Shales play a major role in petroleum exploration and production because they occur both as source rocks and cap-rocks.Their small pore throat size means that very high capillary pressures are required to establish any hydrocarbon saturation in the shales. The minimum capillary entry pressure (trap capacity) defines the maximum height of a hydrocarbon column that can be trapped by a shale. In this paper, pressure transmission tests were used to experimentally measure capillary entry pressures of various non-wetting fluids (oil-based mud, crude oil. Decane and Nitrogen gas) through different shales.These capillary entry pressures are needed for the estimation of a shale's seal capacity (h).Results show that measured capillary entry pressure (seal capacity) of shales are correlated with other shale properties such as CEC and permeability.The effects of fluid type and interfacial tension on capillary entry pressure of shales were also investigated.Results show that the presence of a hydrocarbon phase (decane) in the shale reduces the shale capillary entry pressure (seal capacity) and significantly increases hydrocarbon flux. Also, the presence of surfactants in the hydrocarbon phase significantly reduces the capillary entry pressure and, therefore, the shale's seal capacity.Measured capillary entry pressures were also used to estimate the pore throat radius of shales. Since pressure transmission tests are so difficult to run, a quick and easy rig-site electrochemical test on shale cuttings to characterize the capillary entry pressure of drilled shale formations is suggested. Introduction In order for hydrocarbon accumulations to exist, there must be a source rock to produce the hydrocarbon, a reservoir rock to host the hydrocarbon and a good cap rock to trap it and stop its migration upwards.According to Vavra et al (1992), a seal is generally defined as a sediment, rock or immobile fluid with high capillary entry pressure (also known as capillary breakthrough or capillary entrance pressure) that acts to stop the flow of hydrocarbon.Salts, anhydrites, silty shales and clay mineral-rich shales are some of the common seal lithologies. Shales play a major role in petroleum exploration and production because they are commonly considered to be both source rocks and seals.Their ability to exhibit good sealing characteristics arises from their small, water-wet, pores.These small pore throats are responsible for generating high capillary pressures, which excludes hydrocarbons.Shales are also underground seals for CO2 sequestration.One of the critical aspects of CO2 sequestration is the ability of the shale to stop the flux of CO2 through it.This ability is complicated by the partial solubility of CO2 in the water.The capillary pressure is given by: (1) where s is the interfacial tension between the hydrocarbon phase and the water, ? is the contact angle and r is the shale pore throat radius. In order for hydrocarbons to enter a shale, the differential pressure between the hydrocarbon column and the water must exceed the minimum capillary entry"threshold" pressure of the shale.By definition, the minimum capillary entry pressure is the capillary pressure at which the non-wetting phase, usually oil, starts to displace the wetting phase, usually brine, contained in the largest pore throat within a water-wet formation.It can be seen from equation (1) that the capillary entry pressure can be significant, especially for shales with very small pore throats (permeability).Hale et. al. (1993) shows that the hydraulic permeability of shales is extremely low (10–7 to 10–12 Darcies) and also that oil will not enter shale pores until the differential pressure exceeds the minimum capillary entry pressure.

