-53-1-Nagy

115Arch. Min. Sci., Vol. 53 (2008), No 1, p. 115–124

STANISLAW NAGY*, ANDRZEJ OLAJOSSY*

ECONOMIC ANALYSIS OF USE OF THE EARLY APPLICATION CO2 AND CO2/N2-EOR TECHNOLOGY IN POLAND

ANALIZA EKONOMICZNA TECHNOLOGII WTÓRNEJ EKSPLOATACJI ZŁOŻA ROPY NAFTOWEJ Z WYKORZYSTANIEM CO2 ORAZ CO2/N2 W POLSCE

Enhanced oil recovery methods are applied more frequently nowadays, mainly because of economic reasons. The classic waterfl ooding methods that aim to maintain the reservoir pressure are substituted or updated by the Water Alternating Gas technology (WAG).

It involves alternating injection of water and gas, or simultaneous injection of water into the bottom of reservoir and gas into the cap of it. The new intelligent methods (which use synergy of gathering and processing reservoir data, special injection systems and modifi cation of viscosity if injection fl uids) are very promising in new EOR. The application of high-nitrogen content gas, residue gases after methane-nitrogen separation processes, carbon dioxide or solutions containing carbon dioxide and nitrogen are considered in terms of the oil recovery effi ciency, defi ned as obtaining of a maximal depletion during twenty years of exploitation. For the selected small oil reservoir in the Polish Lowland, it was performed model research with usage of a pseudo-compositional simulator. Various aspects of gas injection concer-ning increasing of the reservoir pressure and increase of recovery has been analyzed. Presented results show possibility to increase of recovery factor from 11% and 36% up to 53/56% in case of CO2/N2 and CO2 EOR. The presented results are promising and show potential possibilities of rising oil recovery up to 60% for average oil price higher than 40 $ per bbl.

Keywords: Enhanced Oil Recovery, EOR, gas injection, nitrogen carbon dioxide sequestration, econo-mics

Metody wtórne w procesach eksploatacji ropy naftowej są stosowane coraz powszechniej w świecie, głównie z przyczyn ekonomicznych. Klasyczne metody nawadniania złoża celem podtrzymania ciśnienia złożowego są zastępowane lub uzupełniane poprzez technologię WAG – naprzemiennego zatłaczania wody i gazu, czy równoczesnego zatłaczania wody do spągu złoża i gazu do czapy oraz poprzez nowe „inteligentne” metody wykorzystujące synergistyczny efekt nowych technik zbierania i przetwarzania informacji oraz aplikacji specjalnych technologii zatłaczania gazu/wody do wyselekcjonowanych partii złoża, modyfi kacji mobilności płynów etc. Wykorzystanie gazu ziemnego zaazotowanego, azotu

* AGH UNIVERSITY OF SCIENCE & TECHNOLOGY, AL. MICKIEWICZA 30, 30-059 KRAKOW, POLAND, [email protected], [email protected]

116

odpadowego po separacji metanu i węglowodorów lub też roztworów zawierających dwutlenek węgla i odpadowy azot jest rozważane w aspekcie skuteczności procesu sczerpania złoża,. Dla przykładowego złoża ropy naftowej Niżu Polskiego wykonano badania modelowe z wykorzystaniem symulatora pseudo-kompozycyjnego. Analizowano różne aspekty zatłaczania gazu w celu podniesienia ciśnienia złożowego oraz zwiększenia wydobycia. Zaprezentowane wyniki są obiecujące i pokazują potencjalne możliwości zwiększenia od 11% i 36% do 56% wydobycia ropy naftowej ze złoża w przypadku użycia CO2/N2 i CO2 w porównaniu do przypadku eksploatacji pierwotnej złoża. Wykonano dla tych przykładów szereg analiz ekonomicznych, które zamieszczono w niniejszej pracy. Instalacje wspomagające mogą być opłacalne i mogą prowadzić do wzrostu końcowego współczynnika wydobycia ropy do 60% dla średniej ceny ropy na poziomie 40 USD.

