This paper presents experimental data showing the dependence of shale membrane efficiency of water-base muds on its petrophysical properties and mud composition. Wellbore instability often occurs as a result of osmotic pressures that develop when shale is in contact with water-base muds. The osmotic pressures generated are proportional to the shale membrane efficiency. It is not currently possible to directly measure the shale membrane efficiency downhole. A pressure transmission technique was used to measure the membrane efficiency of Atoka shale at different porosities. This provides a way to estimate shale membrane efficiency from wireline measurements. The results of this study could possibly be used to design muds that cause shale strengthening and result in better wellbore stability. Two series of tests were performed; the first used brine solution as the test fluid while the second used three industry provided water-base muds. Results show that the membrane efficiency of Atoka shale ranges from 0.4% to about 13% and is a function of the shale porosity. This shows that the porosity of the shale itself is an important consideration in mud design. The data clearly show that the membrane efficiency is negatively correlated with the shale porosity until about a porosity of 7.5% beyond which there is essentially no change in membrane efficiency. A good correlation was also found between the shale permeability (which is in the order of 0.1 nD) and the membrane efficiency. Beyond a permeability of 0.2 nD osmotic effects are small. For tests conducted with water-base muds, the membrane efficiency of the shale was reduced by a factor of more than 2 after contacting two of the three muds with the mud-altered Atoka shale. This decrease was found to correlate very well with an increase in porosity and permeability in the shale. However, muds which reduced the permeability recorded an increase in membrane efficiency. This shows the importance of porosity and permeability reducing agents in changing the membrane efficiency and osmotic pressure in shales. Shale membrane efficiency has been shown to correlate with the shale porosity and permeability. Interaction of the shale with different water-base muds is shown to change the membrane properties of the shale. Furthermore, the nature of this change determines the effectiveness of these muds in the stabilization of troublesome shales. This is important because of the time dependent nature of wellbore failure. This study shows that certain drilling fluids have the ability to alter the shale through permeability reduction induced by osmotic flow. The results of the study can be used to better design water-base drilling fluids that will stabilize shales. Background and Prior Work Shales are clastic sedimentary rocks containing lithified clay-sized mineral particles with distinct laminated layers. The clay constituents are often characterized by a large surface area and associated bound water. The clay types include smectite, which has water and sodium ions associated with it. It is also the most hydrophilic clay type and has the highest surface area (about 750 m2/gm). Illite is about four times less hydrophilic than smectite. It has potassium with no associated water. The surface area is about 80 m2/gm. However, kaolinite has no isomorphic substitutes in its structure and it is very pure with little or no reactiveness. Ceramists use it for this reason. The characteristics of any particular shale are often governed by the amount of each clay mineral present. Shales that contain more smectite tend to be very reactive and highly susceptible to swelling.
Oil-based muds (OBMs) have been developed to combat drilling problems caused by shale hydration. This paper presents experimental data that show the factors that control the movement of oil filtrate into a shale, as described by its "entrance pressure." Although the oil filtrate of the OBM does not hydrate the shale, it can penetrate the shale, increase the pore pressure, and cause wellbore failure. It is of primary interest to understand this when troublesome shales are drilled. It is also important to understand how factors such as the emulsifier concentration in the OBM and the porosity of the shale affect this entrance pressure.The objective of this study is to determine and quantify the factors that control the oil entry pressures of shales. For this purpose, five OBMs, containing different concentrations of emulsifiers, water, and oil, were studied.The study was also intended to determine the effect of shale porosity on entrance pressure. Data are reported for the Arco China shale samples having porosities of 1.8 (native), 3.9, and 4.9%.It was observed that for a given OBM water content, as the emulsifier concentration increased, the required entrance pressure and the electrical stability (ES) of the mud increased. Also, for shales that had higher porosities and, therefore, larger pore throats, the oil entrance pressure decreased.
Oil-based muds (OBMs) have been developed to combat drilling problems often caused by shale hydration. Therefore, it is of utmost importance to understand the interaction of OBMs as they contact shales. Past research (Chenevert 1970) has shownhow the movement of water from OBMs can be controlled by the addition of salt. This paper deals with the movement of the oil phase of the OBM, as described by its hydraulic "Entrance Pressure." Although the oil filtrate of the OBM does not hydrate the shale, it can penetrate and flow into the shale at a certain entrance pressure. Such flow into shale can be as damaging as water flow, because it increases the pore pressure of the shale, which can cause wellbore failure. It is of primary interest to understand this when using OBMs in shales. It is also important to understand how factors such as the emulsifier concentration in the OBM and the porosity of the shale affect this entrance pressure. The objective of this study is to perform laboratory tests in order to determine and quantify the factors that control the entry pressures for shales. For this purpose, five OBM samples with different emulsifiers and oil and water concentrations were prepared. The study was also intended to derive an understanding of the effects of shale porosity on entrance pressure. In order to vary the porosity of the test samples, it was convenient to place them in various controlled environments with relative humidity (i.e. water activities). Data are reported for Arco China shale samples having porosities of 1.8% (native), 3.9%, and 4.9%, at water activities (aw) of 0.72, 0.86, and 0.96, respectively. It was observed that as the emulsifier concentration increased, the oil breakthrough pressure increased. It was also observed that as the porosity of the shale is reduced (smaller pore throats), the entrance pressure for the mud increases. Introduction Shales are low-permeability sedimentary rocks with small pore radii that have medium to high clay content, in addition to other minerals, such as quartz, feldspar, and calcite. The distinguishing features of shale are its clay content and low permeability, which results in poor connectivity through narrow pore throats. Shales are also fairly porous and are normally saturated with formation water, with several factors affecting their properties, such as burial depth, water activity, and the amount and type of minerals present. Considering the fact that shales account for 70 - 75% of the formations drilled around the world (Manohar, 1999), it is important to understand and minimize shale-related problems while drilling. Drilling performance has exhibited the effectiveness of OBMs in combating drilling problems caused by shale hydration, differential pressure sticking, corrosion, and high formation temperatures (Simpson 1978). However, when using a water-based mud, water movement from the mud to the shale results in swelling stresses and pore pressure increases that lead to wellbore failure. OBMs are water-in-oil emulsions that contain water, emulsifiers, organophilic clay, and a weighting material (Growcock, et, al. 1994). The water phase is usually a calcium chloride (CaCl2) salt solution, with a water activity (aw) that resembles the aw of the formation. This eliminates water transfer to or from the water-sensitive zones and thereby maintains a stable wellbore. The water in the oil is stabilized with a primary emulsifier (often a fatty acid salt), while the weighting material and the drilled solids are made oil-wet and dispersed in the mud with a secondary emulsifier. It is thought that both emulsifiers have dual roles, with the primary emulsifier also acting to some extent as a wetting agent, and the secondary emulsifier acting as a true emulsifier.
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