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The conditions limiting CO2 storage in aquifers
Energy Convers. Mgmt Vol. 34, No. 9-11, pp. 959-966, 1993 Printed in Great Britain. All fights reserved
0196-8904/93 $6.00 + 0.00 Copyright © 1993 Pergamon Press Lid
THE CONDITIONS LIMITING CO2 STORAGE IN AQUIFERS
L. G. H. van der Meer TNO Institute of Applied C-enseience (IGG-TNO) P.O. Box 6012, 2600 JA DellL The Netherlands
ABSTRACt The storageof CO2 in aquifersor underground water-bearingzones is a possibleoption for confining CO2 produced by burning fossil fuel and thereby for alleviating its build-up in the atmosphere. Previous research on the practicality of this option lacked the overall limiting conditions. One of the major problems is the divergent conditions encountered if CO2 is stored underground. The storage process is affected by many individual mechanisms and practical limitations: fluid properties at reservoir conditions and the effects of the increa.~d storage pressure on these conditions, specific conditions of the rock matrix and the depositional environment of the geological formation. This paper presents the findings of a study to ascertain the practicalconditionlimitingof CO2 storagein aquifers. KEYWORDS Carbon dioxide storage, aquifers, limiting conditions.
INTRODUCTION Previous publications(van Engelenburg ct al, 1991) on CO2 storagein aquifers,especiallythose on storage capacity,have been based on general laws of physics which, by definitionare inappropriate.This lack of understanding of the storageconcept can be illustratedby the attempt to apply the law of the solubilityof C O 2 in water, in which the CO2 storage capacity of The Netherlands was based on the country'stotal underground reserves of water combined with the solubilityof CO2 in water under average subsurface conditions. This paper describes an attempt to find and set practical limiting conditions, so that realistic concepts and practicalstoragevolumes can be derived.For thisexercisethe storagesystem was subdivided into four:,the surface transportsystem, the injectionsystem, the storage reservoirand the integrityof the totalstorage systcm. SURFACE TRANSPORT SYSTEM The efficiency of any transport and/or storage system is dictated by the density of the goods to be transported. The phase diagram of pure CO2 shows a critical temperature of 31 oC (304.15 OK) and a critical pressure of 7.38 MPa. Below this temperature and/or pressure the CO2 is either in a liquid or vapour phase, as can be seen in figure I. The conditions for the solid state of CO2 are not applicable in this instance. At temperatures and pressures above the critical values the pure CO2 is in "supercritical state" which is characterized by a gas type of behaviour with a liquid type of density. For the temperature and pressure range of interest the supereritical state is the most desirable. For practical purposes a delivery pressure of 10 to 12 MPa at the injection location has to be assumed.
959
960
VAN DER MEER: CO2 STORAGE LIMITING CONDITIONS IN AQUIFERS
constraint 1) transport pressure: a delivery pressure of 10 to 12 MPa m the injection site. Pure CO2 as such is not corrosive. The presence of contaminants such as water (I-I20) and sulphur dioxide (S02) will enhance the corrosiveness of the fluid mixture. Water condensingfrom the C02 in the pipeline will cause serious corrosion problems and could lead to "slugs" of liquid being delivered at the C02 storage location. In general the C02 production site will be an average distance of 100 km from the storage location. For a CO2 flow rate of 15 000 ton/day (CO2 emission of a 750 MW coal-fired power station) it was calculated that a line with a 600 mm (24 inch) internal diameter would be needed. The pressure drop for this system was calculated to be less than 1 MPa. Using stainless steel for the transport and injection system is unpractical, for reasons of incremental cost. constraint 2) C02 purity: the C02 has to be delivered as pure as possible, the H20 content must be below 500 ppm wt.
TEMPERATURE [°C] 0 O-
a
50
1130
150
I
I
I
200 ,30
V-CO2 HYDRATE
.35
Pc=7.38
.40
500-
1000-
1
WELLHEAD CONDITIONS
CO 2
- .45
(11 M P a / 2 0 °C) 1500
u)
z
~3 15- .50
O
M=I
2000-
20
2500-
25
MOBILITY RATIO 'A' ,o,-..........o
;;i:>...........'o"...........0 ............0
.55
- .60
DENSITY 'A'
\
MOBILITY RATIO
-10 .65
\
3500 -
\
.70
\. ,, / A v e r a g e hydrostatic ",,/" conditions ('A')
- .75
J
72°~ O
4000-
.80
i ' DENSITY 'B'
4500-
/ Average geostatic conditions ('B') •---O
~,
'\ 5000-
-.85
,,
'%
-.90 ~40
50 I
Fig. 1:
[-30
",, %-
Est/mated aqu~er pressure-temperature plot
INJECHON SYSTEM Introduction In order to estimate the subsurface consequences of C02 storage in aquifers, it was assumed that a storage location must be able to handle 15 000 ton/day of CO2. This results in a surface volume of 8 150 0O0 Nm 3
VAN DER MEER: CO2 STORAGE LIMITING CONDITIONS IN AQUIFERS
961
of CO2 per day. It was de,sided to use 6 wells to handle this total CO2 surface volume; the resulting daily injection rate is 1 350 000 Nm 3 per well.
