acid gas interfacial tensions and their impact on acid gas geological storage

international journal of greenhouse gas control 2 (2008) 594–604

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Water/acid gas interfacial tensions and their impact on acid gas geological storage Virenkumar Shah a,b, Daniel Broseta a,*, Gerard Mouronval b, Franc¸ois Montel b a b

Laboratoire des Fluides Complexes, UMR 5150, Universite´ de Pau et des Pays de l’Adour, BP 1155, 64013 Pau, Cedex, France TOTAL SA, Centre Scientifique et Technique Jean Feger, 64018 Pau, Cedex, France

article info

abstract

Article history:

Acid gas geological disposal is a promising process to reduce CO2 atmospheric emissions

Received 17 December 2007

and an environment-friendly and economic alternative to the transformation of H2S into

Received in revised form

sulphur by the Claus process. Acid gas confinement in geological formations is to a large

4 February 2008

extent controlled by the capillary properties of the water/acid–gas/caprock system, because

Accepted 7 February 2008

a significant fraction of the injected gas rises buoyantly and accumulates beneath the

Published on line 17 March 2008

caprock. These properties include the water/acid gas interfacial tension (IFT), to which the so-called capillary entry pressure of the gas in the water-saturated caprock is proportional.

Keywords:

In this paper we present the first ever systematic water/acid gas IFT measurements carried

Interfacial tension

out by the pendant drop technique under geological storage conditions. We performed IFT

Geological storage

measurements for water/H2S systems over a large range of pressure (up to P = 15 MPa) and

Acid gas

temperature (up to T = 120 8C). Water/H2S IFT decreases with increasing P and levels off at

Carbon dioxide (CO2)

around 9–10 mN/m at high T (70 8C) and P (>12 MPa). The latter values are around 30–40% of

Hydrogen sulphide (H2S)

water/CO2 IFTs, and around 20% of water/CH4 IFTs at similar T and P conditions. The IFT

Capillary pressure

between water and a CO2 + H2S mixture at T = 77 8C and P > 7.5 MPa is observed to be approximately equal to the molar average IFT of the water/CO2 and water/H2S binary mixtures. Thus, when the H2S content in the stored acid gas increases the capillary entry pressure decreases, together with the maximum height of acid gas column and potential storage capacity of a given geological formation. Hence, considerable attention should be exercised when refilling with a H2S-rich acid gas a depleted gas reservoir, or a depleted oil reservoir with a gas cap: in the case of hydrocarbon reservoirs that were initially (i.e., at the time of their discovery) close to capillary leakage, acid gas leakage through the caprock will inevitably occur if the refilling pressure approaches the initial reservoir pressure. # 2008 Elsevier Ltd. All rights reserved.

1.

Introduction

Carbon dioxide storage in geological formations such as deep saline aquifers or depleted hydrocarbon reservoirs appears to be an attractive process for mitigating CO2 emissions. In this respect, a huge research effort is currently being devoted on issues related to the integrity of the formation over an extended period of time. Leakage rates in

the range of 0.01–1% per year are considered acceptable (Bachu, 2008). As an increasing number of CO2- and H2S-containing (sour) gas reservoirs are being exploited in the world, there is a growing interest for injecting and storing in geological formations the acid gas that is separated from the (sour) natural gas in gas processing plants. (Thus, in practice the acid gas also contains traces of hydrocarbon components.) In

* Corresponding author. Tel.: +33 5 59407685; fax: +33 5 59407725. E-mail address: [email protected] (D. Broseta). 1750-5836/$ – see front matter # 2008 Elsevier Ltd. All rights reserved. doi:10.1016/j.ijggc.2008.02.002

international journal of greenhouse gas control 2 (2008) 594–604

Western Canada, H2S-containing acid gases have been injected in more than 40 deep aquifers or depleted hydrocarbon reservoirs for about 15 years, albeit on a moderate scale: approximately 3 million tons of CO2 and 3 million tons of H2S have been injected, with a maximum 83% of H2S in the injected acid gas (Bachu, 2008). The interest of injecting H2S (together with CO2) in geological formations is to avoid desulphurization of H2S through the Claus process, which has in fact many drawbacks, both economic and environmental: 1. Sulphur production is increasing day by day because of increasing exploitation of sour gas reservoirs. Many of the giant gas fields under production or yet to be developed, e.g., in the Middle East countries and in the countries surrounding the Caspian Sea, contain high concentrations of H2S. The current global supply of sulphur exceeds worldwide consumption by 2.5 million tons per year (AbouSayed et al., 2005) and this oversupply is expected to increase. Henceforth, a steady decline in sulphur price is observed. Thus, the economic burden of this process is increasing with time. 2. As the production of sulphur is in excess of demand, there are problems related with the storage of enormous quantities of sulphur, which reacts with air to produce SO2 and if not safely stored this SO2 may escape into the atmosphere (e.g., at Tengiz field, the storage of sulphur on a ground surface resulted in a legal action by Kazakhstan government; Abou-Sayed et al., 2005). 3. In this process tail gas is burnt and then emitted in the atmosphere in the form of SO2 and CO2, which is the least environment-friendly aspect. Thus, when H2S is present in an acid gas stream, an economic and environment-friendly option is to co-inject and store H2S along with CO2 in a geological formation. However, the implementation of this option on a large scale requires a proper assessment of the effects induced by the presence of H2S on the integrity of the formation. In this respect, the studies conducted on the various possible CO2 leakage mechanisms need to be extended to acid gases containing significant amounts of H2S. In acid gas geological storage, during and shortly after the injection period, a significant fraction of the injected gas is expected to rise buoyantly and accumulate beneath the geological seal (caprock), a low-permeable (most often clayey or evaporitic) porous medium usually saturated with water. This mode of trapping, referred to as ‘hydrodynamic trapping’ (Bachu et al., 1994; Juanes et al., 2006), is the storage mode of interest in this paper. The remaining fraction of the injected gas is stored in the formation by other modes of storage like capillary or pore-level trapping (which consists in a residual phase of disconnected gas droplets; Juanes et al., 2006), mineralization and dissolution in brine or residual oil. This fraction is stored ‘permanently’: the injected acid gas will not reach to surface any sooner than the other fluid species originally present in the formation. The importance of each storage mode depends on the characteristics of the formation, injected fluid and time period after the injection (mineralization and dissolution are very slow processes; Bachu et al., 2007).

