Shale Gas Production Processes

Shale Gas Analysis

What is shale gas?

According to Alexander et al., (2011), shale gas refers to a natural gas that stored in organic-rich, fine-grained rocks, including shale, laminated siltstone, or mudstone. It contains a mixture of hydrocarbon gases, majorly ethane, and methane. The gases are tightly locked within the pore spaces of the sedimentary rocks. The reservoirs of the shale gas have features such as low impermeability to clay content and, small grain sized contents. The term shale does not focus on a specific rock, but rather the rocks that have fine-grained particles that are smaller than the coarse-grained particles such as siltstone and carbonate rocks among other rocks. The generation of the shale occurs through various processes that include primary and secondary thermogenic degradation alongside biogenic degradation of the organic matter. The occurrence may also occur in a combination of all of the above mechanisms. The formation of shale gas occurs through a complex process that takes years (Andrews, 2013). The process of formation begins with the deposition of material consisting of a mixture of clay and minerals in deep waters such as lakes, seas, and oceans. The material also combines with algae, plankton, and plant matter during their burial. As the mud changes into shale during its shallow burial, bacteria act on the available organic matter resulting in the release of biogenic methane as a byproduct (Bakshi, 2012).

What are shale gas reservoirs?

Shale gas originates from a source rock with hydrocarbons that are generated following the burial of clay, minerals, algae, plankton, and plant matter. The hydrocarbons migrate from the original rock via carrier beds and accumulate in the porous reservoir over time. The porous reservoir consists of carbonate and/or sandstone in discrete traps that are located on the structural high on the margins of the center basins. The low permeability of the rock that acts as the source of the gas makes it trap the shale gas and prevent it from escaping towards the surface of the earth. The gas can also be held in the natural fractures below the surface of the earth alongside the pore spaces of the sedimentary rocks (Berman, 2009). In addition, Bulletin & Norton (2003) recognize that the gas can be absorbed into organic material that can be processed to release the stored gas. Moreover, Issler et al., (2002) states in their article that the shale gas can be adsorbed to the surfaces of the minerals within the natural fractures and/or pore spaces and absorbed to mineral surfaces of the matrix rocks. The existence of the shale gas in fractures is obtained using methods such as multi-stage fracturing and drilling horizontal wells.

Defining characteristics

Geologists consider specific geochemical characteristics to evaluate the ability of the shale to have the desired production potential. The core data acts as the major source of the features of evaluating the abilities of the shale rock under consideration. Methods such as downhole sensors and calibration of the log data are effective in allowing the geologists determine the potentialities of the shale rock (Ross & Bustin, 2008). In specific, they consider the ability of the shale rock to meet the characteristics of shale resource that include the gas volume and capacity, mineralogy, permeability, thermal maturity, and total organization carbon (TOC). Total organic carbon governs the potential of the shale rock to provide the desired amount of shale gas. Therefore, rocks with high TOC values are rich in shale gas, while those with low values have less shale gas content (Lee et al., 2011).

Shale rocks have features that vary significantly between the reservoirs and within the reservoir due to the variety of materials and fabric anisotropy possessed by the organic-rich shale. The elastic characteristics of the shale gas make it to have strong anisotropic properties. The degree of anisotropy correlates with the amount of organic contents and clay in the parent rock. Vertical Young's modulus and velocity also play a role in influencing the anisotropy of the shale rocks. Significant evidence shows that the shale gas has a relatively stronger anisotropy irrespective of its limited TOC content of less than six percent. Shale rock considered a reliable source of shale gas should have high gamma-ray values. High Gamma ray value translates to high organic carbon content, thereby, a considerable source of shale gas (Shebl et al., 2010).