Verticai flow behaviour of C02 in an injection string In general it can be stated that the calculation of the pressure change in a vertical injection string is complicated by the conditions and/or the prediction of flow patterns. As a consequence of underground storage the pressure and temperature will increase, and hence CO2 will remain in a supercritical phase. To ascertain the influence of the size of the injection string, calculations were done with pipe diameters from 4.0 inches to 7.0 inches and pipeline lengths of 800 and 1800 m. To study the influence of increased CO2 flow, the calculations were done for CO2 injection rates from as little as 100 000 Nm3/day to a maximum of 1 500 000 Nm3/day. From the results (for the 800 m case see figure 2) it can be concluded that all the pipeline diameters investigated are capable of defivering the CO2 at the injection location. A smaller pipeline diameter or an increased injection flow rate will reduce the CO2 delivery pressure at this location. Furthermore it has to be realised that with smaller pipe diameters the velocity of CO2 in the pipe can reach unacceptable levels ff rates of C02 injection rates are high. Note that the critical velocity is dependent on the pressure. A corrosion inhibitor will be effective only if the the inhibiting film formed in the injection string is not broken up by the CO2 being injected at a high rate. Another argument for using larger diameters is the fact that the more this pressure is reduced as a result of frictional forces, the sooner compression power with a greater capacity will be required. This yields the the following constraint: constraint3) injection string: for weU injection rates of l 500 000 Nm3 the minimum diameter of the tubing is 5.5 inches. 15.8 16.0 16.2 e
16.4
/
E~; 16.6 o
~
16.6
iu ~ " .
17.0
E
/
J
17.2 17.4 17.6 17.8 18.0
V
0.25
0.5
0.75
1
1.25
1.5
CO2 injection rate (million Nm3/clay)
Fig. 2:
Well bore performance plot for 800 metre tubing
THE STORAGE RESERVOIR Introduction In a previous publication(van der Meer, 1992) I defined a number of constraintsresultingfrom geological and reservoir engineering considerations. Those relevant here are:
constraint 4) porosity: the aquifer should, by definition, possess intergranular pore space within the rock, and constraint 5) permeability: its constituent rock must be permeable to a fluid. constraint 6) The top of the aqu(fer must be located at a depth of at least 800 m. constraint 7) The ~ depth for C02 storage in The Netherlands is dictated by the top of the Visean Limestone.
962
VAN DER MEER: CO2 STORAGE LIMITING CONDITIONS IN AQUIFERS
constraint 8) Depending on the depth, an aquifer should have a permeability of at least 0.050-0.100 ln,n2. constraint 9) An impermeable layer (a seal) should directly overlie the aquifer. constraint 10) The aquifer should be part of a geological trap structure. Aquifer Pressure The total pressure at any depth in the subsurface, resulting from the combined weight of the formation rock and fluid, is known as the overburden pressure or geostatic pressure. In most sedimentary basins it increases linearly with depth. At a given depth the overburden pressure if'o) equals the fluid pressure (Pf) plus the grain or matric pressure (Pg, vertical lithostatic pressure) acting between the individual rock particles, i.e. Overburden pressure = Fluid pressure + Grain pressure
(1)
and, in particular, since the overburden pressure remains constant at any given depth, then d(fluid pressure) = - d(Grain pressure)
(2)
That is, a reduction in the fluid pressure leads to a corresponding increase in the grain pressure, and vice versa. In a perfectly normal case the water pressure at any depth can be calculated as:
dp Pw = {(~)wster x D} + P.
(3)
in which dp/dD, the water pressure gradient, is dependent on the chemical composition (salinity), and for "standard" water containing 100 parts per thousand of total dissolved solids has a value of 10.5 KPa m-1 (12.4 kPa m "1 for strong brines). D represents the vertical depth and Pa the atmospheric pressure. A similar equation can be drawn up for the temperature of the subsurface in which the pressures have to be replaced by respectively the temperature gradient (35 °C/hn in the Netherlands) and the average surface temperature. From the resulting data an average thermal-hydrostatic profile can be constmced (see figure 1). For clarity, in figure 1 a depth scale has been added next to the pressure scale. If we extend this plot with an extra line depicting the average geostatic conditions (average rock density of 2.3 g/crn3) we are able to visualize the theoretical pressure available for injection. The vertical distance between the average hydrostatic line and the average geostatic conditions line, related to the depth at the average hydrostatic condition line, will give the grain pressure at this depth. Figure 1 shows this average for two depths. From the plot it is clear that this grain pressure increases with depth.
constraint 11) storage pressure: the pressure availablefor C02 storagefalls with decreasing depth. The calculations of the behaviour of the injection string pressure and of the aquifer storage pressure enable some conclusions to be drawn about the reservoir engineering. In the case of a reservoir at 800 m the bottom hole injection pressure with 7 inch tubing exceeds the geostatic pressure. It must be remembered that this bottom hole pressure is the result of the CO2 surface pressure complemented by the hydrostatic pressure in the injection string. Reducing the well head pressure by 1 MPa will overcome this problem. The use of a minimum CO2 well head injection pressure confirms constraint 6. In the case of a reservoir at 1800 m depth, well head compression is needed if the average reservoir pressure in the drainage area of the well approaches the flowing bottom hole pressure of the well (approx. 27. MPa).
