Gas breakthrough pressure for hydrocarbon reservoir seal rocks: implications for the security of long-term CO 2 storage in the Weyburn field

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1 Geofluids (2005) 5, Gas breakthrough pressure for hydrocarbon reservoir seal rocks: implications for the security of long-term CO 2 storage in the Weyburn field S. LI 1,M.DONG 1,Z.LI 1,S.HUANG 2,H.QING 1 AND E. NICKEL 3 1 University of Regina, Regina, Saskatchewan, Canada; 2 Saskatchewan Research Council, Regina, Saskatchewan, Canada; 3 Saskatchewan Industry & Resources, Regina, Saskatchewan, Canada ABSTRACT This paper reports a laboratory study of the gas breakthrough pressure for different gas/liquid systems in the Mississippian-age Midale Evaporite. This low-permeability rock formation is the seal rock for the Weyburn Field in southeastern Saskatchewan, Canada, where CO 2 is being injected into an oil reservoir for enhanced recovery and CO 2 storage. A technique for experimentally determining CO 2 breakthrough pressure at reservoir conditions is presented. pressures for N 2,CO 2 and CH 4 were measured with the selected seal-rock samples. The maximum breakthrough pressure is over 30 MPa for N 2 and approximately 21 MPa for CO 2. The experimental results demonstrate that the Weyburn Midale Evaporite seal rock is of high sealing quality. Therefore, the Weyburn reservoir and Midale Beds can be used as a CO 2 storage site after abandonment. The measured results also show that the breakthrough pressure of a seal rock for a gas is nearly proportional to the interfacial tension of the gas/brine system. The breakthrough pressure of a CO 2 /brine system is significantly reduced compared with that of a CH 4 /brine system because of the much lower interfacial tension of the former. This implies that a seal rock that seals the original gas in a gas reservoir or an oil reservoir with a gas cap may not be tight enough to seal the injected CO 2 if the pressure during or after CO 2 injection is the same or higher than the original reservoir pressure. Therefore, reevaluation of the breakthrough pressure of seal rocks for a given reservoir is necessary and of highest priority once it is chosen as a CO 2 storage site. Key words: breakthrough pressure, CO 2 storage, seal rock, sealing capacity Received 28 January 2005; accepted 13 July 2005 Corresponding author: M. Dong, Faculty of Engineering, University of Regina, 3737 Wascana Parkway, Regina, Saskatchewan, S4S 0A2, Canada. mingzhe.dong@uregina.ca. Tel: Fax: Geofluids (2005) 5, INTRODUCTION Seal rock is a formation with extremely low porosity and permeability overlying an oil or gas reservoir, and it constitutes the barrier against the volume flow of hydrocarbons into the upper layers. Although a seal rock can be considered as a seal to hydrocarbons, it is erroneous to regard it as a completely impermeable layer. Two main mechanisms have been well recognized to be responsible for migration of hydrocarbon gases through seal rocks into adjacent upper layers (Krooss et al. 1992). One is molecular diffusion through the water-saturated pore space of the seal rock. The other is the compressible slow Darcy flow of a free gas phase. Molecular diffusion is a ubiquitous but slow process that is only considered significant in geological timescales. The second one, the slow Darcy flow, depends strongly on the geologic and hydrodynamic conditions of the system, including the reservoir, the seal rock, and the overburden formations, as well as the properties of the fluids in both the reservoir and the seal rock. Slow Darcy flow occurs when the pressure difference across the seal rock is sufficiently high to overcome the sealing capacity of the seal rock. In essence, the sealing capacity of a seal rock is provided by the capillary forces across the interface of the wetting phase (usually brine), which saturates the seal rock, and the nonwetting phase (oil or gas), which accumulates in the reservoir. The capillary sealing mechanism is illustrated schematically in Fig. 1. Ó 2005 Blackwell Publishing Ltd