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There are two possible mechanisms of caprock failure caused by the presence of the underlying overpressured gas. Mechanical failure due to hydraulic fracturing or fault reactivation occurs when gas pressure exceeds a certain value (Pm). Capillary failure (or breakthrough) occurs when pressure exceeds the so-called displacement pressure Pd, above which water in the caprock is displaced by the intruding gas phase. The latter failure mechanism leads to a more pervasive and slower leakage than the former (Gluyas and Swarbrick, 2004). The two pressures Pd and Pm must be determined as precisely as possible prior to the implementation of any gas injection and storage project in a given formation. A conservative approach consists in keeping the formation pressure below the minimum of these two characteristic pressures during and after the injection; the value of this minimum, Pd or Pm, can be converted into a maximum height of gas column and a storage capacity, defined as the maximum quantity of gas that can be trapped safely in the formation. When Pd < Pm, an injection pressure in the interval (Pd, Pm) is admissible if the leakage rate is below acceptable limits. Leakage rate is directly related to the effective gas permeability, which varies from one caprock to another. Effective CO2 permeabilities in the range of 104–105 mD are observed in the caprock samples from the Weyburn EOR and storage site, which corresponds to significant CO2 leakage rates (Li et al., 2006); whereas values in the range of 107– 109 mD are reported in caprock samples of the Alberta Basin by (Bennion and Bachu, 2007), which corresponds to acceptable leakage rates. However, the stability over extended periods of time of the observed CO2 effective permeability needs to be assessed as well. Under various geochemical alteration processes, such as dissolution and (re)precipitation of mineral species, this permeability can either increase or decrease. This paper is concerned with the capillary breakthrough mechanism, which is controlled by the interfacial properties of the water/gas/caprock system and particularly by the water/gas interfacial tension (IFT). Capillary breakthrough occurs when the pressure Pd exerted by the gas phase exceeds that in the water (brine) that imbibes the caprock (Pw) by an amount equal to or larger than the so-called capillary entry pressure. (The overpressure Pd  Pw is due to the buoyancy force arising from the density difference between the water and gas phases.) This pressure, which characterizes the capillary-sealing efficiency of the caprock with respect to the gas, is given by the Laplace law: Pce ¼ Pd  Pw  2s wg cosðuÞ=R

(1)

where R is an effective caprock pore radius, swg the IFT between water and gas and u is the contact angle (measured in the water phase) of the caprock mineral/water/gas system. Throughout the paper, complete weting of the caprock by water, i.e., cos(u) = 1, is assumed. The breakthrough or displacement pressure Pd as given by (1) is the minimum pressure above which the non-wetting (gas) phase displaces water in the caprock. Water/CO2 IFT is of the order of 25–30 mN/m at typical storage conditions (P > 8 MPa, T > 310 K) (Chiquet et al., 2007a)

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international journal of greenhouse gas control 2 (2008) 594–604

which is about half the value of water/hydrocarbon (e.g., methane) IFT at similar conditions. This means that the capillary entry pressure for a given caprock is two times lower, and therefore the displacement (or breakthrough) pressure Pd is lower when a hydrocarbon gas is replaced by CO2 in a gas reservoir or in an oil reservoir with a gas cap (Li et al., 2005, 2006). This has been clearly demonstrated in recent laboratory experiments (Hildenbrand et al., 2004; Li et al., 2006), in which displacement pressures were measured on the same (clayey or evaporitic) caprock samples for various gases (N2, CH4, CO2). In these experiments, lower breakthrough pressures were observed in the case of CO2 due to a lower water/CO2 IFT and a possible wettability effect (Chiquet et al., 2007b). As pointed out by Li et al. (2006), depending on the initial reservoir pressure and the displacement pressure, it may therefore be wrong (and dangerous) to assume that a given caprock, because it has prevented the upward migration of hydrocarbons over long (geological) periods of time, will also be able to retain CO2 if maintained below discovery pressure. While there have been many efforts to evaluate water/CO2 IFTs (Chalbaud et al., 2006; Chiquet et al., 2007a; Massoudi and King, 1974) and CO2 capillary entry pressures in various caprock samples (Hildenbrand et al., 2004; Li et al., 2005, 2006), very little is known on the behaviour of the IFT between water and acid gases containing significant amounts of H2S at the conditions of geological storage. We are only aware of a few low-pressure (P < 3 MPa) water/H2S IFT data published in the early seventies (Herrick and Gaines, 1973; Strathdee and Given, 1976), as well as of two very recent water/H2S IFT measurement points at reservoir conditions (Bennion and Bachu, 2006). These data indicate that IFT values are significantly lower than water/CO2 IFT at similar conditions, but they are too scarce to be conclusive. We present in this paper a series of water/H2S-rich acid gas IFT measurements at typical reservoir temperature (up to 120 8C) and pressure conditions (up to 15 MPa) by using the pendant drop technique. The experimental setup, procedure and results are presented in next section. The implications of the observed IFT behaviour on the safety of acid gas geological storage are discussed in the last section.