Moreover, the content of the organic matter defines the features of the shale rock. Shale rock should be rich in total organic matter of values greater than two percent. The high TOC content shows the potentials of the rock to provide an adequate supply of shale gas. In addition, the kerogen shale rock should be Type I, II, or IIS to make it qualify as a potential shale reservoir. Kerogen of the above classes' mean the rock is of marine or the planktonic origin, thereby, has a large amount of shale gas (Schenk, 2011). According to Speight (2013), shale rock should have an original hydrogen index of more than 250 mg/g for it to supply the required amount of shale gas. Such value is desirable because the kerogen type found in the shale rock relies on the original hydrogen index of the shale rock. Similarly, Lee et al., (2011) recognizes that the mineralogy or the clay content of the shale rock should be low, i.e. less that 35%. Low content of clay improves the quality of the shale rock by facilitating fracking, thereby, extraction of the shale gas. The content of silica should be more than 30% with some presence of some carbonate and non-swelling clays.

Jacobi et al., (2008) recognizes that shale rock should meet the requirement of thermal maturity that include maturation for gas generation. The thermal maturity of the rock should range between 1.1-3.5% to become a suitable rock for extracting shale gas. The geologists should identify the oil precursor in the rock to make it an ideal source of shale gas. In addition, Loucks & Ruppel (2007) present a system of shale rock analysis that considers the gas content, depth minimum, shale porosity, and overpressure as the key defining features of the potential shale rock for producing shale gas. In specific, the authors recognize that the gas should be present in the rock as a free and/or adsorbed gas with gas content of 60-200 bcf. The depth minimum should be greater than 5000 feet with a shale porosity of between 4% and 7% and not more than 15%. The overpressure in the parent rock should be highly over-pressured and having burial and tectonics history. Shale rocks with tectonics and burial history are rich in carbon due to involvement of planktons and algae of the sea that were buried deep into the earth. Therefore, shale rock having these features qualifies as the potential source of shale gas (Schenk, 2011).

How are shales evaluated for gas potential?

It is highly recognizable that not all the shale rocks have the potentials to provide the required volume of shale gas. Zou et al., (2012) appreciates that assessment of the shales often occurs prior to the evaluation of the potentialities of the shale rocks. Assessment entails conducting preliminary reservoir and geologic characterization of the shale formation and basins alongside establishing the area extent of the shale oil and gas formation. The assessment also entails defining the area of prospecting the gas and oil alongside calculating the risked shale oil and shale gas place. Seismic mapping using the available hydrocarbon is one of the methods of evaluating the potentiality of the shale rocks. Seismic mapping provides information related to the carboniferous basin shales that provide rich sources of carbon that determine the shale content of the shale rocks (Loucks & Ruppel, 2007).

The potentiality of the shales can also be evaluated by computing the organic content of the shale rocks using the density logs. The process entails taking the density of the shales in the area of focus alongside the density of the shale minerals and the average grain density of the shale matter. The method of evaluation operates on the premise that changes in the organic content of the shales produce significant changes in their formation, density, and the organic content. As such, slight variation in the density of the content will provide valuable information for evaluating the potentiality of the shales (Loucks & Ruppel, 2007). Moreover, Zou et al., (2012) recognize that the success of using this method to evaluate the potentiality of the shales depend on analyzing the four component system of the parent rock that has rock matrix, pyrite, organic matter, and interstitial pores.

Geochemical analysis also allows for the evaluation of the potentialities of the source rocks of the shale gas. The process involves analyzing the samples of the shales in conjunction with a detailed evaluation of the logs obtained from previously drilled wells. Geochemical testing is done to the capabilities of the shale rock in generating hydrocarbons required for producing the desired volume of shale gas. As such, rocks with high amounts of concentrate organic matter has better potentials as compared to those with low concentration of organic matter. Evaluation of the potentialities of the shale rock is also done using the vitrinite reflectance test. Vitrinite reflectance provides valuable information on the maturity of the shale rock. The method operates on the premise of the reflectance of the kerogen that shows the maturation and the evolutionary age of the shale rock. It also relies on the fact that as the temperature of the parent rock increases, the hydrocarbon generation increases resulting in a change in the reflectance of the kerogen (Shebl et al., 2010).

According to Kinley et al., (2008), the programmed pyrolysis technique is also used to evaluate the potentialities of the shale rock. The process entails heating the shale rock at different temperatures (300 and 550 degree Celsius) to release the hydrocarbons it contains. Geologists measure the collected hydrocarbon for its hydrogen content that correlates with the availability of the shale gas in the rock. Well logs serve as a valuable source of information that can be used for the evaluation of the potentials of the shale rock to produce an adequate amount of shale gas. Logs provide information such as gamma activity that plays a central role in influencing the occurrence of shale gas in the shale rocks (Schenk, 2011).

