transport cost 3.8 USD/tonne

4.0

Modification of oil production system USD/(bbl/day)

Engineering costs % equipment costs

Contingency costs % equipment costs

Offshore factor

Running and maintenance % of equipment costs

Energy compressor USD/kWh

Discount rate %

mill. USD/well

Net present value

Oil price USD/bbl

USD

Aquifer deposition costs USD/tonne


A CO2 deposition scenario

Includes 19 Norwegian and 30 UK North Sea oil fields and unspecified aquifersTotal injection rate is 178 million tonnes CO2/yearProject lifetime is 40 (or 30) yearsThe scenario is not optimised

Results:Deposition profilesEOR production profilesKey economic figuresValues for CO2


CO2 storage profiles in oil fields60 USD/bbl, 40 years injection

Norwegian fields UK fields

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2013 2018 2023 2028 2033 2038 2043 2048

Year

CO

2 sto

red

(mill

. ton

nes/

year

)

Valhall

Ekofisk

Eldfisk

Ula

Gyda

Balder

Oseberg Øst

Oseberg Sør

Veslefrikk

Snorre B

Sygna

Tordis

Vigdis

Statfjord Øst

Statfjord Nord

Statfjord Brent

Gullfaks

Brage

Snorre

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90

2013 2018 2023 2028 2033 2038 2043 2048Year

CO

2 sto

red

(mill

. ton

nes/

year

)

ToniTiffanyThisleThelmaTernTartanScottScapaRob RoyPiperOspreyNinianNelsonMurchisonMillerKittiwakeHeatherFulmarFortiesFifeEiderDunlinDunbarCormorant NorthClydeClaymoreBrae CentralBerylBanffArbroath


Incremental oil production60 USD/bbl, 40 years injection

Norwegian fields UK fields

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2013 2018 2023 2028 2033 2038 2043 2048

Year

EOR

oil

(mill

. Sm

3)

Valhall

Ekofisk

Eldfisk

Ula

Gyda

Balder

Oseberg Øst

Oseberg Sør

Veslefrikk

Snorre B

Sygna

Tordis

Vigdis

Statfjord Øst

Statfjord Nord

Statfjord Brent

Gullfaks

Brage

Snorre 0

50

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150

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350

2013 2018 2023 2028 2033 2038 2043 2048

Year

EOR

oil

(mill

. Sm

3 )

ToniTiffanyThisleThelmaTernTartanScottScapaRob RoyPiperOspreyNinianNelsonMurchisonMillerKittiwakeHeatherFulmarFortiesFifeEiderDunlinDunbarCormorant NorthClydeClaymoreBrae CentralBerylBanffArbroath


Summary of EOR project performance60 USD/bbl, 40 years project lifetime

Item Norway UK Total

Investment costs (mill. USD) 28400 30832 59232

Operating costs (mill. USD/year) 1104 1234 2338

Total oil (mill. Sm3) 2664 2054 4718

Oil recovery (% OOIP) 56.7 67.1 60.8

EOR oil (mill Sm3) 375 312 687

Incremental oil recovery (% OOIP) 8.0 10.2 8.8

Total stored CO2 (mill. ton) 3373 3881 7254Stored CO2 in oil reservoirs (mill. ton) 1479 853 2332


Incremental oil recovery for tertiary CO2 injection

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Norway UK Word averagesandstone

World averagecarbonate

Incr

emen

tal o

il (%

OO

IP)


The value of CO2

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Oil price (USD/bbl)

CO

2 val

ue (U

SD/to

n)

US mid west (Taber 1994)

North Sea 30 yearsNorth Sea 40 years


CO2 balance for 19 Norwegian CO2 EOR projects

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Theorectical (oilvolume repalcement)

From combustion ofEOR oil and gas

Stored during projectperiod

Mill

ion

tonn

es C

O2

From EOR gasFrom EOR oil

CO2 stored in aquifers

CO2 stored in oil reservoirs


The time-window for EOR projects

Future operation costs for North Sea oil reservoirsSource: www.Petoro.no

The implementation of EOR projects must be done before operation of the field becomes unprofitable For many fields this time limit may be reached before a CO2infrastructure is established in the North SeaThe benefits of CO2injection may therefore be lost


Conclusions

CO2 based EOR can contribute to reduce GHG emissionsThe use of CO2 for EOR gives a value to CO2 that can cover parts of the capture and deposition costsThe storage potential for CO2 in North Sea oil reservoirs in in the order of two billion tonnesThe EOR potential is estimated to 600 to 700 mill. Sm3

These potentials can only be realised if a CO2 infrastructure to the North Sea oil reservoirs is established within a few years and if the oil fields are not permanently shut down in the meantime

eor and co2 disposal – economic and capacity potential in

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