2.

densities. The best fit identifies the correct capillary length; swg is then deduced from the capillary length (a) and from the densities of the equilibrated water and gas phases, for which an estimation methodology is presented in Appendix A. In the following we first describe the experimental setup and procedure and then the IFT results.

2.1.

Experimental setup

The experimental setup meets the necessary safety conditions to handle H2S, which is corrosive, extremely toxic and inflammable. We first describe the measurement cell and the opto-mechanical device used to form, digitize and process a drop of H2S in water, then we present the gas handling system and safety environment.

2.1.1.

Measurement cell and opto-mechanical device

The measurement cell (Fig. 1) was designed and built in collaboration with Ecole des Mines, Fontainebleau, France and Teclis-IT Concept, Longessaigne, France. It consists of a cylindrical vessel with two see-through sapphire windows. The inside volume of the cell is 400 cc. It is entirely made of titanium, chosen for its excellent corrosion-resistant properties towards water/H2S systems. The maximum allowable operating pressure and temperature are P = 19 MPa and T = 150 8C, respectively. The cell contains a glass syringe used to form a (rising) acid gas drop in water at the tip of the syringe needle (external diameter = 1.25 mm). The syringe piston, controlled from outside the cell by a computer-driven motor, can be withdrawn from the syringe body to allow refilling of the syringe with the overlying acid gas. Temperature regulation and measurement are ensured by two PT100 probes inserted in the cell. One is used for regulating (by means of a PID regulator) and measuring the temperature maintained by four cartridge heaters placed in the cell walls, and the other is used for safety purposes to ensure that temperature never exceeds a maximum operating temperature (150 8C).

Experimental

The pendant drop technique is one of the most convenient methods for IFT measurements at high-pressure conditions. In this technique, either a pendant drop of the denser phase (here, the water-rich phase) or a rising drop of the less dense phase (here, the acid gas-rich phase) is formed in the other phase and maintained in equilibrium at the tip of a needle. A drop image is recorded using a CCD camera, from which the drop contour is extracted and then processed by the so-called Axisymmetric Drop Shape Analysis (ADSA) method. In short (see Rio and Neumann, 1997; Sunsar et al., 1996, for more details), ADSA calculates the theoretical profile that best fits the drop profile extracted from the drop image. The theoretical profile is the solution of the Laplace equation of capillarity, and depends only on the capillary length a ¼ ð2s wg =gDrÞ½ , where g is the gravitational acceleration and Dr = rw  rg is the difference between the water and gas (or non-aqueous) phase

Fig. 1 – Measurement cell and opto-mechanical system: 1: motor; 2: computer; 3: digital camera; 4: acid gas bubble; 5: piston; 6: syringe; 7: sapphire window; 8: water phase; 9: acid gas; 10: temperature probes; TC: temperature controller.

international journal of greenhouse gas control 2 (2008) 594–604

The opto-mechanical device (TrackerTM, Teclis-ITConcept) is composed of a diffuse light source, a CCD camera positioned on the axis of the two sapphire windows and linked to a computer, and a motor that drives the syringe piston. The drop image is processed first by using a thresholding segmentation technique, in which a binary image composed of only black and white pixels is created using a threshold value from a greyscale image (for more details about this technique see Prokop et al., 1998). This binary image provides the drop profile, which is processed by the ADSA method using a software (WindropTM, Teclis-ITConcept) to determine various parameters from the drop contour, such as drop volume, diameter, capillary length and IFT (provided phase densities are given); the software also controls the position of the syringe piston and therefore the drop volume.

2.1.2.

Gas handling system and safety environment

Experiments are carried out in a highly secured laboratory equipped with several H2S detectors (Fig. 2). Detection limit is set at 5 ppm: once H2S concentration in the laboratory reaches this limit, it triggers an electronic alarm system, which automatically initiates several safety actions, consisting of turning on high speed exhaust fans, closing the electronic valve placed at the exit of H2S bottle, cutting off the electricity in the laboratory in order to avoid any sparks, etc. Hydrogen sulphide is injected in the cell by means of a compressor [B] (maximum injection pressure: 20 MPa). A rupture disk [D] and a safety cell [C] are installed to ensure that pressure never surpasses the maximum allowable operating pressure. The rupture disk is made of HASTELLOY1 C-276 [a nickel–molybdenum–chromium wrought alloy that is generally considered a versatile corrosion-resistant alloy (Haynes International Inc.)] and is calibrated at 19 MPa. In case pressure surpasses 19 MPa, this disk collapses and allows the gas to pass in the safety cell in order to release the

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pressure. The pressure transducer’s [E] membrane is made of HASTELLOY1 C-276. All tubing, valves, and connections are made of stainless steel (SS 316) except those in direct contact with the cell which are made of HASTELLOY1 C-276. All seals used are made of KALREZ1 (perfluoroelastomer) compound 6375 [DuPont Inc.]. This compound has outstanding chemical resistance in combination with high thermal stability; it withstands nearly all classes of chemicals including wet H2S.

