EAGE Asia Pacific Virtual Geoscience Week

Gas extraction through a specific shale formation mostly relies on its gas storage capacity. In unconventional system i.e., shale gas, gas is largely stored in the pores spaces and adsorbed on the surface of mineral and organic matter particle. Thus, sorption properties along with mineralogical and geochemical characterization can deliver valuable information on the gas storage capacity of a specific shale formation. Paleozoic black shale-bearing formations are widespread in WP Malaysia. However, there is a lack of published literature present on WP Malaysia shale formations regarding the methane adsorption capacities at reservoir T&P, geochemical and mineralogical analysis which reveals their potential as shale gas reservoirs. Therefore, sixteen samples from seven Paleozoic formations of different geological ages (Silurian-Permian) were collected. These Paleozoic Formations are exposed at Langkawi, Kedah, Perlis, and Perak state of WP Malaysia and grouped into four divisions on the basis of their age i.e., Silurian-Devonian (Baling and Bendang Riang Formations), Devonian (Sanai and Timah Tasoh Formations), Carboniferous (Kubang Pasu, Sanai and Batu Gajah Formations), and Permian (Kubang Pasu Formation). For the assessment of shale gas potential, a comparison of key major properties of the WP Malaysia shale to the world-renowned potential gas shale reservoirs was also examined.

The thickness of the complex fracture beds in shale plays a major role in controlling the porosity and permeability in fractured shale reservoir. Shale has high number of fractures with high Poisson’s ratio, high Young’s modulus, and high brittleness. These complex fractures affect the porosity and permeability in reservoir which impacts the production of oil and gas. Thus, the identification of fracture thickness is essential since it controls the porosity and permeability of shale reservoir. This study demonstrates on the identification of the thickness of fracture by geophysical method since it provides a solution. The thickness of fracture can be estimated using rock physics analysis followed by the selection of seismic attribute. Besides, RGB Blending and Unsupervised Vector Quantizer (UVQ) on fracture network can enhance the visibility of fracture since the minor fracture has low frequency due to its thickness. Lastly, generating wedge modelling is the final route to identify the thickness of fracture bed. We concluded, that, such kind of study for complex fracture help to improve the productivity from shales fracture reservoir and increase the production.

Shale is a source of salinity that selects for organisms that produce osmoprotectants like glycine-betaine. This substrate can be fermented by the consortium of microbial community to yield sustainable methanogenic substrates. Thus, the information provided here would able to give a sufficient overview of methanogenesis in hydraulic fractured shale and may enable the microbiologist, geologist and engineers to work in a collaborative manner to explore the possibility of advancing biogenic methane as future energy technology.”

In this study, adsorption of CO2 on Terengganu shale core samples will be discussed. The working parameters effect on adsorption capacity such as temperature and pressure are studied. A number of analytical analyses such total organic carbon (TOC), X-ray diffraction (XRD), Fourier Transform Infra-red Spectroscopy (FTIR), field Emission Scanning Electron Microscopy (FESEM), surface area and porosity analyzer (Brunauer, Emmett and Teller (B.E.T.)) are investigated. The volumetric adsorption technique is utilized to conduct adsorption measurements at up to 150 bar pressure and 30, 45, and 70oC temperatures to stimulate reservoir conditions. The adsorption and measurements are described in term of equilibrium isotherm models such as Langmuir, Freundlich, Toth, and Sips to demonstrate the adsorption process in term of physical/chemical, homogeneous/ heterogeneous, monolayer/multilayer, and pore filling phenomenon. The kinetic measurement of shale sample is analyzed based on Pseudo First Order and Pseudo Second Order. The results showed that shale characteristics in term of minerology and porosity can plays a vital role in CO2 adsorption capacity. The total organic carbon (T.O.C) for the collected sample shows a range of 2.0 – 3.0 weight percent, which provides an indication of organic matter present. The mineralogy of the Terengganu core shale sample shows the evidence of clay minerals present up to 45% in the rock geometry, which can be an important factor to provide a potential to adsorb CO2 gas .Furthermore, the FESEM results provide a solid evidence of clay mineral present on surface. The average pore size of shale samples are in the range of 13.5 – 14.1 Nm which represents the shale samples as mesoporous. Based on the isotherm plots, result shows the type II adsorption isotherm according to the Brunauer, Deming, and Teller classification. This indicates the occurrence of micro-pores filling. Pressure and temperature parameter plays a major role in CO2 adsorption capacity in shale rock. Increasing the pressure with low temperature can increase the amount of CO2 adsorption in rock. Moreover, increasing pressure and temperature may result in less CO2 adsorption, which can supports physical adsorption as the dominant process. The best fitted isotherm models with the experimental results are Langmuir, Freundlich and Toth, which supports both mono- and multilayer with heterogeneous coverage. The k2 (diffusion) rate constant illustrates higher values compared to k1 (chemisorption) for all Terengganu shale sample with different temperature. Higher rate of constant in this work is shown by the diffusion process. A diffusion phenomenon is more dominant than chemisorption during CO2 adsorption. The findings of this study could help provide detail information about the influence parameters pressure, temperature, and mineralogy that increase the potential of CO2 adsorption and indirectly contribute to enhancing oil recovery (EGR)