2 Gas breakthrough pressure for different gas/liquid systems 327 the nonwetting phase. The capillary pressure P c in a pore throat is expressed as Seal rock Pc Figure 1 shows a pore throat and a curved interface between the wetting and nonwetting phases in a seal rock, where P n is the pressure in the nonwetting phase, P w is the pressure in the wetting phase, and P c is the capillary pressure across the nonwetting/wetting meniscus in a pore throat. It is the capillary pressure that prevents the penetration of the nonwetting fluid into the seal rock through slow Darcy flow. When the pressure difference between the nonwetting and the wetting phase exceeds the capillary pressure at a pore throat, i.e. P n )P w > P c, the nonwetting phase will advance along the channel until it reaches the next smaller pore throat. When the differential pressure across the seal rock overcomes the capillary pressures of a series of interconnected pore throats of arbitrarily large sizes, a continuous filament of nonwetting phase will be formed and, consequently, a slow Darcy flow will occur. This differential pressure is regarded as the breakthrough pressure of the seal rock (Berg 1975; Schowalter 1979; Dullien 1992; Hildenbrand et al. 2002). The breakthrough pressure is an important parameter for assessing the sealing capacity of a seal rock of a hydrocarbon trap. It is also referred to as the bubbling pressure or sealing pressure, but is different from threshold pressure, displacement pressure, or minimum capillary entry pressure (Dullien 1992). The latter three have the same essential meaning in that they are a measure of the diameter of the largest pore on the exterior of a rock sample for given rock wettability and wetting/nonwetting interfacial properties. However, the breakthrough pressure has applications in different areas, such as oil and gas reservoir evaluation prior to exploitation, basin analysis, hydrocarbon secondary migration assessment, as well as the selection of geological sites to store natural gas or industrial waste gases. The magnitude of the breakthrough pressure is determined by the highest capillary pressure of an interconnected network of pore throats that are first invaded by Pw P n Water Oil or gas Fig. 1. Schematic of capillary sealing mechanism in a pore throat of seal rock. P c ¼ 2 r cos ð1þ where r is the interfacial tension (IFT) between the nonwetting phase (hydrocarbon) and wetting phase (brine), r is the equivalent radius of the pore throat, and h is the contact angle of the pore surface. Equation 1 shows that the breakthrough pressure is proportional to the IFT between the two phases and inversely proportional to the radius of the pore throat. Contact angle, a measure of the wettability of the solid surface, is also an important factor that determines the magnitude of the capillary pressure. Although Eqn 1 suggests a simple relationship between the capillary pressure and the above three parameters (r, r, and h), it is rarely used to predict the breakthrough pressure because the determination of r and h is usually difficult. Measurement of seal-rock breakthrough pressure has been conducted by many researchers (Thomas et al. 1968; Schowalter 1979; Schlo}mer & Krooss 1997; Hildenbrand et al. 2002). Usually, the conventional mercury injection method is used to estimate the magnitude of breakthrough pressure. The measured displacement capillary curve of mercury/air systems is converted to the gas breakthrough pressure of a gas/water system (Berg 1975; Schowalter 1979; Watts 1987; Schlo}mer & Krooss 1997). However, the displacement pressure obtained from the conventional mercury injection method is similar to the capillary entry pressure or threshold pressure which is, in general, much lower than the breakthrough pressure (Dullien 1992; Schlo}mer & Krooss 1997). The direct measurement of the breakthrough pressure of a seal rock involves a displacement of a wetting phase (brine) by a nonwetting phase (such as a gas). The displacing pressure is increased in small steps. The breakthrough pressure is obtained when a slow continuous water flow, eventually followed by a breakthrough of the nonwetting phase, is observed at the outlet of the rock sample (Thomas et al. 1968). The direct measurement of the breakthrough pressure for tight-seal rocks is time consuming and seldom used by researchers; however, it is the most reliable approach. More recently, CO 2 geological storage in depleted oil and gas reservoirs has become an appealing option to mitigate CO 2 emission into the atmosphere. To prevent the injected CO 2 from leaking into the adjacent layers above the storage formation, the sealing pressure of a seal rock has to be determined in order to choose an injection pressure that ensures the differential pressure across the seal rock is smaller than the breakthrough pressure. Otherwise, the injected CO 2 will penetrate into the seal rock, form a continuous gas phase in the interconnected channels, and

