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

Transkrypt

Arch. Min. Sci., Vol. 52 (2007), No 4, p. 553–571
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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 flooding 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 efficiency, defined 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, zdefiniowanego jako uzyskanie maksymalnego sczerpania przez okres dwudziestu lat
eksploatacji. Dla wybranego niewielkiego złoża ropy naftowej Niżu Polskiego wykonano badania modelowe 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 dwutlenkiem 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 fluids 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 mixing with each other at the first contact (FCM – First Contact Miscibility). The research
state concerning displacing is described in Stalkup’s works (1983) and Johns (1992).
Miscibility at the first contact occurs in the reservoir if the original reservoir fluid 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 fluid and the injected 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 + N2
2) 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.
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Bubble and dew curves for the specified 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 fig. 1 and fig. 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 fluids during injection process
which lead to formation of the mixing zone (fig. 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 fluids (injected and displaced)
occurs at the specified pressure and the specified reservoir temperature (fig. 3).
C1
G
ga
g1
g2
gt
Op
C 7+
Oa
O1
O1 O2
C
O
C2 – C6
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 first 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
confirmation. Two years later Firoozabadi and Aziz (1986) published the correlation
based on numerous experimental data, however, they did not sufficiently included the
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a)
G
O
O
O
G
g1
b)
O1
O
c)
G
O
g1
O1
g2
d)
G g1
O
O
O1
O
g2
g1
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
C1
P1 > Pm > P2
Pm
P1
P2
O
C 7+
C2 – C6
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
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temperature influence 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
fluid, 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 influence on mixing of the reservoir
fluid 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 specification of minima mixing pressure for oil reservoirs
with gas cap and compositional grading reservoir fluid
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 fluid attributed to the specified 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).
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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
8.2
8
7.5
Molecular
mass C7+
160
200
220
MMP
[MPa]
56.2
64.0
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, combustion gases or buffer injection of LPG with methane (see Hanssen, 1988);
b) Significant decrease of efficiency of the heaviest hydrocarbons in the reservoir recovery; 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 benefit 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 methods.
In the possible EOR project development – case of injection of with CO2 may be
useful. In the first 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
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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 (modified by Tsai-Chen.) was applied (Nagy,
2002). The saturation pressure and PVT properties of separated oil were matched. It was
created a simplified PVT model for 8 pseudo-components for use of Merlin simulator
(Merlin, 2006).
TABLE 1
Modeled oil composition and flash 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
CO2
N2
C1
C2
C3
C4-6
C7+1
C7+2
C7+3
Total composition Liquid composition Vapor composition
(%)
(%)
(%)
0.588
0.017
0.857
12.188
0.042
17.881
35.905
0.272
52.605
8.760
0.551
12.607
4.879
0.183
7.080
3.975
4.306
3.819
8.411
15.501
5.088
11.775
36.771
0.060
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. Simplified 3D anticline view is
presented in fig. 5 and cross-section of structure map passing through well R-3 is presented
in fig. 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 fitted 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/mn3 ** 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
** mn3 – normal cubuc meter measured at 1.01325 bar and 0°C
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Pressure, bar
200
100
0
100
200
300
400
Temperature, C
Fig. 4. Saturation curve of modeled reservoir fluid, according to modified 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)
R4K
R2
R11
R5K
R10
Fig. 5. The 3D structural map view of R-field
Rys. 5. Widok 3D struktury złoża R
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
