Properties Of Shale Rocks Research Articles

Effect of Low-Concentration Hydrochloric Acid on Properties of Shale Rocks

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165689, ’Effect of Low-Concentration Hydrochloric Acid on the Mineralogical, Mechanical, and Physical Properties of Shale Rocks,’ by Samiha Morsy, SPE, C.J. Hetherington, and J.J. Sheng, Texas Tech University, prepared for the 2013 SPE Eastern Regional Meeting, Pittsburgh, Pennsylvania, USA, 20-22 August. The paper has not been peer reviewed. Matrix acidizing is commonly used as a preflush to the hydraulic-fracturing stimulation of shale formations. The process dissolves sediments and mud solids that inhibit the permeability of the rock, enlarging the natural pores of the reservoir and stimulating flow of hydrocarbons. In this paper, the mineralogical and physical responses to matrix acidizing of several important North American shale formations are evaluated. Introduction A few studies have quantified the effect of hydrochloric acid (HCl) matrix acidizing on mineralogical and physical properties of shale formations. However, less is known about the development of conductivity and the acid concentrations necessary to optimize conductivity and, by extension, the impact on production and rock stability. The mechanical properties of shale formations vary as a function of mineralogy, with shales rich in brittle minerals such as quartz and carbonates having higher Young’s- modulus values. Increases in the clay content, total organic carbon (TOC) content, and porosity may lower the Young’s- modulus values. Therefore, dissolution of brittle minerals, while improving short-term conductivity, may lower long-term shale rock stability. HCl reacts rapidly with calcite [Ca2 (CO3)2] and, to a lesser extent, with dolomite [CaMg(CO3)2], and it is predicted that the main impact of HCl on shale will vary as a function of how much calcite is dissolving, which, in turn, is controlled by acid strength, temperature, and pressure. Shale Samples Eagle Ford shale reservoir core samples and outcrop samples from the Mancos, Barnett, and Marcellus shale formations with contrasting assemblages—ranging from the calcite-/clay-rich, quartz-poor Eagle Ford to the quartz-/ illite-rich, carbonate-poor Mancos—were used in this study. The Eagle Ford shale contains the greatest proportion of carbonate, but the absolute volumes of carbonate vary systematically. At deeper structural levels, such as those exploited in south Texas, there is upward of 70% carbonate by volume. With progression toward the northwest, the clay content increases, and the formation is exploitable at shallower depths. The high percentage of carbonate makes it more brittle and fracturable. The Mancos is predominately steel-gray sandy shale but includes stringers of earthy coal, impure limestones, and many thin beds of fine-grained yellow and brown sandstone that are chiefly composed of subangular and angular quartz grains cemented by lime. The Barnett is a very brittle gasbearing siltstone. Most Barnett shales are siliceous mudstones, rich in quartz, and may be considered argillaceous siltstones. Some of the Barnett lithofacies are insensitive to acid because of low volumes of carbonate, but their clay- mineral assemblage may be moderately sensitive to fresh water. Other litho facies have higher abundances of carbonate and are therefore more reactive to matrix acidizing. The Marcellus formation is dominated by black shale with some interspersed limestone beds. Bedding is well developed and often splits along bedding planes. Pyrite is also relatively common in this shale.

Shale Caprock/Acidic Brine Interaction in Underground CO2 Storage

Shale caprock integrity is critical in ensuring that subsurface injection and storage of anthropogenic carbon dioxide (CO2) is permanent. The interaction of clay-rich rock with aqueous CO2 under dynamic conditions requires characterization at the nanoscale level due to the low-reactivity of clay minerals. Geochemical mineral–fluid interaction can impact properties of shale rocks primarily through changes in pore geometry/connectivity. The experimental work reported in this paper applied specific analytical techniques in investigating changes in surface/near-surface properties of crushed shale rocks after exposure (by flooding) to CO2–brine for a time frame ranging between 30 days and 92 days at elevated pressure and fractional flow rate. The intrinsically low permeability in shale may be altered by changes in surface properties as the effective permeability of any porous medium is largely a function of its global pore geometry. Diffusive transport of CO2 as well as carbon accounting could be significantly affected over the long term. The estimation of permeability ratio indicated that petrophysical properties of shale caprock can be doubled.

Empirical Correlation of Effective Stress Dependent Shale Rock Properties

Abstract Maintenance of a stable wellbore is of primary importance during the drilling of oil and gas wells, and it can be troublesome. Porosity and permeability are essential shale rock properties necessary for stress analysis as related to wellbore stability. Empirical relationships that correlate porosity and permeability of shales have been developed based on the effective stress concept. A series of compaction and permeability tests were performed on four shale samples. A small-scale laboratory pressure vessel that includes an innovative testing procedure under simulated downhole conditions was used to determine the effects of confining pressure, pore pressure, temperature, and fluid types on the porosity and permeability of the shales tested. Compaction tests were conducted with de-ionized water under various confining pressures, constant pore pressure, and temperature. The permeability tests were conducted with de-ionized water and nitrogen as the test fluids. Tests were performed by varying the confining pressure, but under steady state conditions and constant temperature. The results of the laboratory tests were used to develop empirical correlations between permeability and porosity for the various shales. The empirical equations were validated with theoretical model equations. Results further showed that porosity and permeability are not constant, but are functions of confining and pore pressures. This study proved that porosity and permeability are not constant and, contrary to the common practice, they are functions of the confining and formation pressures. Therefore, good reservoir and wellbore stability models must consider these effects during ell development programs. Introduction Wellbore instability problems can be better understood by performing compaction and permeability tests under in situ stress conditions. In most cases, these laboratory tests are conducted for reservoir engineering proposes (in sandstone), but they can also be used to derive some clues as to the causes of wellbore instability. Additionally, these tests can predict the conditions under which the formation pressure and in situ stress distribution will result in the failure of the rock. Swelling or shrinkage of the shale formation results from invasion of drilling fluid filtrate into the formation while drilling. This invasion into shale formations is possible due to permeability and porosity properties. This invasion may also be responsible for sliding or creeping of the shale formation, leading to sloughing. The low permeability of shale greatly restricts fluid movement, which not only retards water uptake, but will also retard water expulsion when the wellbore total aqueous potential is dropped below the total aqueous potential within the shale(1, 2). This could result in a type of "spalling" failure of shale into the wellbore. Chenevert and Sharma(3) concluded that the low permeability characteristics of shales, coupled with reduced wellbore pressures and expanding pore fluids, can cause fractures to form in a shale, and produce a form of shale "spalling" into the wellbore. They also showed that the relationship between permeability and effective stress is logarithmic, and a straight line correlates porosity and effective stress. But, they did not develop a mathematical model or correlate with theoretical equations.