3 328 S. LI et al. migrate into the upper layers by Darcy flow. Most of the available results of the breakthrough pressures reported by researchers are primarily for hydrocarbon/water systems (Thomas et al. 1968; Hildenbrand et al. 2002). These results cannot be used directly to represent the CO 2 breakthrough pressure in CO 2 geological storage because the CO 2 breakthrough pressure is expected to be lower because of the lower IFT of CO 2 /water systems. Moreover, the contact angle of a CO 2 /water/rock system can be different from that of an oil/water/rock system. Therefore, the direct measurement of breakthrough pressure for CO 2 is at present indispensable in providing a basic parameter for determining the upper limit of injection pressure for CO 2 storage in a depleted hydrocarbon reservoir. This paper reports the experimental results of CO 2 breakthrough pressures for Midale Evaporite seal-rock samples of the Weyburn reservoir, where the International Energy Agency Greenhouse Gas R & D Programme Weyburn CO 2 Monitoring and Storage Project (IEA GHG Weyburn) is in progress (Wilson & Monea 2004). The results provide a pressure constraint for the design and implementation of CO 2 injection in hydrocarbon reservoirs for both the CO 2 enhanced oil recovery (EOR) process and CO 2 storage. In this paper, the impact of the fluid/fluid IFT on the breakthrough pressure is also examined by measuring the breakthrough pressures of different gases (nitrogen, methane, and carbon dioxide) in the same seal-rock samples. EXPERIMENTAL DESIGN Apparatus The schematic of the experimental apparatus is shown in Fig. 2. It mainly consists of an air bath, a Hassler-type high-pressure core holder with a thick lead sleeve to contain the core sample, a high-pressure gas sample cylinder, Flowmeter BPR P P Computer Air bath Gas samples Core holder Gas samples P Vacuum pump Brine Pump 2 Pump 1 Fig. 2. Schematic of apparatus for breakthrough pressure measurement. two high-pressure pumps, a backpressure regulator (BPR), and a 0.5 ml metering capillary tube (with fine scales) as the gas flowmeter. The coreholder is specialized for high-pressure CO 2 displacement tests with the use of thick lead sleeves instead of the commonly used rubber sleeves to ensure a leak- tight seal around the rock samples. This avoids sealing failure caused by the effects of CO 2 absorption in rubber sleeves in a long-duration experimental run. The air bath was used to keep the temperature constant during the measurement. One high-pressure pump (pump 1) was used to control the net confining pressure (the difference between the confining pressure and the injection pressure), and the other one (pump 2) was used to inject brine to saturate the core samples and to pressurize the gas sample to provide the inlet pressure. A net confining pressure of about 10 MPa was applied for all the measurements to ensure a seal around the core sample and prevent bypassing of the test gas. The BPR was used to control the outlet pressure. Both the inlet and the outlet pressures were recorded by a computer acquisition system. Procedure Prior to the breakthrough pressure measurements with the seal-rock samples, an equal-size metal plug (to simulate a zero-porosity core sample) was used to test whether the net confining pressure of 10 MPa is sufficient to prevent any leakage through possible channels between the sleeve and the core sample. With a 10 MPa net confining pressure, no gas (nitrogen) leak was detected at the downstream when the inlet pressure was maintained as high as 30 MPa for more than 10 h. In addition, the net confining pressure of 10 MPa is close to the in situ net stress in the Weyburn reservoir, which ranges from 7 to 15 MPa (Wilson & Monea 2004). To measure the breakthrough pressure, a core sample was first installed in the core holder and saturated with Weyburn formation brine collected from well W2M. To saturate the extremely tight rock sample with the brine, CO 2 was first injected at the inlet (at the bottom) to displace the air in the core, and then the sample was evacuated to a pressure of <0.025 lmhg. Evacuation at this level was continued for >2 h. Following this, CO 2 was introduced to purge the core sample and then the evacuation was repeated once. De-aerated formation brine was injected from the bottom of the sample (inlet) and, simultaneously, the core was evacuated from the outlet (at the top) until the brine reached the outlet. The system was then pressurized to a net pore pressure of 7 MPa for at least 12 h. Following this, a steady-state brine injection was performed to displace the brine in the core sample and to measure the water permeability. For the tests with N 2 and CH 4, the outlet of the core was at atmospheric pres-