2.2.

Experimental procedure

Water/acid gas IFTs along a given isotherm are measured as follows: the cell is initially partially filled with water and then mounted on the opto-mechanical device. The compressor is then used to charge acid gas at maximum pressure. After a few hours of phase equilibration (helped by magnetic agitation) at the desired temperature, a drop of the acid gas-rich phase is formed at the tip of the syringe needle. An image of this drop is recorded using the CCD camera and this image is processed using the ADSA software (WindropTM). Measurement is taken only when all measured parameters, e.g., capillary length, drop diameter, volume. . .etc, are stabilized and do not vary in time. Finally, the IFT at the given temperature and pressure is obtained by combining the measured capillary length with calculated phase densities (see Appendix A). The cell is then depressurized to a lower pressure, the system is allowed to equilibrate and the IFT is measured again. Pressure steps were in the range of 0.5–2 MPa, depending on whether IFT varied slightly (at high pressure) or considerably (at low pressure) with pressure. Each IFT value reported in this paper is the result of at least three measurements, each realized with a fresh drop. We observed that these measurements were reproducible and in most of the cases provided IFT values that agreed to within 0.5 mN/m.

Fig. 2 – Schematic representation of experimental set-up: [A] measurement cell; [B] compressor; [C] safety cell; [D] rupture disk; [E] pressure transducer; dotted line: Hastelloy C-276; solid line: SS 316.

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international journal of greenhouse gas control 2 (2008) 594–604

Fig. 3 – Image of liquid H2S drop (left) and vapour H2S drop (right) suspended in water.

The most considerable difficulty encountered during water/H2S IFT measurements was the lack of sufficient contrast between the water-rich and liquid H2S-rich phases: these phases have in fact very similar refractive indices. In some instances (see Fig. 3 (left)), the image processing software was unable to detect the drop contour and perform the necessary calculations to estimate IFT due to insufficient contrast. In most cases we were able resolve this problem by changing the threshold value (cf. 1.1) and by reducing the light source diffusion area. We also encountered blockage problems due to hydrate formation in tubes, valves and in the pressure transducer, as well as, occasionally, drop visualization problems due to adhesion of drops to the sapphire window during the degassing process. The former problems were overcome by heating the entire H2S flow path using a wraparound heating cord. The latter problems were alleviated by reducing the decompression rate.

2.3.

appears: this pressure is very close to the saturation pressure of pure H2S (Carroll and Mather, 1989). At Psat there is a downward leap, which is of the order of the surface tension of pure H2S at the same temperature. When P > Psat the water/liquid H2S IFT does not vary much with increase in pressure, as expected with two slightly compressible and slightly miscible liquids. The selected CO2 + H2S mixture is supercritical at T = 77 8C (Kellerman et al., 1995); its IFT with water has the same qualitative behaviour as that of water/H2S IFT at 120 8C (Fig. 4); the pseudo-plateau value of 25 mN/m is approximately equal to the molar average IFTs of the water/CO2 and water/H2S binary systems at similar T and P (where pure CO2 is supercritical and pure H2S liquid), i.e., s w;0:7CO2 þ0:3H2 S  0:7s w;CO2 þ 0:3s w;H2 S (Fig. 5).

3. Discussion and implications for H2S-rich acid gas geological storage

Experimental results

Water/H2S IFTs were measured at temperatures and pressures both below and above the critical temperature and pressure of H2S (respectively equal to Tc  100 8C and Pc  9 MPa: these conditions are only very slightly altered in the presence of a water phase, Carroll and Mather, 1989). Water/H2S IFTs were measured along two subcritical isotherms T = 40, 70 8C and one supercritical isotherm T = 120 8C and in a pressure range extending up to 15 MPa. The IFTs between water and a CO2 (70 mol%) + H2S (30 mol%) mixture were measured in the same pressure range at T = 77 8C, which is above the critical temperature of the mixture (this temperature was selected because of the availability of density data in this range of pressure for the selected acid gas composition; Kellerman et al., 1995). The measured values along with the phase densities are presented in Tables 1 and 2. As shown in Fig. 4, at low pressure the water/H2S IFT decreases linearly with pressure. At a temperature (T = 120 8C) above the critical temperature of H2S this decrease persists until high pressure (P  12 MPa), then IFT levels off and reaches a pseudo-plateau of 9–10 mN/m. At temperatures below the critical temperature of H2S (T = 40 and 70 8C), the water/H2S IFT decreases linearly with pressure up to Psat where a third, H2S-rich liquid phase

In this section, we first compare our water/H2S IFT results with the few existing data. We were unable to compare our water/ (CO2 + H2S) IFT measurements with the literature because of the unavailability of such data. Then, using our measurements

Fig. 4 – Experimental water/H2S IFTs along three isotherms T = 40 8C (*), 70 8C (4) and 120 8C (&). Dashed lines correspond to extrapolations of the measured IFT curves up to the saturation pressure of H2S (Psat, shown as a vertical dotted line).

international journal of greenhouse gas control 2 (2008) 594–604

599

Table 1 – Water/H2S IFT experimental results T (8C)

IFT (mN/m)

P (MPa)

Bulk (water-rich) phase density, rw (kg/m3)

Drop (H2S-rich) phase density, rH2 S (kg/m3)