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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)).
300
FOPR, Sm3/day
CO2/MIX, 2 wells
200
N2, 2 wells
MIX, 2 wells
base
100
0
0
2
4
6
8
10
12
14
16
18
20
Time, years
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
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500000
CO2/MIX, 2 wells
FGPR, Sm3/day
400000
N2, 2 wells
MIX, 2 wells
300000
200000
100000
base
0
0
4
2
6
8
10
12
14
18
16
20
Time, years
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
2E+6
CO2/MIX
1E+6
MIX
N2
FOPT, Sm3
1E+6
1E+6
base
8E+5
6E+5
4E+5
2E+5
0E+0
0
2
4
6
8
10
12
14
16
18
20
Time, years
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
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2.0E+9
1.8E+9
1.6E+9
N2, 2 wells
MIX, 2 wells
FGPT, Sm3
1.4E+9
CO2/MIX, 2 wells
1.2E+9
1.0E+9
8.0E+8
6.0E+8
base
4.0E+8
2.0E+8
0.0E+0
0
2
4
6
8
10
12
14
16
18
20
Time, years
Fig. 9. Gas production total recovery (Sm3) for several cases: (a) base – without injection and injection
Fig. 9. Sumaryczne wydobycie gazu (Sm3) dla następujących przypadków: (a) wariant bazowy
4.0E+5
CO2/MIX, 2 wells
FGIR, Sm3/day
3.0E+5
2.0E+5
1.0E+5
0.0E+0
0
2
4
6
8
10
12
14
16
18
20
Time, years
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:
564
5000
FGOR, Sm3/Sm3
4000
3000
MIX, 2 wells
2000
CO2/MIX, 2 wells
N2, 2 wells
1000
base
0
0
2
4
6
8
10
12
14
16
18
20
Time, years
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
300
200
CO2/MIX, 2 wells
FPR, barsa
N2, 2 wells
MIX, 2 wells
100
base
0
0
2
4
6
8
10
12
14
16
18
20
Time, years
Fig. 12. Reservoir pressure (@ WOC) for several cases: (a) base – without injection and injection
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
565
300
CO2, pure
FOPR, Sm3/day
CO2/MIX
200
CO2/N2
MIX
100
base
0
0
4
2
6
8
10
12
14
16
18
20
Time, years
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:
2.0E+6
1.8E+6
CO2/N2
1.6E+6
FOPT, Sm3
CO2/MIX
CO2, pure
1.4E+6
MIX
1.2E+6
base
1.0E+6
8.0E+5
6.0E+5
4.0E+5
2.0E+5
0.0E+0
0
2
4
6
8
10
12
14
16
18
20
Time, years
Fig. 14. Gas production rate (Sm3/day) for several cases: (a) base – without injection and injection
Fig. 14. Wydajność gazu (Sm3/dobę) dla następujących przypadków: (a) wariant bazowy
566
7.0E+5
6.0E+5
CO2/N2
FGPR, Sm3/day
5.0E+5
CO2/MIX
4.0E+5
MIX
3.0E+5
CO2, pure
2.0E+5
1.0E+5
base
0.0E+0
0
2
4
6
8
10
12
14
16
18
20
Time, years
Fig. 15. Oil production total recovery (Sm3) for several cases: (a) base – without injection and injection
Fig. 15. Sumaryczne wydobycie ropy naftowej (Sm3) dla następujących przypadków: (a) wariant bazowy
3E+9
FGPT, Sm3
2E+9
CO2/N2
CO2/MIX
1E+9
CO2, pure
base
MIX
0E+0
0
2
4
6
8
10
12
14
16
18
20
Time, years
Fig. 16. Gas production total recovery (Sm3) for several cases: (a) base – without injection and injection
Fig. 16. Sumaryczne wydobycie gazu (Sm3) dla następujących przypadków: (a) wariant bazowy
567
5000
FGOR, Sm3/Sm3
4000
3000
CO2/N2
CO2/MIX
2000
CO2, pure
MIX
1000
base
0
0
2
4
6
8
10
12
14
16
18
20
Time, years
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
400
CO2/MIX
300
CO2/N2
FPR, barsa
MIX
CO2, pure
200
100
base
0
0
2
4
6
8
10
12
14
16
18
20
Time, years
Fig. 18. Reservoir pressure (@ WOC) for several cases: (a) base – without injection and injection
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
568
7.0E+5
6.0E+5
CO2, pure
FGPR, Sm3/day
5.0E+5
MIX2
CO2/N2
CO2/MIX
4.0E+5
3.0E+5
2.0E+5
1.0E+5
0.0E+0
0
4
2
6
8
10
12
14
16
18
20
Time, years
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
3.0E+9
CO2/N2
FGIT, Sm3
2.0E+9
CO2/MIX
1.0E+9
CO2, pure
MIX
0.0E+0
4
6
8
10
12
14
16
18
Time, years
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
569
7. Analysis of results of modeling
The analyses field production/injection process (a-d) into two wells – without and
with injection of gas mixture processes are presented in the figs. 6-12. The fig. 6 and 7
show oil and 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.
The total production of oil and gas during this process is presented in the fig. 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 presented in fig. 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 fig. 12.
The analyses field production/injection process (a-e) into four wells – without and
with injection of gas mixture processes are presented in the figs. 13-20. The figures 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 fig. 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 injection using four wells into the cap of reservoir: (b) nitrogen, (c) MIX gas, (d) CO2/MIX
– is given in fig. 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
figures 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 fig. 8 and fig. 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 (fig. 6 or fig. 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 supercritical 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

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

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