Displacement behaviour An earlier publication (van tier Meer et al., 1992) listed 8 displacement effects which were classified according to their relative effect on a CO2 water storage process. It was concluded that two effects on the large scale would dominate the displacement process. Density differences between the CO2 and the aquifer water will result in gravity segregation. The second dominating effect results from the difference in mobility between CO2 and water. The calculated mobility ratios for a process in which CO2 displaces water suggest
VAN DER MEER: CO2 STORAGE LIMITINGCONDITIONS IN AQUIFERS
963
there will be substantial viscous fingering effects. Below I describe an attempt to find the constraints limiting these effects.
Gravity segregation To illustrate the engineering difficulties related to the gravity segregation effects, in figure 1 1 have plotted the CO2 density at the average hydrostatic condition and at the average geostatic conditions. The shapes of these curves are largely dependent on the combined effects of temperature and pressure. When analysing the temperature and pressure bebaviour of a CO2 storage reservoir, the pressure is the easiest to predict and to control The situation with the CO2 temperature profile between the injected CO2 and the aquifer water is complex and hard to predict. After the initial stage the relatively colder injected 032 will find warmer water only at the displacement front, so the temperature profile will be rather flat in the C02 bubble and be steeper nearer the C02-water interface. From this we can conclude that the trends in C02 density in a C02 storage reservoir are complex and difficultto predict. On the other hand, the two density curves on plot 1 show that the density in the entire pressure and temperature range of interest stays below the density of aquifer water. In the case of conditiom close to the average hydrostatic conditions the gravity segregation effects will be more extreme than those at the average geostatic conditions.
constraint 12:C02 density: the density of C02 at storage conditions will be less than the aquifer water density, resulting in gravity segregation. Viscous fingering The displacement of one fluid by another in a homogeneous porous media is mechanically simple when the mobility ratio of the two fluids is less than or equal to one and when gravity does not influence the displacement by segregating the two fluids. For these conditions, the displaced fluid is moving efficiently ahead of the displacing fluid and the latter only penetrates the displacing fluid by dispersion. For mobility ratios greater than one, the displacement has a very different character. The displacing fluid front becomes unstable, and numerous fingers of displacing fluid develop and penetrate the displaced fluid in an irregular fashion. In the case of a CO2 storage process these fingers will result in a poor sweep efficiency and early breakthroughs of the CO2 at possible spillpoints of a storage reservoir. To get some indication of the mobility ratio development at CO2 storage conditions I attemted to calculate these values for the two average conditions, despite the poor viscosity data (Goodrich, 1980, Beat, 1946) available for CO2. The two derived curves are plotted in figure I. As can be observed, for both the reservoir cases (800 and 1800 deep), the mobility ratio converges close to 1 for increasing depth. The mobility ratio is close to 25 for the initial conditions of the 800 m reservoir;, as pressure increases in response to CO2 injection, the mobility ratio falls to 11 at the average geostatic conditions. These values are respectively 11 and 5.5 for the reservoir at 1800 m. As a result we can conclude that the mobility ratio declines with increasing pressure (i.e. depth). It is debatable if this phenomenon is attractive for CO2 storage. In the initial stages of C02 storage in a reservoir at relatively shallow depth the dispersive qualities of C02 are rather great which can be very unattractive in the case of a small aquifer with one or two spillpoints. A storage reservoir at greater depth with a mobility ratio as close as possible to 1 will be more attractive for storing CO2 in a confined volume.
constraint 13: viscous fingering: viscous fingering will dominate the displacement front at shallow reservoirs. Thie deeper the reservoir, the weaker this effect. Integr~ of the total storage system In an earlier publication (van tier Meer et al. 1992) the results of a limited simulation study were reported. A 2-D radial model was used to simulate a dome-shaped part of a larger aquifer (depth 800 m, porosity Brussel sand 30 - 36 %,permeability .05 - .6 pm2, thickness 50 m). This part of the aquifer was selected because it satisfied all conswaints, especially the one concerning the geological trap structure.The results of this study revealed a storage efficiency of only 3.05 % and showed that CO2 reached the adopted spillpoint after 8 years of injection. Both results were dictated by the selected geometry of the dome-shaped part of the aquifer. In order to study the effects of injection beyond the original spiHpoint, and the effects of abandoning the reservoir, a full 3-D reservoir study was done.
964
VAN DER MEER: CO2 STORAGE LIMITING CONDITIONS IN AQUIFERS
Model description The same well configuration was used for the new model (6 wells, injection rate 1 350 000 Nm3/d, all wells on a circle with a radius of :1:500 m at the apex of the dome) The model covers a part (50 x 30 Kin) of the province of Grouingen, in the Netherlands which includes the original dome-shaped structure (figure 3). The area was overlain with gridblocks with a dimension of 1 km. In the area penetrated by the wells the larger blocks were subdivided into blocks of 200 m square. This resulted in a total grid of 63 by 40 gridblocks. Because of the lack of data an uniform thickness of 50 m was assumed for the whole model. This total thickness was represented in the model by 5 layers with uniform properties and incremental thickness (5, 5, 10, 15, 15 m).