Słowa kluczowe: wtórne metody eksploatacji ropy naftowej, EOR, zatłaczanie gazu, azot, sekwestracja dwutlenku węgla, ekonomika

1. Introduction

The increasing importance of carbon dioxide sequestration processes, together with possibilities of application of gases with low caloric values, and high prices of oil will favor attempts of “waste” CO2 exploitation from large energy sources (e.g. power plants) for EOR purposes (e.g. Nagy, Olajossy & Siemek, 2006; Krzystolik et al., 2007; Siemek et al., 2006; Nagy 2006; Nagy et al., 2006). Those methods include: injection of gases like CO2, N2 or the natural gas. The combination of CO2 sequestration and EOR processes seems to be an interesting idea, provided that carbon dioxide is available. Also large amounts of available gases of low-calorifi c values (or non-calorifi c ones (very high N2 content)) leads its application into the EOR processes. Another additional issue is the possibility of introducing of the new EOR technology called “Game Changer”, accepted by the Depart-ment of Energy (DOE U.S.A.) (Kuuskraa et al., 2006). The aforementioned technologies allow increasing the total recovery factor to the level of 60-80% (Kuuskraa et al., 2006).

2. „Game Changer” CO2-EOR Technology

In order to create the new technology, it was used the results of 82 projects con-cerning CO2 EOR analysis since 80’s (Kuuskraa et al., 2006). Those projects, which were realized in the USA, make use of four natural CO2 sources in Jackson Dome, McElmo Dome, Sheep Mountain and Bravo Dome. Most of those projects concern the Permian Basin and the Rocky Mountains. The total production of oil in those processes exceeds 250 thousands of barrels per day. The main purpose of the new technology is the recovery of signifi cant amount of oil which arises in a reservoir after fi nishing the primary exploitation process and the secondary exploitation process (waterfl ooding of reservoir). The remaining amount of oil, following those two processes, equals usually between 40-50% of original geological resources. The analysis of the present amount of resources exploitable in the context of increasing prices of oil allowed specifying the new economically affordable EOR-CO2 technology.

117

The old (classic) technology differs from an optimal system of CO 2 fl ooding mainly because of (Kuuskraa et al., 2006):

• Complex geological characterization• Inability to monitor the real course of the EOR process• Limited abilities of fl uid injection process steering

In particular, high price of CO2, lack of information and inability to control process led to the fact that too low amount of CO2 was injected into the reservoir (see the analysis of the amount of injected CO2 infl uence for Hadlow (1992)). Increasing of injected CO2 from 0.2 HCPV to 0.8 HCPV allows to boost the recovery coeffi cient by 20%. New laboratory research and computer modeling indicate that it is necessary to increase the amount of injected CO2 to 1.5-2 HCPV. For present economical conditions it is possible to increase exploitation from 8 to 15 times in comparison to the classic CO2-EOR technologies.

The old technological limits were not only involved with the small amount of CO2, but also with phenomena limiting CO2-oil contact (viscous fi ngering, low mobility ra-tio). Applied presently viscosity modifi ers (polymers) allow eliminating those negative issues. The additional possibilities of precise specifi cation of vertical distribution of horizontal permeability allow the selective choice of active (opened) layers that can be fl ooded. Those layers have lower permeability that results in lower risk of quick CO2 breakthrough between injection and production wells.

Applied new techniques of CO2-EOR process show that it is possible to increase the recovery coeffi cient in carbonate rocks even to 80% (Wilkinson et al., 2004). The new recommendation of DOE (Game Changer Document) specifi es a number of innovative hints to successfully develop “Game Changer CO2-EOR” technology.

1. Innovative project of injection and well’s placement2. Increasing of mobility and changing of viscosity3. Increasing of CO2 injection amount (above 1.5 HCPV)4. Diagnosis of the EOR process and its consequences:

• Creating of interdisciplinary experts teams• Usage of 4D seismic• Introduction of in situ measurements• Determination of information concerning saturation zones

The additional benefi t of such CO2-EOR projects, which will be realized in following years, is increasing of the storage capacity coeffi cient of CO2 during the process mainly due to reduction of saturation of oil and dissolution of parts of CO2 in bottom aquifer layers. The example of such a leading CO2-EOR project is the “Weyburn” one.