Dr = rw  rH2 S equilibrium (kg/m3)

40

0.45 0.9 1.5 2.0 2.5 4.3 6.2 8.4 10.4 12.6

992.2 992.2 992.3 992.3 992.3 992.9 993.4 993.6 994.2 995.1

6.1 12.6 22 30.9 40.9 744.2 749.2 754.7 759.3 764

986.1 979.6 970.3 961.4 951.4 248.7 244.2 238.9 234.9 231.1

60.3  0.7 55  0.6 47.3  0.3 41.7  0.3 34.5  0.4 16.9  0.1 16,7  0.2 16.5  0.4 16.3  0.2 15.9  0.3

70

0.55 1.15 2.0 3.0 3.9 4.9 7.3 9.0 11.5 13.8 14.5

977.8 977.9 977.9 978 978.1 978.2 978.2 976.5 976.2 976.1 976.1

6.6 13.8 26.6 43.2 61.4 89.8 677.8 683.2 695.6 705.2 708.4

971.2 964.1 951.3 934.8 916.7 888.4 300.4 293.3 280.6 270.9 267.7

56.6  0.4 52.6  0.4 45.9  0.2 37.8  0.2 32.2  0.2 23.8  0.8 8.3  0.1 9.4  0.2 8.8  0.2 8.3  0.1 7.4  0.4

120

0.5 0.95 2.0 3.0 4.0 5.0 7.0 8.5 10.1 12.0 13.0 14.6

943.1 943.2 943.2 943.3 943.4 943.4 942.9 941.9 941.3 941.5 941.8 942.3

4.3 9.3 21.4 33.9 47.8 63.2 101.5 142.9 232.4 482.1 522.9 555.4

938.8 933.9 921.8 909.4 895.6 880.2 841.4 799 708.9 459.4 418.9 386.9

52.2  1 48.5  0.5 44.5  1 40.8  0.8 37.0  0.5 34.0  0.3 26.7  0.7 21.6  0.2 15.3  0.6 10.6  0.3 10.3  0.6 10.5  0.8

and the available water/CO2 IFT data, we discuss the implications of our results for acid gas geological storage. We are aware of only three sets of experimental water/H2S IFT measurements. Two of these data sets (Herrick and

Gaines, 1973; Strathdee and Given, 1976), obtained at low pressure (P < 3 MPa), are in excellent agreement with each other. Herrick and Gaines (1973) performed measurements between 25 and 40 8C and up to 2 MPa. Strathdee and Given

Table 2 – Water/(70 mol%CO2 + 30 mol%H2S) mixture IFT experimental results T (8C)

77

P (MPa)

Bulk (water-rich) phase density, rw (kg/m3)

Drop (acid gas-rich) phase density, rg (kg/m3)

Dr = rw  rg equilibrium (kg/m3)

0.5 1.0 1.5 2.0 2.4 3.0 3.9 4.8 6.2 7.5 10.0 12.0 14.0 15.6

973.8 974.0 974.3 974.5 974.7 974.9 975.3 975.7 976.3 976.9 978.0 978.9 979.7 980.4

7.2 14.6 22.4 30.2 36.8 47.1 63.5 81.3 112.4 145.9 229.6 315.9 399.7 454.0

966.6 959.5 951.9 944.3 937.9 927.9 911.9 894.4 864.0 831.0 748.4 663.0 580.0 526.4

IFT (mN/m)

55.7  0.4 53.6  0.9 51.1  0.3 50.5  0.3 48.1  0.3 46.6  0.3 43.7  0.6 40.4  0.4 36.8  0.1 33.7  0.3 29.2  0.3 26.5  0.3 26.0  0.4 25.3  0.5

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Fig. 5 – Measured IFTs between water and a 70 mol%CO2 + 30 mol%H2S mixture at 77 8C (&), water/H2S IFT at 70 8C from our work (*), water/CO2 IFT at T = 70 8C (4) taken from Chiquet et al. (2007a), molar average IFT (—) (i.e., 0:7s w;CO2 þ 0:3s w;H2 S ).

water (brine) rather than pure water (see caption of Fig. 6): the measured IFTs are 12.2 and 12.3 mN/m, respectively. Here, we remind that the presence of salt in water has the effect of slightly raising the IFT (the increase is in the range of 1–2 mN/ m per mole of added salt, depending on temperature, mineral salt and non-aqueous phase (Chalbaud et al., 2006; Massoudi and King, 1974). In fact these brine/H2S IFT measurements, particularly at 35 8C and 8.6 MPa, are not consistent with our water/liquid H2S IFT values at 40 8C (16 mN/m, see previous section) and with that measured by Strathdee and Given (1976) at Psat, 35 8C (17.9 mN/m) and 40 8C (16.5 mN/m). However, the IFT values of interest for geological storage are generally those obtained at high temperature (>40 8C, typically) and high pressure (>10 MPa), corresponding to storage depths larger than 1000 m. In the following section, we take a water/H2S IFT value of 9 mN/m for all conditions of T  70 8C and P > 12 MPa, which represents the lower limit of ‘real’ IFTs (i.e., brine/H2S IFTs) at these conditions.

