RETRACTED ARTICLE: A simulation approach: Miscible carbon dioxide injection in a carbonate reservoir
Pet.Sci.
E L T C
Ehsan Heidaryan 2
Jamshid Moghadasi 1
Marylena Garcia Quijada 0
0 Texas A&M University, College Station , Texas , USA
1 Petroleum Engineering Department, Petroleum University of Technology , Ahwaz , Iran
2 Faculty of Energy, Kermanshah University of Technology , Kermanshah , Iran
The purpose of this study is to optimize the existing carbon dioxide (CO2) flood in deep dolomite formations by improving oil sweep efficiency of miscible CO2 floods and enhancing the was built to optimize the injection pattern. The model is a quarter of an inverted nine-spot and covCers20 conformance control. A full compositional simulation model using a detailed geologic characterization acres of field formation. Geologic description was used to construct the simulation grids. The sIimulation was performed to validate the model. Several sensitivity runs were made to improve TtheCO2 sweep layers represent actual flow units and resemble the large variation of reservoir properties. History match was determined approximately. Simulation results also indicate that a water-alRternating-gas (WAG) efficiency and increase the oil recovery. Finally, the optimum CO2 injection rate for dolomite formations incremental oil recovery of 18%. The additional recovery increases to 34% Aapolymer if is injected as ratio of 1:1 along with an ultimate CO2 slug of 100% hydrocarbon pore volume (HCPV) will allow an a conformance control agent during the course of the WAG process at a ratio of 1:1. According to the incremental oil recovery of 26%. D results, a pattern reconfiguration change from the nine spot to staggered line drive would represent an
Miscible injection; carbon dioxide; dolomite formEation; water-alternating-gas
1 Introduction
as immiscible and/or miscible. Recovery Amechanisms in
Carbon dioxide (CO2) flooding processes can be classified
oil swelling, and solution-gas drive. In Rgeneral, CO2 is very
miscible flooding processes involve reduction in oil viscosity,
the oil and reduces oil viscosity T
(Martin and Taber, 1992)
.
soluble in crude oil at reservoir pressures; therefore, it swells
multiple-contact miscibility Eprocess, which starts with
denseMiscibility between CO2 and crude is achieved through a
into the oil, making Rlighter it and often driving methane out
phase CO2 and hydrocarbon liquid. The CO2 first condenses
ahead of the oil bank. The lighter components of the oil then
vaporize into the CO2-rich phase, making it denser, more like
the oil, and thus more easily soluble in the oil. Mass transfer
continues between the CO2 and the oil until the two mixtures
become indistinguishable in terms of fluid properties (Jarrel
et al, 2002).
Because of this mechanism, good recovery may occur at
pressures high enough to achieve miscibility. In general, the
high pressures are required to compress CO2 to a density at
which it becomes a good solvent for the lighter hydrocarbons
in the crude oil. This pressure is known as minimum
miscibility pressure (MMP), that is the minimum pressure
at which miscibility between CO2 and crude can occur
(Martin and Taber, 1992)
. This pressure is usually determined
experimentally. The water-alternating-gas (WAG) process
consists of the injection of water and gas as alternate slugs
by cycles or simultaneously (SWAG), with the objective of
improving the sweep efficiency of water flooding and miscible
or immiscible gas-flood projects by reducing the impact of
viscous fingering. A schematic of the WAG process is shown
in the literature (Caudle and Dyes, 1959). During a WAG
process, the combination of higher microscopic displacement
efficiency of gas with better macroscopic sweep efficiency of
water helps significantly increase the incremental production
over a plain water flood. A wide variety of gases have been
employed for a wide range of reservoir characteristics in
the miscible mode; however, CO2 and hydrocarbon gases
represent approximately 90% of the injected gases (Jarrel et
al, 2002).
2 Reservoir performance
Cores analyses have revealed that the "main pay" interval
presents three rock types: a pelletal dolomite packstone with
interparticle and intercrystal porosity (pelletal packstone);
a fossiliferous dolomite wackestone with moldic porosity
(moldic wackestone); and a fossiliferous dolomite packstone
with moldic and interparticle porosity (moldic packstone).
The pelletal packstone rocks occur both as homogeneous
units and in burrows and irregular patches in the wackestones.
They have excellent reservoir rock properties; permeability
can be as high as 152 mD and interparticle porosity is up
to 24.3%. In the wackestone rocks, molds and vugs are the
dominant pore types, ranging in size up to 6 mm. Within the
rock, molds are not in contact with other; core observation has
revealed that the molds are isolated in the rock by a relatively
tight matrix. This isolated moldic porosity negatively affects
the reservoir properties of the rock. Permeability is less than
1 mD, even though moldic porosity may range as high as
10%
(Mathis and Sears, 1984)
. Summary of reservoir data are
given in Table 1. In preparation for the CO2 flood, the random
waterflood pattern was converted into a nine-spot pattern.
Oil production response was observed soon after injection
began and the oil cut rose from below 14% to 31%. In Fig. 1
CO2 response can be clearly seen on a plot of oil cut versus
cumulative production. The WAG flood in the WAG area was
started with a constant 1:1 gas/water ratio (1% hydrocarbon
pore volume (HCPV) of CO2 and 1% HCPV of water). The
original injection schedule involved injecting alternating
6-month slugs of CO2 and water until a 40% HCPV slug of
CO2 had been injected.
