Effect of reservoir pressure and total organic content on adsorbed gas production in shale reservoirs: a numerical modelling study

Adsorbed gas plays a key role in organic-rich shale gas production due to its potential to contribute up to 60% of the total gas production. The amount of gas potentially adsorbed on organic-rich shale is controlled by thermal maturity, total organic content (TOC), and reservoir pressure. Whilst those factors have been extensively studied in literature, the factors governing desorption behaviour have not been elucidated, presenting a substantial impediment in managing and predicting the performance of shale gas reservoirs. Therefore, in this paper, a simulation study was carried out to examine the effect of reservoir depth and TOC on the contribution of adsorbed gas to shale gas production. The multi-porosity and multi-permeability model, hydraulic fractures, and local grid refinements were incorporated in the numerical modelling to simulate gas storage and transient behaviour within matrix and fracture regions. The model was then calibrated using core data analysis from literature for Barnett shales. Sensitivity analysis was performed on a range of reservoir depth and TOC to quantify and investigate the contribution of adsorbed gas to total gas production. The simulation results show the contribution of adsorbed gas to shale gas production decreases with increasing reservoir depth regardless of TOC. In contrast, the contribution increases with increasing TOC. However, the impact of TOC on the contribution of adsorbed gas production becomes minor with increasing reservoir depth (pressure). Moreover, the results suggest that adsorbed gas may contribute up to 26% of the total gas production in shallow (below 4,000 feet) shale plays. These study findings highlight the importance of Langmuir isothermal behaviour in shallow shale plays and enhance understanding of desorption behaviour in shale reservoirs; they offer significant contributions to reaching the target of net-zero CO2 emissions for energy transitions by exhibiting insights in the application of enhanced shale gas recovery and CO2 sequestration — in particular, the simulation results suggest that CO2 injection into shallow shale reservoirs rich in TOC, would give a much better performance to unlock the adsorbed gas and sequestrate CO2 compared to deep shales.

Factor Analysis of Well Logs for Total Organic Carbon Estimation in Unconventional Reservoirs

Several approaches have been applied for the evaluation of formation organic content. For further developments in the interpretation of organic richness, this research proposes a multivariate statistical method for exploring the interdependencies between the well logs and model parameters. A factor analysis-based approach is presented for the quantitative determination of total organic content of shale formations. Uncorrelated factors are extracted from well logging data using Jöreskog’s algorithm, and then the factor logs are correlated with estimated petrophysical properties. Whereas the first factor holds information on the amount of shaliness, the second is identified as an organic factor. The estimation method is applied both to synthetic and real datasets from different reservoir types and geologic basins, i.e., Derecske Trough in East Hungary (tight gas); Kingak formation in North Slope Alaska, United States of America (shale gas); and shale source rock formations in the Norwegian continental shelf. The estimated total organic content logs are verified by core data and/or results from other indirect estimation methods such as interval inversion, artificial neural networks and cluster analysis. The presented statistical method used for the interpretation of wireline logs offers an effective tool for the evaluation of organic matter content in unconventional reservoirs.

Seismic expression of delta to deep-lake transition and its control on lithology, total organic content, brittleness, and shale-gas sweet spots in Triassic Yanchang Formation, southern Ordos Basin, China

The Triassic Yanchang Formation is currently a hot spot for lacustrine shale-gas exploration in the Ordos Basin, China. A seismic-sedimentological study using a newly acquired 3D survey was conducted to advance the interpretation and prediction of the shale-gas reservoirs. The seismic volume was converted into a log-lithology volume at the thin-bed level. The inverted acoustic impedance volume was stratal sliced to extract seismic geomorphologic information. Deltaic facies and depositional history were interpreted using lithologic and planform morphology of seismic attributes on stratal slices. Detailed core analysis data including total organic content (TOC), mineral composition, and mechanical properties of sandstones and shales were correlated with seismic-derived lithology and facies. Microseismic data were evaluated for reservoir performance in production wells. Finally, shale-gas sweet spots, or optimal drilling targets, were predicted by mapping relatively high-brittleness lithofacies in 3D using seismic attributes. In the three submembers of the Chang 7 member of the Yanchang Formation, the high-TOC Ch7-1 shale unit is not ideal for shale-gas development because of its ductile nature and tunnel effect when fracturing. Ch7-2 prodelta sediments are shale-gas sweet spots because they are thick, relatively brittle, and in close proximity to high-TOC Ch7-1.

Prospects and Challenges of Developing Unconventional Petroleum Resources in the Anambra Inland Basin of Nigeria

ABSTRACT The boom in the development of unconventional petroleum resources, particularly shale gas in the United States of America during the last decade has had far reaching implications for energy markets across the world and particularly for Nigeria, a country that traditionally has been Africa’s leading crude oil producer and exporter. The Cretaceous Anambra Basin is currently the only inland basin in Nigeria where the existence of commercial quantities of oil and gas has been proven (outside the Tertiary Niger Delta Basin). The possibility of similarly finding commercially viable resources of unconventional petroleum resources in the basin appears quite attractive on the basis of the existence of seepages of shale oil and presence of coal-bed methane in some of the coal seams of the Mamu Formation (Lower Coal Measures) in the basin. This paper presents the results of our preliminary assessment of the shale oil and gas resources of the Anambra Basin. Our main objective is to locate the zones of very high quality plays within the basin, focusing on their depositional environments (whether marine or non-marine), areal extent of the target shale formations, gross shale intervals, total organic content, and thermal maturity. Data on the total organic content (TOC %, by weight) and thermal maturity of shales from different wells in the basin show that many of the shales have high TOCs (i.e greater than 2%) comparable to known shale gas and shale oil plays globally. Shale oil seepages are known to occur around Lokpanta in south-eastern Nigeria, but there is a general predominance of gas-prone facies in our inland basins indicating good prospects for finding unconventional petroleum in this and other Nigerian inland sedimentary basins. The main challenge to the exploration of unconventional resources in Nigeria today has to do with the absence of the enabling laws and regulatory framework governing their exploration and subsequent exploitation. The revised Petroleum Industry Bill (PIB) currently under consideration in the National Assembly is expected to introduce drastic and lasting changes in the way the petroleum industry business is conducted in the country, but all the provisions of the draft law pertain mainly to conventional oil and gas resources.