Fig. 3:
Top of structureof aquifer in Groningen on which the simulatiionwas done and the grid layout used.
The total time covered by the simulation consisted of two cycles: the first one is the C02 injection cycle and the second a shutin cycles. The injection cycle span a period of 20 years and the shutin a period of 10 years. The function of the first cycle was mainly to investigate the CO2 distribution beyond the original spillpoint, the pressure distribution and the field target injection rate development. The second period could indicate the behaviour of the storage reservoir after its abandonment, especially with respect to the CO2 and pressure distribution. The black-oil model from the VIP family of simulators marketed by Westem Atlas Software was used. This three-phase (gas, oil, water) simulator was used in the gas-water mode where the available gas phase was used to simulate the CO2 at critical conditions. The simulator is isothermal and does not simulate viscous fingering effects, on the other hand it takes full account of possible density difference and phase mobflitles of the two phases. Furthermore, the two phase are completely separated i.e. there is no diffusion, dispersion or absorption of CO2 into the water phase. It is thought that these only have effects on a small scale i.e. within metres and over a very long time.
Simulation results The injectivity of a storage reservoir largely depends on the aquifer permeability. As a worst case, the model was run with a constant permeability of .050 lain2. The maximum Flowing Bottom Hole Pressure (FBHP, 16.5 Mpa) will be reached after 5 years as a direct result of this permeability. After 5 years of simulation this FBHP is not enough to deliver the targeted injection rate, resulting in a slowly declining CO2 injection rate. Figure 4 shows this effect graphically. In order to increase the durability of the injection plateau rate a second simulation run was done with a uniform horizontal permeability of .150 iun 2. In this run the plateau rate for the total simulated period (20 years) could be injected with enough pressure to spare (after 20 years FBI-IP - 14.6 MPa) to guarantee another 10 years of injection at the plateau rate.
VAN DER MEER: CO2 STORAGE LIMITINGCONDITIONS IN AQUIFERS 17
965
100130
/
~>o<>¢oooo-.~>---o---~o--o--or<>--o-<--0
16
~ l'
l /
I I I'~ I
ml D~ " = --'~ m' I' " mm
--
14
i
7000 ,
12
1
FIIHP(50)
II
0
1000
;
Qinj.(150)
E3
Qmj.(m)
2000
3000
4(]o0
4000 TIME
Fig. 4:
5000
6000
7000
8000
(days)
Storagefield injectivityperformance
Examination of the CO2 concentration distribution, alter 20 years of CO2 injection at plateau rate (.150 gm2 case), is showing a CO2 bubble with an average horizontal radius of 13.5 kin or covering a total area of 752 km2. The vertical distribution of the CO2 is pore. The bubble is mainly penetrating the upper three layers (20 m) with the exception of areas around the wells (wells are perforated in the top four layers, a total of 35 m out of a total formation thickness of 50 m). Figure 5 is a graphical representation of the concentration distribution in the top layer (besides a 3-D representation, also a projection of the circular contour lines on the base plane is shown)
0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.i O' 300 0
4bU
Fig. 5:
C02 concentration (fraction of pore volume) after 20 years injection at plateau injection rate.
966
VAN DER MEER: CO2 STORAGE LIMITINGCONDITIONS IN AQUIFERS
Figure 6 shows the CO2 concentration of the top layer after another 10 years of shutin. In this shutin period the CO2 migration is only based on the pressure distribution initially built up in the storage reservoir. This migration activity decays exponentially like. In I0 years the C02 bubble has grown in all directions by approximately 1 kin. This effect depend highly on the geometric shape of the top of the structure.
0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.i 0 300 ]
q~u
Fig. 6:
C02 concentration after 20 years injection at plateau injection rate and 10 years of shutin.
CONCLUSIONS From the result of the study ~3orted in this paper it can be concluded that it is extremely difficult to predict any total CO2 storage volume. Besides the individual geological possibilities for CO2 storage in an aquifer, the findings show that the CO2 properties vary greatly under storage conditions. In general itcan be stated that deeper aquifers arc more attractiveas potential storage reservoirs in terms of the CO2 properties and the available storage pressure. With increasing pressure the density differences between CO2 and water become less extreme and the mobility ratio diminishes. Furthermore the pressure available for storage increases with depth.
In order to obtain a sustainable plateau injection rate the aquifer should be very permeable. Present calo_~la_aonsregarding the storage efficiencyof an aquifer are subjective due to the lack of definition of the total pore volume available for CO2 storage. International standards are needed. REFERENCE Beal, C. (1946), Tram AIME, voL 165, p. 97. Goodrich, J.H. (1980), "Target Reservoir for CO2 Miscible Flooding - Final Report", Gray Federal, Houston, Texas, USA, U.S. DOFJMC/08341-17. van Engelenburg, B.C.W., Blok, K. (1991), "Prospects for the disposal of carbon dioxide in aquifers", Department of Science, Technology and Society of the University of Utrecht, The Netherlands, Report No. G-91006. van der Meer, L.G.H. (1992), "Investigations regarding the storage of carbon dioxide in aquifers in The Netherlands", Energy Convers. Mgmt Vol.33, No. 5-8, pp. 611-618. van der Meer, L.G.H., Griffioen, J., Geel, C.R. (1992), "Investigations regarding the storage of carbon dioxide in aquifers in The Netherlands", IGG-TNO-report OS 92-24-A, 105 pages.
