-52-4-Nagy

553Arch. Min. Sci., Vol. 52 (2007), No 4, p. 553–571

STANISLAW NAGY*, ANDRZEJ OLAJOSSY*

ANALYSIS OF USE OF LOW QUALITY NATURAL GAS TO IMPROVE OIL RECOVERY FACTOR

ANALIZA MOŻLIWOŚCI WYKORZYSTANIA GAZU O NISKIEJ JAKOŚCI DO ZWIĘKSZENIA WSPÓŁCZYNNIKA SCZERPANIA ZŁOŻA ROPY NAFTOWEJ

Enhanced oil recovery methods are applied more frequently nowadays, mainly because of economic reasons. The classic water fl ooding methods that aim to maintain the reservoir pressure are substituted or updated by the Water Alternating Gas (WAG) Technology. 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 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 concerning increasing of the reservoir pressure were analyzed, particularly those involving injection into the cap through two wells as well as through four ones. Performed calculations are presented in this paper. The best results were obtained for the injection of the pure carbon dioxide. Other satisfactory solution involves injection of carbon dioxide through two years, and after that injection of nitrogen or the mixture of carbon dioxide and nitrogen. The presented results are promising and show potential possibilities of rising oil recovery by 50-80% with reference to the case without gas injection.

Keywords: Enhanced Oil Recovery, EOR, gas injection, lean gas, nitrogen, carbon dioxide sequestration, modeling

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. Wykorzystanie gazu ziemnego zaazotowanego, azotu odpadowego po separacji metanu i węglowodorów, dwutlenek węgla lub też roztworów zawierających dwutlenek węgla i azot jest rozważane w aspekcie skuteczności procesu

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

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czerpania złoża, zdefi niowanego jako uzyskanie maksymalnego sczerpania przez okres dwudziestu lat eksploatacji. Dla wybranego niewielkiego złoża ropy naftowej Niżu Polskiego wykonano badania mo-delowe z wykorzystaniem symulatora pseudo-kompozycyjnego. Analizowano różne aspekty zatłaczania gazu w celu podniesienia ciśnienia złożowego – w szczególności zatłaczanie do czapy zarówno poprzez dwa odwierty, a także poprzez cztery odwierty. Wykonane obliczenia zaprezentowano w niniejszej pracy. Najlepsze wyniki uzyskano dla zatłaczania czystego dwutlenku węgla. Innym dobrym rozwiązaniem jest zatłaczanie dwutlenku węgla przez okres dwóch lat a następnie zatłaczanie azotu lub azotu z dwu-tlenkiem węgla do złoża. Zaprezentowane wyniki są obiecujące i pokazują potencjalne możliwości zwiększenia o 50-80% wydobycia ropy naftowej ze złoża w porównaniu do przypadku eksploatacji pierwotnej złoża.

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

1. Introduction

Displacing of oil from porous medium through the fl uids mixing with oil found application in the technologies of secondary oil reservoir exploitation methods (EOR) and new projects related to EOR with carbon dioxide sequestration (Nagy et al., 2006; Krzystolik et al., 2007; Siemek et al., 2006; Nagy, 2006). Those methods include: injection of gases like CO2, N2 or the natural gas. The gas injection reduces the pressure decline connected with the production of oil from the reservoir. However, the gas injected affects the equilibrium composition of the gas/oil system in the reservoir. Selective reduction of ingredients in oil phase (VGD – Vaporising Gas Drive) is observed. It may also occur the inverse phenomenon which involves condensation of some ingredients from the gas phase (CGD – Condensing Gas Drive) or gas and oil may also have inclination to mi-xing with each other at the fi rst contact (FCM – First Contact Miscibility). The research state concerning displacing is described in Stalkup’s works (1983) and Johns (1992). Miscibility at the fi rst contact occurs in the reservoir if the original reservoir fl uid and injected gas are miscible. This means that all possible mixtures for initial compositions lead to forming of a single-phase system.

In case of condensing-drive process (CGD) the original reservoir fl uid and the in-jected gas are not miscible; later the miscibility could be obtained near the injection well. In this process intermediate components selectively may condensate from the gas injected to oil.