60
50
40
%
t,u 30
c
li
O20
10
0
0
E
Carbon dioxide injection
L
C
I
T
75 100 125 150 175
Cumulative oil production, MMB
200
25
50
Fig. 1 Oil Rcutversus cumulative oil production
during continuous CO2 flood
Reservoir characteristics
Producing area, acres
Formation
Average depth, ft
Gas-oil contact, ft
Average permeability, mD
Average porosity
Average net oil pay thickness, ft
Oil gravity, degrees API
Reservoir temperature, °F
Primary production mechanism
Secondary production mechanism
Original reservoir pressure, psia A1805
Tertiary production mechanism CO2 miscible
Bubble point pressure, psia R 1805
Average pressure at start of secondary recovery, psia ±800 / ±1100
Target reservoir pressure for CO2, Tpsia
Initial formation volume factor E(FVF), bbl/STB
R
Solution gas-oil ratio at original pressure, bbl/STB
Solution gas-oil ratio at start of secondary recovery original pressure, scf/bbl
Oil viscosity at 60 °F and 1100 psia, cP
Minimum miscibility pressure, psia
Values
25505
Dolomite 5200 1325 5
A
3 Parameters modeling
0.12 DThereservoir oil is saturated black oil with a stock tank
137 gravity of 33° API and an initial gas-oil ratio (GOR) of 660
33 Esacref/S1T,8B0.5Inpistiiaalartesaerrevfoeirrepnrceessduerpethanodf b5u,b0b0l0e fptoainntdp1r0es5su°rFe.
105 TThe CO2 minimum miscibility pressure (1,300 psia) was
Solution-gas drive determined experimentally. Reservoir fluid compositions are
WaCterflood available in Table 2. The tuning of the equation of states (EOS)
in this work followed the methodology suggested by Khan
et al (1992) to characterize CO2 oil mixtures. The P-R EOS
(Peng and Robinson, 1976) was chosen as the EOS model
because it has been found adequate for low-temperature
CO2/oil mixtures (Khan et al, 1992). The viscosity model
considered to match the oil viscosity of the reservoir fluid
2200 was the Lohrenz-Bray-Clark (LBC) model (Lohrenz et al,
1.312 1964) which is a predictive model for gas or liquid viscosity.
Detailed PVT experiments are listed in Table 3; and the
420 related preliminary matches by the basic EOS.
The maximum oil relative permeability is 65% at 15%
1060 connate water saturation (Swc=15%). At 60% water saturation
1.18 i(nSjwecc=t6e0d%,t)h,ethweatoeirl rreellaattiivvee ppeerrmmeeaabbiliiltiytyi niscrzeearsoe.s,Arseawcahtienrgias
1300 maximum value of 50% at 60% water saturation.
WAG 1 1
No treatment
Polymer
History
20
0
180
160
140
120
d
/B 100
T
,So 80
Q 60
40
20
0
180
160
140
/d120
TB100
,S 80
o
Q 60
40
20
0 0
0
5
10
15
25
30
35
40
20
Years
5 10 15 20 25 40
T
Years
Fig. 10 Comparison of staggered-line-drive, line-drive,
E
and nine-spot well patterns
R
both the staggered-line-drive pattern and the line-drive pattern
create an immediate peak above 100 STB/d in the production
rate, which represents approximately a 66% of increase in
production as a result of the pattern reconfiguration.
6 Conclusions
(Edited by Sun Yanhua)
Line drive T
9 spot
C
A
45
50
Recovery from a WAG process is a function of the injection rate as well as WAG ratio and the CO2 slug size .
WAG injection is effective in increasing the sweep efficiency of the injected CO2 in reservoirs. Simulation shows that tertiary CO2 flood would have a maximum recovery of 18% at a 1:1 WAG ratio and a CO2 slug size of 100% HCPV .
CO2 at a WAG 1:1 ratio. The injection of visEcous water and The optimum injection rate for the pattern is 300 RB/d of an incremental oil recovery of 32% and L20% respectively.
polymer results in a positive production response that yields inverted nine-spot pattern to a staCggered-line-drive improves Modeling suggests that converting the pattern from the the production oil rate by 66%I.The CO2 pattern modeling T
Caudle B H and Dyes A B. Improving miscible displacement by gasJarrel P M , Fox ACE , Stein M H , et al. Practical aspects of CO2 flooding .
water injection . Transactions of AIME . 1959 . 213 . 281 -284 Monograph Series . Society of Petroleum Engineers. 2002 Dphase CO2/oil mixtures . Paper SPE/DOE 24130 presented at SPE / Khan S A , Pope G A and Sepehrnoori K. Fluid characterization of threeEOklahoma
DOE Enhanced Oil Recovery Symposium , 22 - 24 April 1992, Tulsa, Lohrenz J , Bray B G and Clark C R. Calculating viscosities of reservoir fluids from their compositions . Journal of Petroleum Technology.
Martin D F and Taber J J. Carbon dioxide flooding . Journal of Petroleum Technology . 1992 . 44 ( 4 ): 396 -400 Mathis R L and Sears S O. Effect of CO2 flooding on dolomite reservoir rock . Paper SPE 13132 presented at SPE Annual Technical Conference and Exhibition , 16 -19 September 1984 , Houston, Texas Peng D Y and Robinson D B . A new two-constant equation of state.
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