0196-8904/93 $6.00 + 0.00 Copyright © 1993 Pergamon Press Lid
THE CONDITIONS LIMITING CO2 STORAGE IN AQUIFERS
L. G. H. van der Meer TNO Institute of Applied C-enseience (IGG-TNO) P.O. Box 6012, 2600 JA DellL The Netherlands
ABSTRACt The storageof CO2 in aquifersor underground water-bearingzones is a possibleoption for confining CO2 produced by burning fossil fuel and thereby for alleviating its build-up in the atmosphere. Previous research on the practicality of this option lacked the overall limiting conditions. One of the major problems is the divergent conditions encountered if CO2 is stored underground. The storage process is affected by many individual mechanisms and practical limitations: fluid properties at reservoir conditions and the effects of the increa.~d storage pressure on these conditions, specific conditions of the rock matrix and the depositional environment of the geological formation. This paper presents the findings of a study to ascertain the practicalconditionlimitingof CO2 storagein aquifers. KEYWORDS Carbon dioxide storage, aquifers, limiting conditions.
INTRODUCTION Previous publications(van Engelenburg ct al, 1991) on CO2 storagein aquifers,especiallythose on storage capacity,have been based on general laws of physics which, by definitionare inappropriate.This lack of understanding of the storageconcept can be illustratedby the attempt to apply the law of the solubilityof C O 2 in water, in which the CO2 storage capacity of The Netherlands was based on the country'stotal underground reserves of water combined with the solubilityof CO2 in water under average subsurface conditions. This paper describes an attempt to find and set practical limiting conditions, so that realistic concepts and practicalstoragevolumes can be derived.For thisexercisethe storagesystem was subdivided into four:,the surface transportsystem, the injectionsystem, the storage reservoirand the integrityof the totalstorage systcm. SURFACE TRANSPORT SYSTEM The efficiency of any transport and/or storage system is dictated by the density of the goods to be transported. The phase diagram of pure CO2 shows a critical temperature of 31 oC (304.15 OK) and a critical pressure of 7.38 MPa. Below this temperature and/or pressure the CO2 is either in a liquid or vapour phase, as can be seen in figure I. The conditions for the solid state of CO2 are not applicable in this instance. At temperatures and pressures above the critical values the pure CO2 is in "supercritical state" which is characterized by a gas type of behaviour with a liquid type of density. For the temperature and pressure range of interest the supereritical state is the most desirable. For practical purposes a delivery pressure of 10 to 12 MPa at the injection location has to be assumed.
959
960
VAN DER MEER: CO2 STORAGE LIMITING CONDITIONS IN AQUIFERS
constraint 1) transport pressure: a delivery pressure of 10 to 12 MPa m the injection site. Pure CO2 as such is not corrosive. The presence of contaminants such as water (I-I20) and sulphur dioxide (S02) will enhance the corrosiveness of the fluid mixture. Water condensingfrom the C02 in the pipeline will cause serious corrosion problems and could lead to "slugs" of liquid being delivered at the C02 storage location. In general the C02 production site will be an average distance of 100 km from the storage location. For a CO2 flow rate of 15 000 ton/day (CO2 emission of a 750 MW coal-fired power station) it was calculated that a line with a 600 mm (24 inch) internal diameter would be needed. The pressure drop for this system was calculated to be less than 1 MPa. Using stainless steel for the transport and injection system is unpractical, for reasons of incremental cost. constraint 2) C02 purity: the C02 has to be delivered as pure as possible, the H20 content must be below 500 ppm wt.
TEMPERATURE [°C] 0 O-
a
50
1130
150
I
I
I
200 ,30
V-CO2 HYDRATE
.35
Pc=7.38
.40
500-
1000-
1
WELLHEAD CONDITIONS
CO 2
- .45
(11 M P a / 2 0 °C) 1500
u)
z
~3 15- .50
O
M=I
2000-
20
2500-
25
MOBILITY RATIO 'A' ,o,-..........o
;;i:>...........'o"...........0 ............0
.55
- .60
DENSITY 'A'
\
MOBILITY RATIO
-10 .65
\
3500 -
\
.70
\. ,, / A v e r a g e hydrostatic ",,/" conditions ('A')
- .75
J
72°~ O
4000-
.80
i ' DENSITY 'B'
4500-
/ Average geostatic conditions ('B') •---O
~,
'\ 5000-
-.85
,,
'%
-.90 ~40
50 I
Fig. 1:
[-30
",, %-
Est/mated aqu~er pressure-temperature plot
INJECHON SYSTEM Introduction In order to estimate the subsurface consequences of C02 storage in aquifers, it was assumed that a storage location must be able to handle 15 000 ton/day of CO2. This results in a surface volume of 8 150 0O0 Nm 3
VAN DER MEER: CO2 STORAGE LIMITING CONDITIONS IN AQUIFERS
961
of CO2 per day. It was de,sided to use 6 wells to handle this total CO2 surface volume; the resulting daily injection rate is 1 350 000 Nm 3 per well.