To illustrate the mixing process the triangle diagrams are used, dividing mixture composition into three component groups (Laciak & Nagy, 1995):

1) light components: C1 + CO2 + N22) intermediate components: C2 – C6 3) heavy components: C7+

Each vertex represents 100% content of component group. The arbitrary concentration between 0-100% is represented in the diagram in the form of an appropriate segment.

555

Bubble and dew curves for the specifi ed pressure and temperature values determine two-phase area, marked in the picture by the thick line, point C is the critical point of the pseudo-mixture.

Gas injection with evaporation process (VGD) is shown in fi g. 1 and fi g. 2ad. Points G, ga, g1, g2, gt pertain to the injected gas, whereas points Op, Oa, O1, O2 pertain to displaced oil. Points G and O represents initial compositions of injected gas and oil, whereas points g1, g2 and O2 indicate changes in compositions of both fl uids during injection process which lead to formation of the mixing zone (fi g. 2ad). Presented mixing process occurs in the distance of few meters from the injection well and involves situation in which the injected gas is the natural gas. The process of mixing of fl uids (injected and displaced) occurs at the specifi ed pressure and the specifi ed reservoir temperature (fi g. 3).

Fig. 1. Minimum Miscibility Pressure determination in the triangle diagram

Rys. 1. Minimalne ciśnienie mieszania (MMP) określone na diagramie trójkątnym

2. Minimum mixing pressure (MMP) for methane and nitrogen as injected medium

The fi rst dependence of his type was published by Stalkup (1984) and by Yelling and Metcalfe (1980), however, the author suggested careful using of this method. The main disadvantage of this work was not enough number of researches targeting its confi rmation. Two years later Firoozabadi and Aziz (1986) published the correlation based on numerous experimental data, however, they did not suffi ciently included the

C1

C7+ C – C2 6

G

ga

g1

g2

gt

OOp

Oa

O1O2

O1C

556

Fig. 3. Minimum Miscibility Pressure as a function of oil and injection of gas compositions in the reservoir temperature

Rys. 3. Minimalne ciśnienie mieszania, jako funkcja własności ropy i zatłaczanego składu gazu dla temperatury złożowej

Fig. 2. Forming of mixing zone a. start of injection, b. start of mixing zone, c. continue of process, d. origin of mixing zones (Laciak, Nagy, 1995)

Rys. 2. Tworzenie strefy mieszania a. początek zatłaczania, b. początek tworzenia strefy mieszania, c. c.d. tworzenia strefy mieszania, d. utworzona strefa mieszania

G

G

O

O1

OO

O

a)

b)

c)

d)

O

g1

G

O1O

g2 Og1

O1

G g1 g2

g1

O

C1

C7+ C – C2 6

P1

PmP2

P > Pm > P1 2

O

557

temperature infl uence on MMP. Meanwhile Glaso (1985, 1988) and Emanuel et al. (1986) have proposed a number of MMP correlations for the natural gas, CO2 and N2. His work is based on the Benham et al. (1960) data. Unfortunately this correlation is not very accurate.

Numerous works involving MMP, nitrogen and natural gas as an injecting medium were published by Glaso (1988) and Hudgins et al. (1988) for nitrogen as a displacing fl uid, Nouar and Flock (1988) for the natural gas and Eakin and Mitch (1988) for all types of gases and mixing processes (CO2, N2 and natural gas). The work of Nouar and Flock (1988) differs widely from the other ones. The authors performed the very precise interpretation of three-component diagram for methane as the displacing gas. It is the graphical correlation, based on the numerous experimental data. Obtained results are convergent with those given by Hudgins et al. (1988).

The most important parameters having direct infl uence on mixing of the reservoir fl uid with nitrogen or the natural gas are: content of intermediate pseudo-components (hydrocarbons C2 – C6, CO2, H2S), molecular weight of heavy fractions MC7+ and temperature.

3. Problem of specifi cation of minima mixing pressure for oil reservoirs with gas cap and compositional grading reservoir fl uid

The extensive considerations according to the variation of the minimal mixing pressure are included in the Hoeier & Whitson (2001). Analysing MMP variation for the depth function, the variation of MMP reaches 10 MPa and is the depth function and MME (Minimum Miscibility Enrichment – see Zick (1986)). Such analysis could be performed after obtaining full and reliable thermodynamic data regarding the total composition of the reservoir fl uid attributed to the specifi ed depth.