4 Gas breakthrough pressure for different gas/liquid systems 329 sure; for the CO 2 and oil-enriched CO 2 breakthrough pressure test, a constant backpressure of approximately 7.3 MPa was set to ensure that the CO 2 was in supercritical state during the tests. All the breakthrough tests were performed at Weyburn reservoir temperature of 59 C. Before the breakthrough pressure measurement, the brine trapped in the tube leading to the inlet end of the core sample was removed to ensure that the displacing gas contacted the inlet end face of the core sample. To start the breakthrough pressure measurement, the displacing gas was introduced into the inlet end at a desired lower pressure level. The movement of liquid meniscus in the metering capillary tube connected to the outlet of the core was monitored, and from this, the flow rate was calculated. When the movement of liquid meniscus in the capillary tube ceased (no movement for at least 4 h), the injection pressure was increased to the next higher level (approximately MPa increments for each step). Meanwhile, the net confining pressure was kept constant. After each inlet pressure increment, a very small movement of the water meniscus in the capillary tube was observed. This is because a small volume of water was displaced by the injected gas before a new capillary pressure was reached to balance the new displacing pressure (the difference between the injection pressure and the backpressure). The above procedure was repeated until a continuous slow liquid flow took place followed, after certain time, by a mixed flow with gas bubbles indicating the gas breakthrough. The displacing pressure of this last step was regarded as the breakthrough pressure in this experiment. WEYBURN SEAL ROCK MIDALE EVAPORITE The Midale Evaporite is an important seal rock for the Midale-hosted oil fields throughout south-east Saskatchewan. The Midale Evaporite consists of anhydrite and anhydritic dolomite, 2 11 m thick, tens of kilometers wide and hundreds of kilometers long stretching across southeast Saskatchewan. Stratigraphically, it is the lowermost unit of the Mississippian Ratcliffe beds, and it sits conformably on the uppermost Marly unit of the Midale Beds, which is one of the main reservoir rock in the Weyburn Field. A schematic north south cross-section across the study area of the IEA GHG Weyburn Project is given in Fig. 3. The Weyburn oil reservoir includes an upper Midale Marly dolostone (0 10 m thick) and a lower Midale Vuggy limestone (0 20 m thick). The Marly is a fine-grained microsucrosic dolostone with relatively high intercrystalline porosity (16 38%) and low permeability (1 50 md). The Vuggy unit consists of primarily ollitic/pelloidal wackestone to packstone with relatively low porosity (8 20%) and relatively high permeability ( md). Both of these units were deposited in a shallow flat carbonate shelf setting, upon which minor relative sea level changes would Fig. 3. A schematic north south cross-section of the study area of the IEA GHG Weyburn Project. abruptly change facies deposition from outer bank (lower Midale Vuggy ) to inner lagoonal (upper Midale Marly ) environments. Continued shallowing to a salina lake environment led to the deposition of the Midale Evaporite. The total oil reserve of the Weyburn field is about 221 million m 3. Oil density ranges from 858 to 921 kg m )3. The total oil production by 2000 is about 24% of the original oil in place (OOIP). The Midale Evaporite on logs is characterized by a very dense and highly resistive bed immediately above the Midale Beds. The top of the Evaporite is defined by a sharp transition to the dolostones in the Ratcliffe Beds. On logs, the base of the Midale Evaporite is placed where the gamma ray log increases into the Marly dolostones of the Upper Midale unit. The seal-rock plugs were sampled systematically from the top to the bottom of Weyburn Midale Evaporite formation in well W2M. The core samples with dimensions of about 5.08 cm (2.5 in.) in length and 3.81 cm (1.5 in.) in diameter were drilled from these plugs. These samples were dried and physically analysed prior to the breakthrough pressure measurements. The porosity was measured by a helium porosimeter. To obtain more reliable results for such tight-rock samples, a sufficient time is allowed in each measurement for helium to reach an equilibrium state. The lithologies and porosities of the core samples are summarized in Table 1. The porosity of the samples is plotted against depth in Fig. 4. It is seen that the porosity of the seal rock changes dramatically at several depths. In the vicinity of the reservoir/seal rock contact zone, the porosity is as high as approximately 8%. In the middle of the Midale Evaporite formation, the sealrock samples are extremely tight and the porosities are as low as %. In this study, the test samples used in breakthrough pressure measurements are selected from the low-porosity region in the middle of the formation.