Apart from the “Game Changer CO2-EOR” technology applied mainly after fi nishing classic program of the reservoir fl ooding, it is possible to use the simplifi ed methodology. It involves omitting of reservoir waterfl ooding period and CO2 injection immediately after fi nishing of primary exploitation process. Such an approach concerns mainly increasing of economic effi ciency of the venture by shortening exploitation period.

118

3. Use of CO2 and CO2/N2 Mixture After Short Period of CO2 Injection

Recently Nagy& Olajossy (2007) show that use of N2/CO2 in injection stream after two years of injection of CO2 into oil reservoir may be possible. Nitrogen as a reservoir injection medium for EOR purposes is very easily accessible, which is a great benefi t. One of ways of obtaining nitrogen is its separation from hydrocarbons included in natural gas. When natural gas includes sulfi de it is necessary to initially remove sulfi de using standard methods (Clauss, MDE et al.).

However, in many cases natural gas recovered in wells does not contain sulfur. Even more profi table situation is when natural gas has additionally the limited nitrogen content of no more than 37% of its volume. In such cases, the authors have access to own modern technology of enriching natural gas with methane which exploits separated nitrogen. In this technology the vacuum pressure swing absorption (VPSA) technique could be ap-plied which uses itemized adsorbent (zeolite molecular sieve – ZMS). This sieve comes from a natural zeolite reservoir and was treated with ionic activation. The product of this installation is, apart from nitrogen, gas of high-methane content which is obtained under a high pressure (equal to the pressure at the well head). This gas can be directly transported to the gas net (Olajossy, 2007). The waste nitrogen can be compressed and inject into reservoir. The main problem is suffi cient quantity of nitrogen. In most cases the quantity is limited. In this case additional cryogenic installation to separate nitrogen from air has to be used. This may be economical questionable in some cases

4. Project of cash fl ow analysis (CF) of small oil fi eld with early application CO2 & CO2/N2 EOR

The techno-economical model integrates the EOR module for small fi eld (43° API, Initial Oil in Place (IGIP) is 25 mln Sm3

, with initial Gas Oil Ratio 170 m3/m3, satura-tion pressure about 250 bar, and initial pressure 260 bar) with economic quantities that enables calculations of cost and incomes related to CO2 enhanced oil recovery projects. One of the most important variables needed in an oilfi eld development decision, is the preliminary estimate of the number of wells required to exploit the reservoir. This best (“optimum”) number should satisfy both the technical and economic criteria. Four well has been designed for production process, and for scenario 2 & 3 additional four well located in the gas cap has been assumed after fi nishing the modeling process.

From the reservoir modeling (Nagy & Olajossy, 2007) information it is possible to calculate the EOR profi les for each reservoir scenario (primary restrictive scenario, primary forced scenario, EOR CO2 scenario, EOR CO2/N2 scenario). In the restrictive scenario only 11% of primary recovery is assumed in 25 years exploitation, 33% during “forced” production by 25 years, and 38% and 56% has been obtained from modeling for scenario 2 & 3 after 25 and 36 years of exploitation (EOR CO2). The scenario for

119

CO2/N2 gives 53% for 36 years. Total eight econonomic scenario has been calculated (two base scenario at oil price 40 and 60 $ per bbl, additional four scenarios with CO2 injection, and two scenarios with CO2/N2). The additional two scenario with CO2/N2 has been cancelled, because of high investment cost of CO2 pipeline used only two years in proposed project. From economical point of view – project, which may be technological effective is generally non profi table.