3.1. (1976) measured IFTs in the two-phase region (water/H2S in vapour phase) between 25 and 130 8C and at three-phase coexistence (i.e., at P = Psat) between 30 and 40 8C. A comparison between our measurements and these literature data at 40 8C is presented in Fig. 6, where the two points on the vertical dotted line (Psat at 40 8C) correspond to the IFTs at three-phase coexistence (T = 40 8C, P = Psat) between the aqueous phase and the other (i.e., H2S-rich) phase in vapour and liquid state, respectively equal to 28.5 and 16.5 mN/m. All our measurements, including the water/liquid H2S IFTs on the isotherm T = 40 8C, are in excellent agreement with both of these data sets (comparisons at 70 and 120 8C are not shown here). The third data set (Bennion and Bachu, 2006) consists of two measurement points, one at 35 8C and 8.6 MPa and another at 56 8C and 17.4 MPa, both carried out with salted

Implications for acid gas geological storage

The above results show that, at high pressure and temperature, water/H2S IFT values are around 30–40% of water/CO2 IFTs and around 20% of water/CH4 IFTs (see Table 3). When the original gas (CH4) in the reservoir is replaced with an H2S-rich acid gas, the capillary entry pressure is reduced by a factor equal to s w;CH4 =s w;H2 S  5, which is much larger than in the case of CO2 (i.e., s w;CH4 =s w;CO2  2). Thus, the risk of capillary failure, pointed out by Li et al. (2005) in the context of CO2 geological storage (cf. Section 1), is even more serious when the injected acid gas is rich in H2S. Therefore, the capillary properties of the water/gas/caprock system should be examined with utmost attention when envisaging a H2Srich acid gas geological storage project. In the following, we present an illustrative calculation, in order to compare the safe (i.e., leakproof) storage conditions for various injected gases: CH4, CO2, H2S and the CO2 + H2S mixture considered above. Here, safe storage condition corresponds to pressures that do not exceed the displacement (or breakthrough) pressure Pd: the possibility of capillary leakage through the caprock is only taken into account (the pressure Pm of caprock mechanical failure is supposed to be

Table 3 – Comparison between water/CH4, water/CO2 and water/H2S IFTs at high P, T conditions

Fig. 6 – Comparison between measured water-H2S IFTs and literature data. (—) this work at 40 8C; literature water/H2S IFT data at 40 8C: (^) Strathdee and Given (1976) and (+) Herrick and Gaines (1973); literature brine/H2S IFT data at 8.6 MPa, 35 8C, 28,286 ppm brine salinity and 17.4 MPa, 56 8C, 136,817 ppm brine salinity: (*) Bennion and Bachu (2006).

Gas

T (8C)

P (MPa)

IFT (mN/m)

CH4 CO2 H 2S

40

12.5

59.8 31.5 15.9

CH4 CO2 H 2S

70

15.0

54.8 32.5 7.4

CH4 CO2 H 2S

120

15.0

50.5 30.5 10.5

Water/CH4, water/CO2 and water/H2S IFT values are interpolated or extrapolated using the data of Ren et al. (2000), Chiquet et al. (2007a) and this work, respectively.

international journal of greenhouse gas control 2 (2008) 594–604

higher than Pd). This pressure is equal to the pressure in the brine phase Pw plus the capillary entry pressure Pce (see Section 1). The maximum column height of gas that can be trapped beneath the caprock is then obtained by equating Pce to the gas buoyancy pressure. Finally, storage capacity is straightforwardly calculated as the quantity of gas over this maximum height per unit area (km2) of the formation. This quantity is a lower bound of true storage capacity, as we only consider ‘hydrodynamic trapping’ and neglect the other modes of storage explained in Section 1. Our calculations apply regardless of the storage medium: (i) in an aquifer and (ii) in a depleted gas (CH4) reservoir or in the gas (CH4) cap of an oil reservoir. In both situations, we assume that the caprock has the same characteristics, and the formation is filled with acid gas up to capillary failure of the caprock, which occurs when capillary pressure reaches the capillary entry pressure: this pressure is proportional to the water/acid gas IFT and to the inverse of a typical pore radius. The maximum allowable pressure (i.e., the displacement pressure Pd), the maximum gas column height and the storage capacity are compared for three typical caprock depths: 1000, 2000 and 3700 m. The displacement pressure is also compared with that of CH4, which, in situation (ii) is the reservoir discovery pressure if the reservoir is assumed to be at the limit of capillary failure at the time of discovery. The principles of the calculation, illustrated graphically in Fig. 7, are as follows:  For each caprock depth (1000, 2000 and 3700 m), temperature is deduced by considering a surface temperature T = 10 8C and a geothermal gradient = 3 8C/100 m.  The acid gas is stored in the formation as a pure phase.  The maximum pressure Pd for a given gas (CH4 or acid gas) is the sum of brine pressure Pw (assumed to be equal to the hydrostatic pressure) and capillary entry pressure Pceg; the latter is derived from Eq. (1) using a caprock pore radius R = 50 nm and the available water/gas IFT data. The values of s w;CO2 and s w;CH4 are taken from the literature (Chiquet et al., 2007a; Ren et al., 2000), while s w;H2 S and s w;0:7CO2 þ0:3H2 S values are taken from this work: at high temperature (70 8C) and high pressure (>12 MPa) s w;H2 S is considered constant (9 mN/m), and s w;0:7CO2 þ0:3H2 S at 70 8C and 20 MPa is taken equal to 25 mN/m. Due to the lack of caprock wettability data in the presence of H2S-rich acid gases, we consider that

601

the caprock is completely water-wet (contact angle u = 0, hence cos u = 1 in Eq. (1)).  The maximum height H of gas column beneath the caprock seal is obtained by equating the buoyancy pressure (rw  rg)gH with the capillary entry pressure Pceg, hence: H¼