5 330 S. LI et al. Table 1 Lithology and porosity of seal rock core samples collected from well W2M in the Weyburn Field. Sample No. Sample location (m) RESULTS AND DISCUSSION Nitrogen breakthrough pressure Rock description Porosity (%) Depth above top* A Anhydrite 0.3 A Anhydrite, shale break 0.4 A Anhydrite, shale break 2.3 Depth below top A Anhydrite, shale break 1.0 A Anhydrite 0.3 A Anhydrite 0.5 A Anhydrite, shale break 1.5 A Anhydrite 0.7 A Anhydrite 0.2 A Anhydrite 0.2 A Anhydrite 0.2 A Anhydrite 0.2 A Anhydrite 0.2 A Anhydrite 0.3 A Anhydrite 0.3 A Anhydrite 0.5 Depth below base A Anhydrite, slightly shaly 5.3 A Anhydrite, slightly shaly 7.8 A Dolomite, slightly shaly anhydrite 8.4 *Top of Midale Evaporite in well W2M is at m and the base is at m. Depth (m) Top Base Porosity (%) Fig. 4. Porosity versus depth of the collected seal-rock samples from well W2M in the Weyburn Field. One example of N 2 breakthrough pressure measurement history is given in Fig. 5 (sample A15). During the test, a stepwise increase in pressure was continued until the Pressure (MPa) Pressure Flow rate Time (hour) Fig. 5. N 2 breakthrough pressure test history of seal-rock sample A15. gas broke through the sample. Microscopically, when an increment in pressure is made, the pressure equilibrium across the gas/water meniscus at the displacement front in the sample is broken [i.e. the differential pressure (P n ) P w ) exceeds the capillary pressure reached at the previous step]; hence, the nonwetting phase (gas) advances along the interconnected channels until it reaches a smaller pore throat where the differential pressure is balanced by a larger capillary pressure. As a result, the flow of the nonwetting phase ceases. This process is repeated when the next step of pressure increase is made until, ultimately, the gas breaks through the smallest pore throat in an interconnected channel and a continuous flow through the sample is formed. For each step of rising pressure, there is a trace of brine production at the outlet because of the advances of gas phase in some pores of the core sample. The flow ceases after a period of time when the capillary pressure and the differential pressure reach a new equilibrium. In order to be sure that gas has not broken through at an injection pressure, the injection pressure is increased to the next level only when the flow at the outlet ceases. Because the advances of the nonwetting phase, as well as the equilibration development between the two phases are slow processes, at each pressure level, it takes several hours to achieve the cease point of flow at the outlet. In this work, the cease point means that there is no increment of brine production in the capillary for at least four hours. As shown in Fig. 5, the breakthrough pressure for sample A15 is 27.9 MPa. When the differential pressure exceeded the breakthrough pressure of the seal-rock sample, there was a continuous liquid flow which was, eventually, followed by a mixed gas/liquid flow as characterized by a dramatic increase in volume flow rate. Flow rate (SC cm 3 hour 1 )

6 Gas breakthrough pressure for different gas/liquid systems 331 The results of the N 2 breakthrough pressures of selected seal-rock samples, as well as their porosities and brine permeabilities are summarized in the first four columns of Table 2. The breakthrough pressure for sample A6 exceeds the capability of the apparatus and could not be measured. Generally, the samples with lower porosity and permeability have higher breakthrough pressures. However, sample A11 and A14 had a porosity of 0.2% and 0.3% respectively. Their N 2 breakthrough pressures were measured as only about 2.3 and 2.9 MPa. A possible reason for this