Verticai flow behaviour of C02 in an injection string In general it can be stated that the calculation of the pressure change in a vertical injection string is complicated by the conditions and/or the prediction of flow patterns. As a consequence of underground storage the pressure and temperature will increase, and hence CO2 will remain in a supercritical phase. To ascertain the influence of the size of the injection string, calculations were done with pipe diameters from 4.0 inches to 7.0 inches and pipeline lengths of 800 and 1800 m. To study the influence of increased CO2 flow, the calculations were done for CO2 injection rates from as little as 100 000 Nm3/day to a maximum of 1 500 000 Nm3/day. From the results (for the 800 m case see figure 2) it can be concluded that all the pipeline diameters investigated are capable of defivering the CO2 at the injection location. A smaller pipeline diameter or an increased injection flow rate will reduce the CO2 delivery pressure at this location. Furthermore it has to be realised that with smaller pipe diameters the velocity of CO2 in the pipe can reach unacceptable levels ff rates of C02 injection rates are high. Note that the critical velocity is dependent on the pressure. A corrosion inhibitor will be effective only if the the inhibiting film formed in the injection string is not broken up by the CO2 being injected at a high rate. Another argument for using larger diameters is the fact that the more this pressure is reduced as a result of frictional forces, the sooner compression power with a greater capacity will be required. This yields the the following constraint: constraint3) injection string: for weU injection rates of l 500 000 Nm3 the minimum diameter of the tubing is 5.5 inches. 15.8 16.0 16.2 e
16.4
/
E~; 16.6 o
~
16.6
iu ~ " .
17.0
E
/
J
17.2 17.4 17.6 17.8 18.0
V
0.25
0.5
0.75
1
1.25
1.5
CO2 injection rate (million Nm3/clay)
Fig. 2:
Well bore performance plot for 800 metre tubing
THE STORAGE RESERVOIR Introduction In a previous publication(van der Meer, 1992) I defined a number of constraintsresultingfrom geological and reservoir engineering considerations. Those relevant here are:
constraint 4) porosity: the aquifer should, by definition, possess intergranular pore space within the rock, and constraint 5) permeability: its constituent rock must be permeable to a fluid. constraint 6) The top of the aqu(fer must be located at a depth of at least 800 m. constraint 7) The ~ depth for C02 storage in The Netherlands is dictated by the top of the Visean Limestone.
962
VAN DER MEER: CO2 STORAGE LIMITING CONDITIONS IN AQUIFERS
constraint 8) Depending on the depth, an aquifer should have a permeability of at least 0.050-0.100 ln,n2. constraint 9) An impermeable layer (a seal) should directly overlie the aquifer. constraint 10) The aquifer should be part of a geological trap structure. Aquifer Pressure The total pressure at any depth in the subsurface, resulting from the combined weight of the formation rock and fluid, is known as the overburden pressure or geostatic pressure. In most sedimentary basins it increases linearly with depth. At a given depth the overburden pressure if'o) equals the fluid pressure (Pf) plus the grain or matric pressure (Pg, vertical lithostatic pressure) acting between the individual rock particles, i.e. Overburden pressure = Fluid pressure + Grain pressure
(1)
and, in particular, since the overburden pressure remains constant at any given depth, then d(fluid pressure) = - d(Grain pressure)
(2)
That is, a reduction in the fluid pressure leads to a corresponding increase in the grain pressure, and vice versa. In a perfectly normal case the water pressure at any depth can be calculated as:
dp Pw = {(~)wster x D} + P.
(3)
in which dp/dD, the water pressure gradient, is dependent on the chemical composition (salinity), and for "standard" water containing 100 parts per thousand of total dissolved solids has a value of 10.5 KPa m-1 (12.4 kPa m "1 for strong brines). D represents the vertical depth and Pa the atmospheric pressure. A similar equation can be drawn up for the temperature of the subsurface in which the pressures have to be replaced by respectively the temperature gradient (35 °C/hn in the Netherlands) and the average surface temperature. From the resulting data an average thermal-hydrostatic profile can be constmced (see figure 1). For clarity, in figure 1 a depth scale has been added next to the pressure scale. If we extend this plot with an extra line depicting the average geostatic conditions (average rock density of 2.3 g/crn3) we are able to visualize the theoretical pressure available for injection. The vertical distance between the average hydrostatic line and the average geostatic conditions line, related to the depth at the average hydrostatic condition line, will give the grain pressure at this depth. Figure 1 shows this average for two depths. From the plot it is clear that this grain pressure increases with depth.
constraint 11) storage pressure: the pressure availablefor C02 storagefalls with decreasing depth. The calculations of the behaviour of the injection string pressure and of the aquifer storage pressure enable some conclusions to be drawn about the reservoir engineering. In the case of a reservoir at 800 m the bottom hole injection pressure with 7 inch tubing exceeds the geostatic pressure. It must be remembered that this bottom hole pressure is the result of the CO2 surface pressure complemented by the hydrostatic pressure in the injection string. Reducing the well head pressure by 1 MPa will overcome this problem. The use of a minimum CO2 well head injection pressure confirms constraint 6. In the case of a reservoir at 1800 m depth, well head compression is needed if the average reservoir pressure in the drainage area of the well approaches the flowing bottom hole pressure of the well (approx. 27. MPa).