4. Minimum mixing pressure for nitrogen for the hypothetical oil reservoir

Hanssen’s correlation was used for estimation of the minimal mixing pressure of the oil (light) and nitrogen system. Because of lack of total composition of the system, calculations should be treated with appropriate carefulness. In case of a Polish reservoir those values varies between 56 and 70 MPa (see Tab.1).

558

TABLE 1

Estimated minimal miscibility MMP pressure for the typical Polish reservoir from the Polish Lowland

TABLICA 1

Oszacowana minimalna wartość ciśnienia mieszania (MMP) dla typowego złoża ropy Niżu Polskiego

% of C2 – C6

Molecular mass C7+

MMP[MPa]

8.2 160 56.28 200 64.0

7.5 220 69.6

5. Negative and positive aspects of injecting nitrogen into reservoir

Numerous negative phenomenon’s were observed during injection of nitrogen into gas-condensate and light oil reservoirs (both in the laboratory scale and in the industry). The most important factors are following:

a) Increase of the minima mixing pressure in comparison with carbon dioxide, com-bustion gases or buffer injection of LPG with methane (see Hanssen, 1988);

b) Signifi cant decrease of effi ciency of the heaviest hydrocarbons in the reservoir re-covery; supplying nitrogen causes increase of constants of the lightest equilibrium and decrease of the heaviest components of the hydrocarbon system (Hagoort et. al., 1988; Boersma & Hagoort, 1994; Evison & Gilchrist, 1992).

The one of benefi t of nitrogen usage for injection (leading to increase of the reservoir pressure) is its availability. The second possibilities for source of nitrogen is separation from “nitrogen high content“ natural gas the cryogenic installations or adsorption me-thods.

In the possible EOR project development – case of injection of with CO2 may be useful. In the fi rst stage CO2 is injected and in the later phase classical nitrogen injection process may be consider (Donohoe & Buchanan, 1981; Eckles et al., 1981; Huang et al., 1986; Metcalfe at al., 1987, 1988; Peterson, 1978; Sanger et al., 1994; Sanger & Hagoort, 1998; Siregar et al., 1992).

6. Example of possible use of pure nitrogen, nitrogen-methane or nitrogen-carbon dioxide mixtures

The relatively high initial reservoir pressure encourages also to inject CO2-N2 mixture as an alternative to the basic case. In order to visualize these problems the numerical

559

model of one of Polish Lowland’s oil reservoirs which is located close to the potential high-nitrogen gas source was created.

PVT Properties. The PVT properties were based on laboratory research and using the Peng-Robinson’s equation of state (modifi ed by Tsai-Chen.) was applied (Nagy, 2002). The saturation pressure and PVT properties of separated oil were matched. It was created a simplifi ed PVT model for 8 pseudo-components for use of Merlin simulator (Merlin, 2006).

TABLE 1

Modeled oil composition and fl ash composition (1 atm, 15°C) of liquid and gas composition of oil

TABLICA 2

Modelowany skład ropy naftowej i składy ropy i gazu po separacji (1 atm, 15°C)

Component Total composition (%)

Liquid composition (%)

Vapor composition (%)

CO2 0.588 0.017 0.857 N2 12.188 0.042 17.881 C1 35.905 0.272 52.605 C2 8.760 0.551 12.607 C3 4.879 0.183 7.080 C4-6 3.975 4.306 3.819 C7+1 8.411 15.501 5.088 C7+2 11.775 36.771 0.060 C7+3 13.515 42.353 4.4E-07

Geological data. The model was designed basing on seismic data, geological data, drilling data and exploitation data. The anticline reservoir was modeled by a 10-layer set. These layers have various hydrodynamics properties. Simplifi ed 3D anticline view is presented in fi g. 5 and cross-section of structure map passing through well R-3 is presented in fi g. 6. The hydrodynamic properties, as well as porosity and saturation of oil and water were introduced into the model. Static data related to the reserves are fi tted in the model. Available date from the past has been used to made history match in the project.

Simulation models used in this study. Basic case (a) – no secondary method in oil reservoir exploitation process: This case was created the model of reservoir simulation that was exploited by 4 wells with an total initial rate of 290 Sm3/day* and Gas-Oil-Ratio (GOR) of approx. 180 Sm3/mn

3** through the period of 20 years. Cases with two injection wells for injection into gas-cap:1. Injection of high-nitrogen gas (95% N2, 5% CH4) into reservoir (“N2”). Assumed

maximal injection rate was 6250 Sm3/hr for each well. The maximum Bottom Hole Pressure (BHP) is restricted to 320 bar (case (b)).