The CO2-EOR project economies are calculated based on incremental oil profi les (Campbell et al., 1991; Seba, 1998), investment costs, operating costs and costs for CO2 or CO2/N2 mixture. It is assumed that all gas is re-circulated after CO2 breakthrough, and the amount of imported CO2 to the fi eld is therefore reduced over time (about 40%). The cost for CO2 transportation is entered in the economy sheet based on the capacity of the main CO2 infrastructure (see Tab. 2-3). The capital cost of pipeline for 100 km with diameter 300 mm is below 25 mln $. The operating cost for transport of 1 CO2 tone is in range 4-6 $. In this project the upper limit has been selected (6 $ per tone). Cost of compression of CO2 is included, as well as cost of four injection wells. The all investment costs for a CO2 incremental oil project are calculated based on costing of:

1. tapping point for CO2 on the main transport line 2. branch CO2 pipeline to the fi eld3. modifi cation of oil production process 4. CO2/N2 compressors 5. injection gas drying plant 6. injection wells.

A starting time for the CO2 injections are entered (after 12 years), and investment and operating costs for each project are calculated based on the CO2 injection rates defi ned in the fi eld sheet. Most of the listed costs are capacity dependent, and the compressor costs are also dependent on the injection pressure. The running costs consist of:

1. CO2 costs2. operating costs for the process equipment 3. energy costs.

For the presented project economy expressed as yearly cash fl ow is calculated and the accumulated discounted net cash fl ow is found and show in the tables 1a-3b. The calculated IRR and NPV is given in the table 4. The plots of NPV & IRR for each 1-3 scenario is presented also in fi g. 1-3. Also at the early decision phase, none of the re-servoir and fi nancial variables involved are known to a high degree of certainty. The project stops in the year 25 (scenario 1) or 38 (scenario 2,3).

120TA

BLE

1a

Cap

ex/O

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and

Cas

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naly

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or sc

enar

io 1

a (b

ase

oil p

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(long

term

) 40

USD

per

bbl

, USD

(200

7))

TAB

LIC

A 1

a

Ana

liza

rent

ownośc

i pro

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u dl

a sc

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iusz

a „1

a” d

la uśr

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onej

cen

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py n

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wej

40

USD

za

baryłkę

Year

Star

t20

0820

0920

1020

1120

1220

1320

1420

1520

1620

2320

2420

2520

2620

2720

2720

2820

2920

3020

3120

32In

com

es99

00

00

00

00

00

00

00

00

00

00

Cap

ex–1

2000

00

00

00

00

00

00

00

00

00

00

Ope

x–1

46–2

261

–224

4–2

636

–264

8–2

649

–264

8–2

633

–260

2–1

88–1

31–1

19–2

08–3

10–3

31–3

54–3

65–3

51–3

38–3

34C

ash fl o

w

(afte

r tax

)–1

2000

933

–127

1–1

584

1133

1313

1312

1313

1123

1099

1997

1277

1198

1065

921

884

845

795

766

736

698

TAB

LE 1

b

Cap

ex/O

pex

and

Cas

h Fl

ow a

naly

sis f

or sc

enar

io 1

b (b

ase

oil p

rice

(long

term

) 60

USD

per

bbl

, USD

(200

7))

TAB

LIC

A 1

b

Ana

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rent

ownośc

i pro

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u dl

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a „1

b” d

la uśr

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onej

cen

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wej

60

USD

za

baryłkę

Year

Star

t20

0820

0920

1020

1120

1220

1320

1420

1520

1620

2320

2420

2520

2620

2720

2720

2820

2920

3020

3120

32In

com

es99

00

00

00

00

00

00

00

00

00

00

Cap

ex–1

2000

00

00

00

00

00

00

00

00

00

00

Ope

x–1

74–2

286

–226

1–2

733

–275

1–2

752

–275

1–2

730

–269

8–2

50–1

70–1

55–2

42–3

42–3

63–3

86–3

96–3

80–3

66–3

60C

ash fl o

w

(afte

r tax

)–1

2000

1,36

5–8

00–1

,271

2,63

12,

901

2,90

02,

901

2,61

62,

568

2,96

31,

881

1,75

91,

596

1,42

41,

377

1,32

81,

259

1,21

11,

161

1,10

4

TAB

LE 2

a

Cap

ex/O

pex

and

Cas

h Fl

ow a

naly

sis f

or sc

enar

io 2

a (b

ase

oil p

rice

(long

term

) 40

USD

per

bbl

, USD

(200

7))