Displacement behaviour An earlier publication (van tier Meer et al., 1992) listed 8 displacement effects which were classified according to their relative effect on a CO2 water storage process. It was concluded that two effects on the large scale would dominate the displacement process. Density differences between the CO2 and the aquifer water will result in gravity segregation. The second dominating effect results from the difference in mobility between CO2 and water. The calculated mobility ratios for a process in which CO2 displaces water suggest
VAN DER MEER: CO2 STORAGE LIMITINGCONDITIONS IN AQUIFERS
963
there will be substantial viscous fingering effects. Below I describe an attempt to find the constraints limiting these effects.
Gravity segregation To illustrate the engineering difficulties related to the gravity segregation effects, in figure 1 1 have plotted the CO2 density at the average hydrostatic condition and at the average geostatic conditions. The shapes of these curves are largely dependent on the combined effects of temperature and pressure. When analysing the temperature and pressure bebaviour of a CO2 storage reservoir, the pressure is the easiest to predict and to control The situation with the CO2 temperature profile between the injected CO2 and the aquifer water is complex and hard to predict. After the initial stage the relatively colder injected 032 will find warmer water only at the displacement front, so the temperature profile will be rather flat in the C02 bubble and be steeper nearer the C02-water interface. From this we can conclude that the trends in C02 density in a C02 storage reservoir are complex and difficultto predict. On the other hand, the two density curves on plot 1 show that the density in the entire pressure and temperature range of interest stays below the density of aquifer water. In the case of conditiom close to the average hydrostatic conditions the gravity segregation effects will be more extreme than those at the average geostatic conditions.
constraint 12:C02 density: the density of C02 at storage conditions will be less than the aquifer water density, resulting in gravity segregation. Viscous fingering The displacement of one fluid by another in a homogeneous porous media is mechanically simple when the mobility ratio of the two fluids is less than or equal to one and when gravity does not influence the displacement by segregating the two fluids. For these conditions, the displaced fluid is moving efficiently ahead of the displacing fluid and the latter only penetrates the displacing fluid by dispersion. For mobility ratios greater than one, the displacement has a very different character. The displacing fluid front becomes unstable, and numerous fingers of displacing fluid develop and penetrate the displaced fluid in an irregular fashion. In the case of a CO2 storage process these fingers will result in a poor sweep efficiency and early breakthroughs of the CO2 at possible spillpoints of a storage reservoir. To get some indication of the mobility ratio development at CO2 storage conditions I attemted to calculate these values for the two average conditions, despite the poor viscosity data (Goodrich, 1980, Beat, 1946) available for CO2. The two derived curves are plotted in figure I. As can be observed, for both the reservoir cases (800 and 1800 deep), the mobility ratio converges close to 1 for increasing depth. The mobility ratio is close to 25 for the initial conditions of the 800 m reservoir;, as pressure increases in response to CO2 injection, the mobility ratio falls to 11 at the average geostatic conditions. These values are respectively 11 and 5.5 for the reservoir at 1800 m. As a result we can conclude that the mobility ratio declines with increasing pressure (i.e. depth). It is debatable if this phenomenon is attractive for CO2 storage. In the initial stages of C02 storage in a reservoir at relatively shallow depth the dispersive qualities of C02 are rather great which can be very unattractive in the case of a small aquifer with one or two spillpoints. A storage reservoir at greater depth with a mobility ratio as close as possible to 1 will be more attractive for storing CO2 in a confined volume.
constraint 13: viscous fingering: viscous fingering will dominate the displacement front at shallow reservoirs. Thie deeper the reservoir, the weaker this effect. Integr~ of the total storage system In an earlier publication (van tier Meer et al. 1992) the results of a limited simulation study were reported. A 2-D radial model was used to simulate a dome-shaped part of a larger aquifer (depth 800 m, porosity Brussel sand 30 - 36 %,permeability .05 - .6 pm2, thickness 50 m). This part of the aquifer was selected because it satisfied all conswaints, especially the one concerning the geological trap structure.The results of this study revealed a storage efficiency of only 3.05 % and showed that CO2 reached the adopted spillpoint after 8 years of injection. Both results were dictated by the selected geometry of the dome-shaped part of the aquifer. In order to study the effects of injection beyond the original spiHpoint, and the effects of abandoning the reservoir, a full 3-D reservoir study was done.
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VAN DER MEER: CO2 STORAGE LIMITING CONDITIONS IN AQUIFERS
Model description The same well configuration was used for the new model (6 wells, injection rate 1 350 000 Nm3/d, all wells on a circle with a radius of :1:500 m at the apex of the dome) The model covers a part (50 x 30 Kin) of the province of Grouingen, in the Netherlands which includes the original dome-shaped structure (figure 3). The area was overlain with gridblocks with a dimension of 1 km. In the area penetrated by the wells the larger blocks were subdivided into blocks of 200 m square. This resulted in a total grid of 63 by 40 gridblocks. Because of the lack of data an uniform thickness of 50 m was assumed for the whole model. This total thickness was represented in the model by 5 layers with uniform properties and incremental thickness (5, 5, 10, 15, 15 m).