* Sm3 – cubuc meter measured at 1.01325 bar and 15°C** mn

3 – normal cubuc meter measured at 1.01325 bar and 0°C

560

2. Injection of mixture CO2/N2/CH4 high-nitrogen gas (15% CO2, 80% N2, 5% CH4) – “MIX” into reservoir (“N2”). Assumed maximal injection rate was 6250 Sm3/hr for each well. The maximum Bottom Hole Pressure (BHP) is restricted to 320 bar (case (c)).

3. Injection of pure CO2 (two years) and then mixture CO2/N2/CH4 high-nitrogen gas (15% CO2, 80% N2, 5% CH4) – “MIX” Assumed maximal injection rate was

Fig. 5. The 3D structural map view of R-fi eld

Rys. 5. Widok 3D struktury złoża R

Fig. 4. Saturation curve of modeled reservoir fl uid, according to modifi ed Peng-Robinson (1976) equation of state (based on laboratory research)

Rys. 4. Ciśnienie nasycenia modelowanego płynu złożowego wg równania stanu Penga-Robinsona (dopasowanie na podstawie badań laboratoryjnych)

200

100

0 100 200 300 400

Temperature, C

Pre

ssure

,bar

R2R4K

R11

R5KR10

561

6250 Sm3/hr for each well. The maximum Bottom Hole Pressure (BHP) is restricted to 320 bar (case (d)).

The calculation has been applied also to cases with four injection wells for injection into gas-cap:

1. Injection of pure carbon dioxide into reservoir (“CO2”). Assumed maximal injection rate was 6250 Sm3/hr for each well. The maximum Bottom Hole Pressure (BHP) is restricted to 320 bar (case (b)).

2. Injection of mixture CO2/N2/CH4 high-nitrogen gas (15% CO2, 80% N2, 5% CH4) – “MIX” into reservoir (“N2”). Assumed maximal injection rate was 6250. Sm3/hr for each well. The maximum Bottom Hole Pressure (BHP) is restricted to 320 bar (case (c)).

3. Injection of pure CO2 (two years) and then mixture of high-nitrogen gas (95% N2, 5% CH4) – “N2” Assumed maximal injection rate was 6250 Sm3/hr for each well. The maximum Bottom Hole Pressure (BHP) is restricted to 320 bar (case (d)).

4. Injection of pure CO2 (two years) and then mixture CO2/N2/CH4 high-nitrogen gas (15% CO2, 80% N2, 5% CH4) – “MIX” Assumed maximal injection rate was 6250 Sm3/hr for each well. The maximum Bottom Hole Pressure (BHP) is restricted to 320 bar (case (e)).

Fig. 6. Oil production rate (Sm3/day) for several cases: (a) base – without injection and injection using two wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 6. Wydajność ropy naftowej (Sm3/dobę) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do dwóch odwiertów w czapie gazowej:

(b) azot, (c) gaz MIX, (d) układ CO2/MIX

0

100

200

300

0 2 4 6 8 10 12 14 16 18 20

Time, years

FO

PR

,S

m/d

ay

3

CO /MIX, 2 wells2

N , 2 wells2

MIX, 2 wells

base

562

Fig. 8. Oil production total recovery (Sm3) for several cases: (a) base – without injection and injection using two wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 8. Sumaryczne wydobycie ropy naftowej (Sm3) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do dwóch odwiertów w czapie gazowej:


Fig. 7. Gas production rate (Sm3/day) for several cases: (a) base – without injection and injection using two wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 7. Wydajność gazu (Sm3/dobę) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do dwóch odwiertów w czapie gazowej:


0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /MIX, 2 wells2

N , 2 wells2

MIX, 2 wells

base

FG

PR

,S

m/d

ay

3

0

100000

200000

300000

400000

500000

0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /MIX2

N2

MIX

base

2E+6

1E+6

1E+6

1E+6

8E+5

6E+5

4E+5

2E+5

0E+0

FO

PT,

Sm

3

563

Fig. 10. Gas injection rate (Sm3) for several cases: (a) base – without injection and injection using two wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX – all cases 3e5 Sm3/day