is that these samples might have some microfractures that were created during the sampling process as no evidence of original microfractures was observed in the Midale Evaporite in the geological investigations (Wilson & Monea 2004). The maximum N 2 breakthrough pressures for the collected Weyburn seal-rock samples is over 30 MPa, showing that the Midale Evaporite formation is a high-quality seal compared with the seal rocks in other reservoirs reported in the literature (Thomas et al. 1968; Hildenbrand et al. 2002). For example, Thomas et al. (1968) reported the N 2 breakthrough pressure ranging from 0.11 to 4.83 MPa for the dolomite and sandstone seal rocks. The N 2 breakthrough pressures for the seal rocks (Tertiary mudrocks from Norwegian shelf) measured by Hildenbrand et al. (2002) were <6.7 MPa. pressure for CO 2 and CH 4 and its dependency on IFT Table 2 pressures of selected Weyburn seal-rock samples for different gases. P breakthrough (MPa) Sample No. Porosity (%) Brine (md) N 2 CO 2 CH 4 A ) A ) A )5 4.6 A )3 2.9 A )3 2.3 A )3 2.9 A6 0.5 >30 A The IFT of CO 2 /water systems is much lower than that of N 2 /water systems. As a result, the breakthrough pressure for CO 2 is expected to be lower than that for N 2 for the same rock sample. Moreover, the difference of the contact angle for different gas/water/rock systems may affect the breakthrough pressure. The influence of the two interfacial properties (IFT and contact angle) on breakthrough pressure is examined by measuring the breakthrough pressures of different gases for the same seal-rock samples. For seal-rock samples A15 and A5, CO 2 breakthrough pressure measurements were conducted after N 2 breakthrough tests. Figure 6 shows the measurement history with CO 2 for sample A15. As shown in Fig. 6, the backpressure was kept constant at 7.3 MPa and the differential pressure (injection pressure minus backpressure) was raised stepwise by increasing the injection pressure. The CO 2 broke through at a differential pressure of 9.2 MPa, which is much lower than the nitrogen breakthrough pressure of 27.9 MPa. A similar reduction in breakthrough pressure was also obtained for sample A5. To further investigate the reduction of the breakthrough pressure when CO 2 is injected to replace hydrocarbon gases, measurements were made for sample A8 with CH 4 and CO 2. The pressure histories for these two measurements with sample A8 are shown in Fig. 7. The measured breakthrough pressures for CH 4 and CO 2 for the above three samples are listed in the last two columns of Table 2. The comparison of breakthrough pressures and IFTs for different gas/liquid systems is summarized in Table 3. The IFT values for different gas/brine systems under the test conditions (temperature and pressure) were obtained by interpolating the published results and are also listed in Table 3 (Ren et al. 2000; Yan et al. 2001). The last row in Table 3 gives the ratios of the breakthrough pressures and IFTs for different gas/water systems. The IFTs for N 2 /brine and CH 4 /brine are very close at the test conditions, which are about two to three times that of CO 2 / brine systems. The ratio of measured N 2 and CH 4 breakthrough pressures to CO 2 breakthrough pressure is approximately the same as the ratio of their IFTs. Nevertheless, the minor difference between these two ratios could be attributed to: (1) the difference between the contact angles of the CO 2 /water system and the N 2 (or CH 4 )/water systems and (2) experimental errors of the breakthrough pressures determined by using the stepwise Pressure (MPa) Injection pressure 2 Backpressure Differential pressure Time (hour) Fig. 6. CO 2 breakthrough pressure test history for seal-rock sample A15.