Pceg ðrw  rg Þg

(2)

where rw and rg are the brine and gas densities at the pressure and temperature of interest (the properties of pure water are taken instead of those of brine) taken from NIST (2007).  This height H is then converted into mass of gas stored per unit surface of the formation M ¼ rg Hfð1  Sw Þ

(3)

where f is the porosity and Sw is the irreducible (or residual) water saturation in the reservoir. We used reasonable porosity and residual water saturation values: f = 0.3 and Sw = 0.1. We considered that rg is constant throughout the column height, which is a reasonable approximation as CO2 and H2S are only slightly compressible at the temperature and pressure conditions considered. The results of this calculation are presented in Table 4, where the acid gas storage capacity is expressed both in terms of mass per unit area (km2) and in terms of volume at standard conditions. The maximum pressure to which a formation can be safely refilled with CO2 is smaller than the initial gas (CH4) reservoir pressure (we assume that the reservoir is at the limit of capillary leakage at the time of discovery) and it is even smaller if the injected gas is H2S-rich (i.e., Pd;CH4 > Pd;CO2 > Pd;0:7CO2 þ0:3H2 S > Pd;H2 S ). These differences in maximum pressures for different gases increase for lower pore radii. The maximum storage capacity depends not only on Pceg but also on rg. At low storage depth (1000 m, corresponding to moderate temperatures and pressures, e.g., T = 40 8C and P = 10 MPa), the difference between the CO2 and H2S storage capacities is small, owing to the relatively small difference between water/CO2 IFT (32 mN/m) and water/H2S IFT (16 mN/ m) and lower density of pure CO2 compared to the density of pure H2S; whereas at high storage depths (2000 and 3700 m) H2S storage capacity is 2–3 times lower than that of pure CO2

Fig. 7 – Schematic representation of the water and gas pressure profiles used to calculate the maximum column height of stored acid gas.

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Table 4 – Summary of calculations of acid gas capillary retention by a water-wet caprock with pore radius R = 50 nm Acid gas

Caprock depth (m)

T, Pw

Maximum pressure for CH4a (MPa)

Maximum pressure (MPa)

Maximum height of acid gas (m)

Storage capacity (Mt/km2)

CO2 H2S

1000

40 8C, 10 MPa

12.5

11.3 10.7

355 285

60 58

33 41

CO2 CO2 (70 mol%) + H2S (30 mol%) H2S

2000

70 8C, 20 MPa

22.1

21.1 21.0

343 237

61 36

33 21

20.4

137

26

18

CO2 H2S

3700

38.0 37.4

332 124

60 22

32 15

a

120 8C, 37 MPa

38.8

This pressure is the discovery pressure in situation (ii) if the reservoir’s caprock is at the limit of capillary leakage at the time of discovery.

due to much lower water/H2S IFTs (8–9 mN/m) compared to water/CO2 IFTs (24–25 mN/m) and almost similar density values of pure CO2 and H2S. The storage capacity of the 70 mol%CO2 + 30 mol%H2S acid gas mixture is intermediate between that of pure CO2 and pure H2S but closer to that of pure H2S although containing a smaller fraction of H2S than CO2. In practice, H2S is always co-injected with CO2 and the composition of the injected acid gas varies from one project to another. An evaluation of the maximum injection pressure and of storage capacity requires the knowledge of IFT between water and the H2S/CO2 mixture, which can be approximated as the molar average of water/CO2 and water/H2S IFTs, if the acid gas is at supercritical conditions.

4.

Storage capacity (std. billion m3/km2)

Summary and conclusions

In this paper we presented a set of water/acid gas IFT measurements at geological storage conditions, i.e., at high temperature (up to 120 8C) and high pressure (up to 15 MPa). An important conclusion that can be drawn from these measurements and from the available water/CO2 IFT data is that water/acid gas IFT at geological storage conditions strongly varies with acid gas composition. Based on water/ acid gas mixture IFT measurements along an isotherm and for a particular gas composition, it appears that IFT is proportional to the CO2 (or H2S) mole fraction in the acid gas, if the acid gas is at supercritical conditions, and it varies from around 30 mN/m for pure CO2 to the values reported in this paper for pure H2S, i.e., 9–10 mN/m for T  70 8C (P  12 MPa). Actual brine/acid gas IFT values are slightly above these values, as the presence of salt in the water phase has for effect to slightly raise IFT (by an amount of the order of 1–2 mN/m per mole of added salt). The strong decrease in water/acid gas IFT with increase in H2S content has important implications for acid gas geological storage. A given caprock will sustain lower gas pressure, or smaller gas column height, if the acid gas contains more H2S: this is especially true at large depths (say, greater than 2000 m). In the case of a depleted gas reservoir, or of an oil reservoir with a gas cap refilled with acid gas, capillary failure will occur when approaching the initial (i.e., discovery) pressure of the reservoir if the initial hydrocarbon reservoir

was at the limit of capillary leakage. Clearly, when planning a H2S-rich gas storage project in a geological formation, a proper assessment of the displacement pressure in the formation’s caprock by appropriate laboratory methods (Thomas et al., 1968) is more stringently needed than in the case of CO2 storage (Li et al., 2005). The other causes of acid gas leakage from the formation should be examined as well. These include mechanical failure or thermal fracturing of the caprock, as well as alteration of abandoned cemented wells.