TAB

LIC

A 2

a

Ana

liza

rent

ownośc

i pro

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u dl

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a „2

a” d

la uśr

edni

onej

cen

y ro

py n

afto

wej

40

USD

za

baryłkę

Cas

h fl o

wSt

art

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2041

2042

2043

2044

Inco

mes

3960

3678

3668

1329

613

297

1333

313

297

1319

312

040

1023

776

6257

9645

8637

3830

9026

0022

1578

4475

8473

3570

55C

apex

–120

000

00

00

00

00

00

0–2

7000

–800

00

00

00

00

Ope

x*–2

86–2

396

–239

5–3

106

–310

6–3

109

–310

6–3

099

–301

3–2

880

–269

0–4

28–3

3979

2–3

790

–375

4–3

726

488

508

526

547

121TA

BLE

2b

Cap

ex/O

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and

Cas

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io 2

b (b

ase

oil p

rice

(long

term

) 60

USD

per

bbl

, USD

(200

7))

TAB

LIC

A 2

b

Ana

liza

rent

ownośc

i pro

jekt

u dl

a sc

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a „2

b” d

la uśr

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onej

cen

y ro

py n

afto

wej

60

USD

za

baryłkę

Cas

h fl o

wSt

art

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2041

2042

2043

2044

Inco

mes

5886

5517

5502

1994

419

945

2000

019

946

1979

018

059

1535

511

492

8693

6879

5607

4635

3899

3323

1176

611

375

1100

210

583

Cap

ex–1

2000

00

00

00

00

00

00

–270

00–8

000

00

00

00

0O

pex

–382

–248

7–2

486

–343

9–3

439

–344

2–3

439

–342

8–3

314

–313

6–2

881

–573

–453

698

–386

7–3

819

–378

1–3

56–3

30–3

05–2

78C

ash fl o

w

(afte

r tax

)–1

2000

4572

2568

2556

1348

313

484

1352

613

485

1336

712

057

1001

270

8966

91–1

5681

3720

767

80–4

5899

0396

0793

2490

07

TAB

LE 3

a

Cap

ex/O

pex

and

Cas

h Fl

ow a

naly

sis f

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enar

io 3

a (b

ase

oil p

rice

(long

term

) 40

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per

bbl

, USD

(200

7))

TAB

LIC

A 3

a

Ana

liza

rent

ownośc

i pro

jekt

u dl

a sc

enar

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a „3

a” d

la uśr

edni

onej

cen

y ro

py n

afto

wej

40

USD

za

baryłkę

Cas

h fl o

wSt

art

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2041

2042

2043

2044

Inco

mes

6416

3681

3671

1331

013

313

1335

413

322

1322

212

069

1026

376

8258

1145

9937

4830

9826

0622

2178

5075

8973

4070

61C

apex

–120

000

00

00

00

00

00

0–2

7000

–800

00

00

00

00

Ope

x–4

09–2

396

–239

5–3

107

–310

7–3

110

–310

7–3

100

–301

5–2

881

–269

1–4

29–3

39–4

609

–919

1–9

154

–912

6–2

320

–230

1–2

282

–226

2C

ash fl o

w

(afte

r tax

)–1

2000

4980

1155

1148

8378

8381

8411

8388

8313

7448

6093

4157

4474

–174

36–2

860

–609

3–6

548

–690

551

3949

4447

5745

48

TAB

LE 3

b

Cap

ex/O

pex

and

Cas

h Fl

ow a

naly

sis f

or sc

enar

io 3

b (b

ase

oil p

rice

(long

term

) 60

USD

per

bbl

, USD

(200

7))