7 332 S. LI et al. Pressure (MPa) Methane Carbon dioxide Time (hour) Fig. 7. Comparison of breakthrough pressures between CH 4 /brine system and CO 2 /brine system for seal-rock sample A8. pressure increase. These results illustrate that the change of breakthrough pressure for different gas/brine systems is nearly proportional to the change in IFT. The difference in contact angle for different gas/brine systems, i.e. the wettability of the core samples with different gas/brine systems, is a minor factor. This also suggests that using the breakthrough pressure measured with nitrogen to represent the breakthrough pressure of CH 4 is acceptable in practice as their IFTs are close under most reservoir conditions based on the results in the literature (Ren et al. 2000; Yan et al. 2001). This is why N 2 has been widely used in breakthrough pressure measurements (Thomas et al. 1968; Schowalter 1979). Moreover, if the IFT for N 2 /water and CO 2 /water systems at reservoir conditions are available, the CO 2 breakthrough pressure of a seal rock can be estimated from the determined N 2 breakthrough pressure of the same seal rock. This provides an economical method to reevaluate the sealing pressure of the seal rock for CO 2 storage. For instance, the CO 2 breakthrough pressure of the seal rocks investigated by Thomas et al. (1968) and Hildenbrand et al. (2002) is estimated to be <3 MPa based on their N 2 breakthrough pressures: MPa by Thomas et al. (1968) and <6.7 MPa by Hildenbrand et al. (2002). Such seal rocks are at extremely high risk if they are to be used to as a seal for CO 2 in CO 2 geological storage. For natural gas reservoirs or oil reservoirs with gas caps, which are the case for many oil reservoirs, the hydrocarbons are initially trapped in the reservoir by the capillary forces across the gas (mainly CH 4 )/water interface in seal rocks. The breakthrough pressure is proportional to the IFT of CH 4 /water. For oil reservoirs without gas caps, the breakthrough pressure is determined by the capillary pressure, essentially the IFT of oil/water interface for a given seal rock. At reservoir conditions (high pressure and elevated temperature), the oil/water IFT is in the range of mn m )1 (Berg 1975; Cai et al. 1996), which is higher than or even several times the IFT of CO 2 /brine system. This implies that the breakthrough pressure of the seal rock for CO 2 would be lower, or in some cases much lower, than that for oil. Therefore, for both oil and gas reservoirs, a seal rock that retains the oil and gas in the first place may not be tight enough to prevent the injected CO 2 from migration into the upper formations. Evaluation of the sealing capacity of the seal rock becomes a necessity before the CO 2 injection operation both for CO 2 -EOR and CO 2 storage in depleted reservoirs. Effect of impurity on CO 2 breakthrough pressure In the actual CO 2 -EOR process or CO 2 storage in depleted oil reservoirs, an oil-enriched CO 2 phase, instead of pure CO 2, will replace the oil phase and stay at the top of the reservoir formation in contact with the brine-saturated seal rocks. It is speculated that the impurities (mainly oil components) in the CO 2 phase may change the IFT as well as the wettability of the rock surface, resulting in a change in breakthrough pressure. To examine the influence of the impurities in the CO 2 phase on breakthrough pressure, sample A6 was selected for use in performing the pure CO 2 and oil-enriched CO 2 breakthrough pressure measurements. The oil-enriched CO 2 was obtained by equilibrating CO 2 and Weyburn oil at 15 MPa and 59 C for >2 weeks. Table 3 Comparison of breakthrough pressures and IFTs for different gas/water systems. A15 A5 A8 System pressure (MPa) IFT (mn m )1 ) pressure (MPa) IFT (mn m )1 ) pressure (MPa) IFT (mn m )1 ) N 2 /brine CH 4 /brine CO 2 /brine Ratio* *In the breakthrough pressure column, ratio ¼ breakthrough pressure of N 2 (or CH 4 )/breakthrough pressure of CO 2 ; in the IFT column, ratio ¼ N 2 (or CH 4 )- brine IFT/CO 2 -brine IFT.

8 Gas breakthrough pressure for different gas/liquid systems 333 In the oil-enriched CO 2 phase, CO 2 is the major component, accounting for 93.6% (molar percentage). The total impurity compositions, mainly hydrocarbon components, are small. The experimental histories of measurements with pure CO 2 and oil-enriched CO 2 are given in Fig. 8. For the same sample A6, the pure CO 2 breakthrough pressure was measured to be approximately 21.4 MPa and the oil-enriched CO 2 breakthrough pressure was measured as 21.1 MPa. The two breakthrough pressures are almost the same within the experimental errors. The oil components extracted into the CO 2 phase tend to increase the IFT of the gas/water system and, meanwhile, may