Acknowledgements We are thankful to B. Gilet-Garas, J.-M. Dufau, G. Moulie and P. Roux for their help in experimentation. We are thankful to Ecole des Mines de Paris (P. The´veneau and D. Richon) and Teclis-IT concept for their constant help in designing and building the measurement cell. We are grateful to TOTAL SA for supporting the study and authorizing the publication.

Appendix A. Evaluation of densities of the coexisting water-rich and acid gas-rich phases We estimated the density of two coexisting phases of water/acid gas mixtures by taking into account their mutual solubility. We observed that the effect of mutual solubility on these phase densities is very small (of the order of 1–2%) for the water/H2S binary system at T = 40 8C and water/ (30% mol H2S + 70% mol CO2) ternary system at T = 77 8C. Therefore, we present here only the calculation for the water/H2S systems at T = 70 and 120 8C. First of all, the composition of the water-rich and H2S-rich phases is calculated at the specified temperature and pressure using the Peng–Robinson equation of state (EoS) (Peng and Robinson, 1976) as modified by Soreide and Whitson (1992). The modifications consists in (i) an energy term in the EoS (usually noted a) developed specifically for the water (or brine) component and (ii) two different binary (water/H2S) interaction parameters (one for the aqueous phase and the other for the non-aqueous phase) that depend on the acentric factor, temperature and salinity. The modified EoS (PRSW EoS) provides phase compositions as a function of temperature

international journal of greenhouse gas control 2 (2008) 594–604

603

and pressure in excellent agreement with experimental data reported by Burgess and Germann (1969), Kuranov et al. (1996), Lee and Mather (1977) and Selleck et al. (1952). However, densities or molar volumes are poorly predicted by this EoS. The molar volume V and density rw of the H2S-saturated water phase are calculated as follows: f þ ð1  xH2 S ÞVH2 O V ¼ xH2 S VH 2S

rw ¼

xH2 S MH2 S þ ð1  xH2 S ÞMH2 O V

(4)

(5)

where MH2 S ; MH2 0 are the molecular weight of H2S and water, respectively, VH2 0 the molar volume of pure water at the same F the apparent molar volume of H2S dissolved in T and P, VH 2S water at infinite dilution at T and P and xH2 S is the mole fraction of H2S dissolved in water (as calculated by the PRSW EoS). The F in the T and P ranges of interest here (from 40 to values of VH 2S 120 8C and P up to 15 MPa) are taken from Hnedkovsky et al. (1996) after an appropriate fitting as a function of T and P. Calculated H2S-saturated water phase densities rw differ from pure water densities by less than 0.5% in this T and P range. This calculation is expected to be accurate because all quantities used (H2S solubility in water, molar volume of pure water and apparent molar volume of dissolved H2S in water) are checked with or taken directly from literature experimental data. While the above density evaluation relies on existing measurements of apparent molar volume of H2S dissolved in water at infinite dilution (Hnedkovsky et al., 1996), no similar data exists for H2S-rich phases with dissolved water. The PRSW EoS, like most cubic EoS, predicts vapour phase density satisfactorily but does not provide accurate liquid phase densities. In order to predict the molar volume and density of the water-saturated H2S phase, we used the corresponding-states model of Lee and Kesler (1975), which is a modified Benedict– Webb–Rubin equation (Benedict et al., 1940, 1942, 1951). In this approach, the compressibility factor (Z = PV/RT) of the mixture is calculated using its acentric factor (v) by interpolating between the compressibility factor Z0 of rare gases (v0 = 0) and that ZR of a reference fluid (vR = 0.3978) Z ¼ Z0 þ v=vR ðZR  Z0 Þ:

(6)

Z0 and ZR are calculated at the same reduced temperature Tr = T/Tc, pressure Pr = P/Pc using correlations given in Lee and Kesler (1975). This model accurately predicts pure H2S densities in the subcritical and supercritical regions. The pseudo-critical properties of H2S-rich phase v, Tc, Pc and Vc necessary to apply this model are evaluated from the critical properties of H2S and water using the mixing rules of Lee and Kesler (1975) as modified by Plocker et al. (1978). While the difference between the calculated densities of pure H2S and water-saturated H2S is negligible at low temperature (e.g., at T = 40 8C), the density of the latter is much higher than that of pure H2S at high temperature (T = 70 and 120 8C) and pressure (P > 10 MPa). A comparison between the density difference between pure water and pure H2S (Dr0),

Fig. A.1 – Density difference between pure water and H2S (Dr0) and calculated density difference between two equilibrated phases (Dr) at T = 70, and 120 8C. Dr0 at 70 8C (– – –), Dr at 70 8C (D), Dr0 at 120 8C (—) and Dr at 70 8C (*).

and two equilibrated phases (Dr) for the 70 and 120 8C isotherms is shown in Fig. A.1. As shown in Fig. A.1 the difference between Dr0 and Dr is significant (i.e., up to 34%) at high P and T (i.e., T = 120 8C and P > 10 MPa) and non-negligible (i.e., up to 10%) at moderate T and P (i.e., T = 70 8C and P > 5 MPa). Use of the density difference between pure components (Dr0) instead of the density difference of two equilibrated phases (Dr) to evaluate the IFT experimentally can cause an error (overestimation) in IFT up to 34% (at T = 120 8C and P = 12–15 MPa). Clearly, there is a need for density measurements on water-saturated H2S at high temperature and pressure.

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