The discovery of significant hydrocarbon reserves in bedrock in Indonesia poses two concerns that need to be addressed: (a) how to characterize basement rocks in modeling bedrock as a natural reservoir for hydrocarbons and (b) what processes govern the accumulation of hydrocarbons in bedrock. However, not all open fractures contribute to the discharge of hydrocarbons. Therefore, identification of critical fractures becomes a component in basement fracture characterization. Comparing results between calculated and actual measurements of porosity and permeability suggests that the empirical calculations overestimated the porosity almost two folds of the magnitude. Applying 50% correction to the aperture brought down the porosity value. However, it appears to have no effect on the calculated permeability. Higher fracture density values seem not to guarantee larger permeability. We propose that fracture connectivity plays a more vital role in determining basement permeability.

The ocean bottom node electromagnetic (OBNEM) exploration technology, as a kind of marine electromagnetic exploration technology, has been recognized by an increasing number of oil companies for its role in reducing drilling risks. In recent years, with the support of the National 863 Project and the Enterprise Industrialization Project, the development of submarine high-power current-emitting system and high-precision electromagnetic sensor have made significant breakthroughs. The working current of our self-developed launching system has obtained 1140A, the daily drift of high-precision sensor is up to 30 microvolts, and the noise level of characteristic frequency point reaches pT. The OBNEM exploration equipment has been tested and applied in the South China Sea region, both for the detection of hydrate resources and deep seabed oil-gas resources.

The natural oil seepage in central part of Kudat Peninsula northwest Sabah indicate there is an active petroleum system in the study area with a mature source rock has reached its oil generation level. An active petroleum source rock is probably located in offshore and buried at sufficient deeper depth to be mature. However, information of the active source rock in this area is very limited and unknown. This study presents preliminary geochemical and petrographical assessment of the organic-rich sediment of Sikuati Member. The source rock potential is analyzed through bitumen extraction and liquid column chromatography analyses. The gas chromatography-mass spectrometry and maceral analysis were used to determine the kerogen type and assess paleo-redox condition. The maturity of the source rock is determined by biomarker analysis and vitrinite reflectance. It can be concluded that the coal sample has high source rock potential, which is composed of terrestrial organic matter deposited in sub-oxic condition, originated from mangrove and being transported to delta plain environment. The analysed samples is dominated by Type III kerogen with very minor amount of Type II/m kerogen. The level of thermal maturity ranges from immature to early mature.

One of JOGMEC’s project partners has drilled several wells in a low-resistivity, dominantly alluvial siliciclastic reservoir in offshore Vietnam. Fluid distribution and volume estimation has been highly uncertain due to the low apparent resistivity of the reservoir. This study was performed to decrease uncertainty in the evaluation of the field by characterizing the controls on resistivity and water saturation. Forty-nine core plugs were analyzed using Dean Stark, XRD, XRF, SEM, SEM-EDS, micro-CT, He-permeametry, MICP, NMR T2, and centrifuge. Lab results were integrated with basic and advanced petrophysical analyses, which included NMR T2 factor analysis, T2 modeling, and pseudo-Pc analysis. The study concluded that the main mechanism for low resistivity in the studied interval is high water saturation, but that bound water can be significant and highly variable. The study also demonstrates a workflow that can be used to determine fluid saturation in low-resistivity, lithologically-complex reservoirs. The integration of laboratory centrifuge-NMR T2 and well log NMR T2 revealed that 11 ms is a much more realistic free/bound fluid cut-off than the default value of 33 ms for sandstones.