cause slight changes in the wettability of the rock surface, resulting in a decrease in the value of cosh (see Eqn1). These two effects, at least in part, cancelled each other out. As a result, the impact of the impurities on CO 2 breakthrough pressure is insignificant. Sample A6 has the maximum value of CO 2 breakthrough pressure among all the measured samples. This breakthrough pressure can be considered as the maximum sealing pressure for CO 2 of Weyburn Midale Evaporate seal. The high breakthrough pressure of the seal rock for CO 2 demonstrates that the Midale Evaporate overlying the Weyburn reservoir, as a seal for the injected CO 2, should not be concerned in CO 2 storage. More attention should rather be paid to the alteration zone immediately beneath the regional Mosozoic unconformity. The main lithology of the Midale alteration zone is anhydritic dolostone and the porosity in this region ranges from 1% to 11% (Wilson & Monea 2004), which is much higher than that of Midale Evaporite. Thus, the sealing efficiency of the alteration zone is expected to be lower than that of Midale Evaporite. Further study for determining the sealing capacity of the alteration zone is necessary. It should also be mentioned that reevaluations of the breakthrough pressure of seal rocks are of first priority for other reservoirs once they are selected as CO 2 storage sites because the sealing capacity of different seal rocks varies significantly and it is much lower for CO 2 than for hydrocarbons. CONCLUSIONS 1 The seal rock of Weyburn Midale Evaporite is of high sealing quality. The measured maximum N 2 breakthrough pressure with the collected seal-rock samples is over 30 MPa, and the maximum CO 2 breakthrough pressure is 21 MPa. 2 The breakthrough pressure for a seal-rock sample is nearly proportional to the IFT of a gas/brine system. CO 2 breakthrough pressure is proportionally lower than CH 4 and N 2 breakthrough pressures because of the lower IFT of CO 2 /brine systems compared with that of CH 4 or N 2 /brine systems. CH 4 and N 2 have almost the same breakthrough pressure as the IFT of CH 4 /brine and N 2 /brine are very close under the test conditions. 3 The results suggest that the sealing capacity of a seal rock that seals the oil and gas in the first place may not be sufficient to seal the injected CO 2 because of the reduction in breakthrough pressure for CO 2. Therefore, reevaluation of the breakthrough pressure is necessary once a reservoir is selected as a CO 2 storage site. 4 The impact on the breakthrough pressure of the oil components extracted into the CO 2 phase is not significant for the seal-rock samples tested in this study. Pressure (MPa) Oil enriched carbon dioxide Pure carbon dioxide Time (hour) Fig. 8. Comparison of breakthrough pressures between oil-enriched CO 2 / brine system and pure CO 2 /brine system for seal-rock sample A6. ACKNOWLEDGEMENTS The financial support from the IEA GHG Weyburn CO 2 Monitoring and Storage Project and Natural Sciences and Engineering Council (NSERC) of Canada are gratefully acknowledged. REFERENCES Berg RR (1975) Capillary pressures in stratigraphic traps. AAPG Bulletin, 59, Cai BY, Yang JT, Guo TM (1996) Interfacial tension of hydrocarbon + water/brine systems under high pressure. Journal of Chemical Engineering Data, 41, Dullien FAL (1992) Porous Media: Fluid Transport and Pore Structure, 2nd edn. Academic Press, San Diego, CA. Hildenbrand A, Schlo} mer S, Krooss BM (2002) Gas breakthrough experiments on fine-grained sedimentary rocks. Geofluids, 2, Krooss BM, Leythaeuser D, Schaefer RG (1992) The quantification of diffusive hydrocarbon losses through cap rocks of natural gas reservoirs a reevaluation. AAPG Bulletin, 76,

9 334 S. LI et al. Ren QY, Chen GJ, Yan W, Guo TM (2000) Interfacial tension of (CO 2 +CH 4 ) + water from 298 K to 373 K and pressures up to 30 MPa. Journal of Chemical Engineering Data, 45, Schlo} mer S, Krooss BM (1997) Experimental characterisation of the hydrocarbon sealing efficiency of caprocks. Marine and Petroleum Geology, 14, Schowalter TT (1979) Mechanics of secondary hydrocarbon migration and entrapment. AAPG Bulletin, 63, Thomas LK, Katz DL, Tek MR (1968) Threshold pressure phenomena in porous media. Society of Petroleum Engineers Journal, 8, Watts NL (1987) Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns. Marine and Petroleum Geology, 4, Wilson M., Monea M (2004) IEA GHG Weyburn CO 2 Monitoring and Storage Project, Summary Report From The Proceedings of 7th International Conference on Greenhouse Gas Control Technologies, 3. Vancouver, Canada. Yan W, Zhao GY, Chen GJ, Guo TM (2001) Interfacial tension of (methane + nitrogen) + water and (carbon dioxide + nitrogen) + water. Journal of Chemical Engineering Data, 46,