TAB

LIC

A 3

b

Ana

liza

rent

ownośc

i pro

jekt

u dl

a sc

enar

iusz

a „3

b” d

la uśr

edni

onej

cen

y ro

py n

afto

wej

60

USD

za

baryłkę

Cas

h fl o

wSt

art

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2041

2042

2043

2044

Inco

mes

9078

5521

5506

1996

219

966

2002

619

977

1982

718

097

1538

911

518

8714

6896

5620

4645

3908

3330

1177

311

382

1100

910

590

Cap

ex–1

2000

00

00

00

00

00

00

–270

00–8

000

00

00

00

0O

pex

–542

–248

8–2

487

–343

9–3

440

–344

4–3

440

–343

0–3

316

–313

8–2

883

–574

–454

–470

2–9

268

–921

9–9

181

–251

6–2

490

–246

6–2

438

Cas

h fl o

w

(afte

r tax

)–1

2000

7029

2571

2560

1349

713

500

1354

613

509

1339

512

086

1003

871

0967

07–1

5669

–108

2–4

623

–531

1–5

851

8159

7863

7580

7263

122

Fig. 1. NPV & IRR for scenario 1a and 1b in k $ (2007) dollar (discount rate 10%, long forecasting oil price 40 $ per barrel (a), and oil price 60 $ per barrel (b))

Rys. 1. Rentowność inwestycji – NPV i IRR dla scenariusza „1a” i „1b” w tys. $ (2007). Założona cena ropy naftowej 40 $ za baryłkę (a) oraz 60 $ za baryłkę (b)

6.000

4.000

2.000

0

(2.000)

(4.000)

(6.000)

(8.000)

(10.000)

(12.000)

(14.000)

0% 10% 20% 30% 40% 50% 60%

IRR

NP

V(k

$)

40 $ per bbl60 $ per bbl

TABLE 4

Comparison of NPV and IRR for each scenarios (NPV in k $, assumed discount rate 10%)TABLICA 4

Porównanie wartości NPV i IRR dla każdego scenariusza (NPV w tys. $, założona stopa dyskontowa 10%

NPV IRRScenario 1a –5840 6.2%Scenario 1a 2120 13.9Scenario 2a 41530 44.8%Scenario 2b 50230 51.2%Scenario 3a 17700 37.7%Scenario 3b 42300 51.0%

5. Conclusions

Based on analysis from the reservoir modeling it was possible to calculate the EOR profi les for each reservoir scenario (primary restrictive scenario, primary forced scena-rio, EOR CO2 scenario, EOR CO2/N2 scenario). In the restrictive scenario only 11% of primary recovery is assumed in 25 years exploitation, 33% during “forced” production by 25 years, and 38% and 56% has been obtained from modeling for scenario 2 & 3

123

after 25 and 36 years of exploitation (EOR CO2). The scenario for CO2/N2 gives 53% for 36 years. Total eight economical scenario has been calculated (two base scenario at oil price 40 and 60 $ per bbl, and additional four scenarios with CO2 injection two scenarios for CO2/N2 injections). From economical point of view – CO2/N2 project may be tech-nological effective is generally non profi table. The best scenario for designing of early

Fig. 3. NPV & IRR for scenario 3a and 3b in USD (2007) dollar (discount rate 12%, long forecasting oil price 40 $ per barrel (a), and oil price 60 $ per barrel, (b))


Fig. 2. NPV & IRR for scenario 2a and 2b in USD (2007) dollar (discount rate 12%, long forecasting oil price 40 $ per barrel (a), and oil price 60 $ per barrel (b))


0% 10% 20% 30% 40% 50% 60%

NP

V(k

$)

IRR

40 $ per bbl

60 000

50 000

40 000

30 000

20 000

10 000

0

(10 000)

60 $ per bbl

0% 10% 20% 30% 40% 50% 60%

NP

V(k

$)

IRR

40 $ per bbl

50 000

40 000

30 000

20 000

10 000

0

(10 000)

60 $ per bbl

124

application of EOR is scenario 2b, which is result of high oil price (60$) and additional income from CO2 storage service (assumed 8 $ per tone). The scenario 3 gives also high NPV but high CO2 cost (at the level 12 $ per tone) diminishes NPV about 15%. The analysis show that very restrictive primary production may be uneconomical, because may not cover capital cost related to drilling of wells in the fi rst stage of project.

6. Acknowledgements

This study is funded by the Ministry of Science and Higher Education grant R09 02301

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Received: 06 August 2007

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