Fig. 10. Wydajność zatłaczania gazu (Sm3/dobę) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do dwóch odwiertów w czapie gazowej:


Fig. 9. Gas production total recovery (Sm3) for several cases: (a) base – without injection and injection using two wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 9. Sumaryczne wydobycie gazu (Sm3) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do dwóch odwiertów w czapie gazowej:


0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /MIX, 2 wells2

N , 2 wells2

MIX, 2 wells

base

FG

PT,S

m3

2.0E+9

1.8E+9

1.6E+9

1.4E+9

1.2E+9

1.0E+9

8.0E+8

6.0E+8

4.0E+8

2.0E+8

0.0E+0

0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /MIX, 2 wells2

0.0E+0

1.0E+5

2.0E+5

3.0E+5

4.0E+5

FG

IR,

Sm

/da

y3

564

Fig. 12. Reservoir pressure (@ WOC) for several cases: (a) base – without injection and injection using two wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 12. Średnie ciśnienie złożowe (na głębokości kontaktu ropa-woda) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do dwóch odwiertów

w czapie gazowej: (b) azot, (c) gaz MIX, (d) układ CO2/MIX

Fig. 11. Gas oil ratio for several cases: (a) base – without injection and injection using two wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 11. Wykładnik gazowy dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do dwóch odwiertów w czapie gazowej:


0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /MIX, 2 wells2N , 2 wells2

MIX, 2 wells

base

FG

OR

,/S

m3

Sm

3

0

1000

2000

3000

4000

5000

0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /MIX, 2 wells2N , 2 wells2

MIX, 2 wells

base

FP

R,bars

a

0

100

200

300

565

Fig. 14. Gas production rate (Sm3/day) for several cases: (a) base – without injection and injection using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 14. Wydajność gazu (Sm3/dobę) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do czterech odwiertów w czapie gazowej:


Fig. 13. Oil production rate (Sm3/day) for several cases: (a) base – without injection and injection using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 13. Wydajność ropy naftowej (Sm3/dobę) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do czterech odwiertów w czapie gazowej:


0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /2 N2

base

0

100

200

300CO , pure2

CO /MIX2

MIX

FO

PR

,S

m/d

ay

3

0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /2 N2

base

CO , pure2CO /MIX2

MIX

2.0E+6

1.8E+6

1.6E+6

1.4E+6

1.2E+6

1.0E+6

8.0E+5

6.0E+5

4.0E+5

2.0E+5

0.0E+0

FO

PT,S

m3

566

Fig. 16. Gas production total recovery (Sm3) for several cases: (a) base – without injection and injection using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 16. Sumaryczne wydobycie gazu (Sm3) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do czterech odwiertów w czapie gazowej:


Fig. 15. Oil production total recovery (Sm3) for several cases: (a) base – without injection and injection using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 15. Sumaryczne wydobycie ropy naftowej (Sm3) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do czterech odwiertów w czapie gazowej:


0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /2 N2

base

CO , pure2

CO /MIX2

MIX

2.0E+5

0.0E+0

FG

PR

,S

m/d

ay

3

3.0E+5

4.0E+5

5.0E+5

6.0E+5

7.0E+5

1.0E+5

0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /2 N2

base

CO , pure2

CO /MIX2

MIX

0E+0

FG

PT,S

m3

1E+9

2E+9

3E+9

567

Fig. 18. Reservoir pressure (@ WOC) for several cases: (a) base – without injection and injection using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 18. Średnie ciśnienie złożowe (na głębokości kontaktu ropa-woda) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do czterech odwiertów

w czapie gazowej: (b) azot, (c) gaz MIX, (d) układ CO2/MIX

Fig. 17. Gas oil ratio for several cases: (a) base – without injection and injection using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 17. Wykładnik gazowy dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do czterech odwiertów w czapie gazowej: (b) azot, (c) gaz MIX,

(d) układ CO2/MIX

0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /2 N2

base

0

1000

2000

3000

CO , pure2

CO /MIX2

MIX

FG

OR

,S

m/

3S

m3

4000

5000

0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /2 N2

base

0

100

200

300

CO , pure2

CO /MIX2

MIX

FP

R,bars

a

400

568

Fig. 20. Total gas injection (Sm3) during exploitation of reservoir for several cases: (a) base – without injection and injection using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX

Fig. 20. Sumaryczny gaz zatłoczony do złoża (Sm3) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do czterech odwiertów w czapie gazowej:


Fig. 19. Gas injection rate (Sm3/day) during exploitation of reservoir for several cases: (a) base – without injection and injection using four wells into the cap of reservoir: (b) nitrogen,

(c) MIX gas, (d) CO2/MIX. Injection into four wells.