Fig. 3:
Top of structureof aquifer in Groningen on which the simulatiionwas done and the grid layout used.
The total time covered by the simulation consisted of two cycles: the first one is the C02 injection cycle and the second a shutin cycles. The injection cycle span a period of 20 years and the shutin a period of 10 years. The function of the first cycle was mainly to investigate the CO2 distribution beyond the original spillpoint, the pressure distribution and the field target injection rate development. The second period could indicate the behaviour of the storage reservoir after its abandonment, especially with respect to the CO2 and pressure distribution. The black-oil model from the VIP family of simulators marketed by Westem Atlas Software was used. This three-phase (gas, oil, water) simulator was used in the gas-water mode where the available gas phase was used to simulate the CO2 at critical conditions. The simulator is isothermal and does not simulate viscous fingering effects, on the other hand it takes full account of possible density difference and phase mobflitles of the two phases. Furthermore, the two phase are completely separated i.e. there is no diffusion, dispersion or absorption of CO2 into the water phase. It is thought that these only have effects on a small scale i.e. within metres and over a very long time.
Simulation results The injectivity of a storage reservoir largely depends on the aquifer permeability. As a worst case, the model was run with a constant permeability of .050 lain2. The maximum Flowing Bottom Hole Pressure (FBHP, 16.5 Mpa) will be reached after 5 years as a direct result of this permeability. After 5 years of simulation this FBHP is not enough to deliver the targeted injection rate, resulting in a slowly declining CO2 injection rate. Figure 4 shows this effect graphically. In order to increase the durability of the injection plateau rate a second simulation run was done with a uniform horizontal permeability of .150 iun 2. In this run the plateau rate for the total simulated period (20 years) could be injected with enough pressure to spare (after 20 years FBI-IP - 14.6 MPa) to guarantee another 10 years of injection at the plateau rate.
VAN DER MEER: CO2 STORAGE LIMITINGCONDITIONS IN AQUIFERS 17
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5000
6000
7000
8000
(days)
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Examination of the CO2 concentration distribution, alter 20 years of CO2 injection at plateau rate (.150 gm2 case), is showing a CO2 bubble with an average horizontal radius of 13.5 kin or covering a total area of 752 km2. The vertical distribution of the CO2 is pore. The bubble is mainly penetrating the upper three layers (20 m) with the exception of areas around the wells (wells are perforated in the top four layers, a total of 35 m out of a total formation thickness of 50 m). Figure 5 is a graphical representation of the concentration distribution in the top layer (besides a 3-D representation, also a projection of the circular contour lines on the base plane is shown)
0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.i O' 300 0
4bU
Fig. 5:
C02 concentration (fraction of pore volume) after 20 years injection at plateau injection rate.
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VAN DER MEER: CO2 STORAGE LIMITINGCONDITIONS IN AQUIFERS
Figure 6 shows the CO2 concentration of the top layer after another 10 years of shutin. In this shutin period the CO2 migration is only based on the pressure distribution initially built up in the storage reservoir. This migration activity decays exponentially like. In I0 years the C02 bubble has grown in all directions by approximately 1 kin. This effect depend highly on the geometric shape of the top of the structure.
0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.i 0 300 ]
q~u
Fig. 6:
C02 concentration after 20 years injection at plateau injection rate and 10 years of shutin.
CONCLUSIONS From the result of the study ~3orted in this paper it can be concluded that it is extremely difficult to predict any total CO2 storage volume. Besides the individual geological possibilities for CO2 storage in an aquifer, the findings show that the CO2 properties vary greatly under storage conditions. In general itcan be stated that deeper aquifers arc more attractiveas potential storage reservoirs in terms of the CO2 properties and the available storage pressure. With increasing pressure the density differences between CO2 and water become less extreme and the mobility ratio diminishes. Furthermore the pressure available for storage increases with depth.
In order to obtain a sustainable plateau injection rate the aquifer should be very permeable. Present calo_~la_aonsregarding the storage efficiencyof an aquifer are subjective due to the lack of definition of the total pore volume available for CO2 storage. International standards are needed. REFERENCE Beal, C. (1946), Tram AIME, voL 165, p. 97. Goodrich, J.H. (1980), "Target Reservoir for CO2 Miscible Flooding - Final Report", Gray Federal, Houston, Texas, USA, U.S. DOFJMC/08341-17. van Engelenburg, B.C.W., Blok, K. (1991), "Prospects for the disposal of carbon dioxide in aquifers", Department of Science, Technology and Society of the University of Utrecht, The Netherlands, Report No. G-91006. van der Meer, L.G.H. (1992), "Investigations regarding the storage of carbon dioxide in aquifers in The Netherlands", Energy Convers. Mgmt Vol.33, No. 5-8, pp. 611-618. van der Meer, L.G.H., Griffioen, J., Geel, C.R. (1992), "Investigations regarding the storage of carbon dioxide in aquifers in The Netherlands", IGG-TNO-report OS 92-24-A, 105 pages.