This paper presents a comprehensive set of experimental data for the membrane efficiency of four shales when interacting with different water-based and oil-based muds. Pressure transmission tests were used to measure the membrane efficiency using three different cations and two different anions at different concentrations (water activities). It was found that the measured membrane efficiencies of shales when exposed to salt solutions were low, ranging from 0.18% to 4.23%. Useful correlations are presented between the membrane efficiency and other shale properties. Results suggest that the membrane efficiency of shales is directly proportional to the ratio of the cation exchange capacity and permeability of shales. Higher cation exchange capacities and lower permeabilities correlate very well with higher membrane efficiencies. Moreover, the ratio of the hydrated solute (ion) size to shale pore throat determines a shale's ability to restrict solutes from entering the pore space and controls its membrane efficiency. Cations and anions with large hydrated radii yielded higher membrane efficiencies, compared to ions with small hydrated diameters. Thus, the formulation of drilling fluids must take into account the types of cation and anion in the water-based fluid. It was also found that the membrane efficiency of oil-based muds was high, however, these membrane efficiencies were not 100 % as postulated by many researchers. Background and past work Osmosis has long been recognized as a means to extract water out of a shale when the water activity of the shale is higher than that of the drilling fluid. In the absence of a hydraulic pressure gradient, the movement of mud filtrate into shale is mainly governed by the chemical potential difference between the pore fluid and the mud and this results in the osmotic transport of water, (Ewy and Stankovich 2000). However, it has been recently shown that the osmotic potential generated between shale and drilling fluid is greatly influenced by the flow of ions into or out of shale due to ionic concentration imbalances (Zhang et. al. 2004). Therefore, the actual osmotic effect is often less than the osmotic potential. This has spurred much interest to quantify the impact of ionic flow on the osmotic potential and that in turn has led to introducing the concept of shale membrane efficiency. The membrane efficiency describes the ability of a shale to hinder ion movement when interacting with drilling fluids. If the shale completely stops ionic flow, the shale is said to act as a perfect semi-permeable membrane with a membrane efficiency of unity. If the shale lets ions flow freely, the shale is said to act as a non-selective membrane with a membrane efficiency of zero. Staverman (1952) was one of the first researchers to investigate the membrane efficiency of shale. He presented a model to estimate the reflection coefficient (i.e. the membrane efficiency) of shale membranes. He showed that the measured osmotic pressure obtained using a non-ideal membrane is different from the thermodynamically predicted value. Furthermore, this measured osmotic pressure is highly dependent on the permeability of the membrane to the solutes. Following Staverman, Low and Anderson (1958), Fritz and Marine (1983) and Ballard et al (1992), presented theories that suggested osmosis as a mechanism for swelling pressures generated by shales. These studies all showed that a shale could act as a leaky semi-permeable membrane since it did not completely stop the flux of ions.

The primary cause of wellbore instability is the interaction of water-based muds with shales. The movement of water and ions into or out of a shale can result in large changes in pore pressure in the vicinity of the wellbore, potentially leading to wellbore failure. A new method, the Gravimetric - Swelling Test (GST), for determining the compatibility between shales and drilling fluids is presented in this paper. An experimental protocol and equations are presented that describe how such measurements can be conducted and interpreted with relative ease. The mass of water and ions entering or leaving shale samples is determined. With additional swelling measurements, the impact of the water and ions uptake on swelling pressures generated can also be obtained. In this paper, results are presented for two preserved shale samples obtained from the field. The influence of different types of ionic solutions on water and ion movement is presented for each shale. It is shown that water uptake and swelling of shales is controlled not only by differences between shale water activity and water activity in the mud (as assumed in the past), but ion type and concentration also play an important role. In these tests the water uptake decreases, while the ion adsorption increases with increasing salt concentration. Different types of cations are shown to have a large influence on water/ion movement. This paper presents a data set showing the influence of ion type and concentration on water uptake by shales. The role of capillary pressure, osmotic effects and ionic diffusion on swelling behavior of shales is also discussed. The technique presented herein may possibly be used at the rig-floor to determine the compatibility of shales with salt-water drilling fluids. Introduction Wellbore instability in shale formations has been a significant problem in the petroleum drilling industry for over a century. It is estimated that this problem costs the oil industry about 1 billion US dollars each year (Chen, 2002). It has been shown that oil-based drilling fluids that contain elevated levels of salt can address this problem, however, excessive costs and environmental requirements limit their use. These factors have encouraged the development of water-based drilling fluids that perform in a manner similar to oil-based drilling fluids. It is believed that the main cause of shale instability stems from unfavorable interactions between the water - based muds and shale formations (Chenevert, 1970; Bol, 1992; Van Oort, 2003). Shale instability is generally caused by pore pressure changes and mechanical property alterations around the wellbore, induced by both chemical and hydraulic effects. All of these alterations are caused by water and ion movement into or out of the shale formations. Chenevert (1970) showed that differences in water activity could cause an osmotic flux of water into or out of the shale. Ballard et al (1992) developed an experimental technique using radioactive tracers to monitor water and ion movement in shales and found it to be a diffusion dominated process under zero applied pressure. Concentration gradients are the driving force for the transfer of ions into or out of shales. Van Oort (1997) showed pore pressure changes due to the flux of water and ions into or out of the shale.

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