As such, rocks that display high gamma value have a high content of kerogen, hence, suitable for providing an adequate amount of shale gas. Elemental Capture Spectroscopy also proves an effective technique for evaluating the potentials of the shale rocks. The technique incorporates the use of Platform Express integrated wireline logging tool that aids in the calculation of the gas saturation and its lithology in the parent shale rock. The geologists are able to compare the content of quartz, carbonate, and pyrite that influence the quality of the shale rock. Other methods of evaluating the potentials of the shale rock include basin inversion and paleogeography, stratigraphy, and in-depth analysis of the isopach maps (Bakshi, 2012).

How is shale gas stored in shale gas reservoirs?

Shale gas is stored in three different ways in the shale gas reservoirs. The ways in which it is stored include adsorbed/absorbed on the organics and minerals, free gas in the parent shale rock and dissolved in water. Adsorbed or absorbed shale gas refers to the gas that is attached to clays or organic matter. The very low impermeability of the shale rock makes the gas to be attached to the clay and mineral particles, as it does not allow the escape of the gas. Similarly, the low impermeability results in the adsorption of the shale gas onto organic material (Pollastro et al., 2007).

Shale gas also exists as free gas in its shale rock. The free gas is held in between the tiny spaces of the rock (micro-porosity, porosity, and pores) or within the spaces brought about by cracking of the rocks in the case of micro-fractures and fractures. Significant analysis of the shale gases in the parent rock reveals that the free gas represents the quantity gas with higher pressures than the other forms of gases in the reservoir. The percentage of the free shale gas in the shale rock ranges from 15 to 80%, depending on the pressure of the reservoir, gas saturation, and porosity. Solution shale gas exists in combination with other liquids such as oil and bitumen. The existence of the gas in solution form translates to the need for the use of sophisticated techniques of obtaining the gas from the solution. Comparative analysis of the three forms in which shale gas is stored places solution form the least mode of storage of the shale gas. In addition, extracting shale gas in dissolved form is harder as compared to the other forms of gas storage (Passey et al., 2010).

How are shale volumes calculated?

The high radioactive nature of shale than that of the sand or the carbonates makes it possible to calculate the volume of shale in the reservoirs. The volume of shale in the reservoir is often expressed as a percentage or a decimal fraction called V (shale). The process of calculating of the volume of shale begins with the calculation of the gamma ray index in the reservoir to evaluate its volume from the ray log of gamma rays. The gamma ray log consists of several linear and nonlinear responses that determine the availability of shale in the reservoir. The nonlinear responses are more optimistic than the linear responses as they are based on the formation age and geographical area of the shale rock. Therefore, the optimistic nature of the nonlinear responses produces shale volumes lower than that obtained from the linear equation (Paquet et al., 2010).

Shale volumes can also be calculated using resistivity shale volume formula. In this case, the shale indicator is dependent on the resistivity response of shale in clean pay sand. A variety of factors, including porosity, salinity of water, and lithology affect the resistivity contrasts seen when calculating the volume of shale using this method. As such, the influence of these factors imply that the calculated volume of the shale from the resistivity can be too high, or too low, or both. The formula for calculating the shale volume using the resistivity is as follows:

vsh=[(Rsh (R,™-R,))/(R,(R^-Rsh))]1/b (Nash, 2010).

In addition, the volume of the shale gas can be calculated based on the neutron-density shale volume method. It allows determination of the volume of shale and effective porosity when the zone consists of effective sands and shales. High-calculated volume of the shale or too low volume of effective porosity will be achieved when there is the presence of the passive shales and other forms of reservoir rocks. The calculated volume of shale can be either pessimistic or optimistic, depending on the matrix parameters used for determining the volume of shale gas. The neuron-density shale volume method of calculating the volume of shale produces three values where the lowest value becomes the volume of shale in relation to the porosity of the rock and hydrocarbon content (Montgomery et al., 2005).