Fig. 19. Wydajność zatłaczania gazu (Sm3/dobę) dla następujących przypadków: (a) wariant bazowy bez zatłaczania gazu oraz warianty zatłaczania do czterech odwiertów w czapie gazowej:


0 2 4 6 8 10 12 14 16 18 20

Time, years

CO /2 N2

CO , pure2

CO /MIX2

MIX2

FG

PR

,S

m/d

ay

3

2.0E+5

0.0E+0

3.0E+5

4.0E+5

5.0E+5

6.0E+5

7.0E+5

1.0E+5

4 6 8 10 12 14 16 18

Time, years

CO /2 N2

CO , pure2

CO /MIX2

MIX

FG

IT,

Sm

3

0.0E+0

1.0E+9

2.0E+9

3.0E+9

569

7. Analysis of results of modeling

The analyses fi eld production/injection process (a-d) into two wells – without and with injection of gas mixture processes are presented in the fi gs. 6-12. The fi g. 6 and 7 show oil and gas production rate (Sm3/day) for several cases: (a) base – without injec-tion and injection using two wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX.

The total production of oil and gas during this process is presented in the fi g. 8 and 9. Oil production rate is declining in the late period of exploitation for most cases. Only

the last case (7) allows maintaining oil production rate. The gas injection rate (Sm3) for several cases: (a) base- without injection and injection using two wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX – all cases 3e5 Sm3/day – is presen-ted in fi g. 10. Fig. 11 shows predicted gas oil ratio for several cases: (a) base- without injection and injection using two wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX. The average reservoir pressure for several cases: (a) base- without injection and injection using two wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX is given in fi g. 12.

The analyses fi eld production/injection process (a-e) into four wells – without and with injection of gas mixture processes are presented in the fi gs. 13-20. The fi gures 13 and 14 show oil and gas production rate (Sm3/day) for following cases: (a) base – without injection and injection using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX. The total production of oil and gas during this process is presented in the fi g. 15 and 16. Fig. 17 shows apparent gas oil ratio for cases: (a) base – without injection and injection using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX. Reservoir pressure for cases: (a) base – without injection and injec-tion using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX – is given in fi g. 18. Gas injection rate (Sm3/day) and total gas injection (Sm3) during exploitation of reservoir for cases: (a) base – without injection and injection using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX is presented in fi gures 19 and 20.

The most interested effect is achieved by injection (1) pure carbon dioxide and (2). Carbon-dioxide-high-nitrogen gas containing 80% of CO2, 15% N2 and 5% of CH4 followed by injection of pure carbon dioxide in supercritical phase.

Created model of reservoir simulation of reservoir exploited with four production wells and four injection well with maintained reservoir pressure is one of the best, but the difference between injection of CO2 slug/N2/MIX cases for 4 and 2 wells is below 15% (see fi g. 8 and fi g. 14).

570

8. Conclusions

Maximal plateau has been observed during injection of pure CO2 into reservoir – until 17th year of production and small decline in the last three years – by 20% – is observed (fi g. 6 or fi g. 12). The minimal patou has been obtained by injection of MIX and N2 streams. In this case after 8th year of oil production a declining production has been observed up to 50% of initial value.

The negative aspect of presented EOR method is relative short breakthrough of gas (c.a. 2 years). The longest non breakthrough time is estimated for CO2, and very short time is observed for low quality streams: “Mix” and “N2”. This is evident explanation of worse oil recovery factor for those cases.

The best results were obtained for the injection of the pure carbon dioxide in super-critical phase. Other satisfactory solution involves injection of carbon dioxide through two years (slug), and after that injection of nitrogen or the mixture of carbon dioxide and nitrogen. The presented results are promising and show potential possibilities of rising oil recovery factor by 50-80% with reference to the primary oil explaitation case without gas injection

Acknowledgements

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

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Received: 24 April 2007

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