Geochemistry of Liquid Hydrocarbons and Natural Gases Combined with 1D Basin Modeling of the Oligocene Shale Source Rock System in the Offshore Nile Delta, Egypt.

The current study aims to integrate the geochemical characteristics of the Oligocene shale source rock system, oil, condensate, and natural gas samples in the Oligocene sandstone reservoirs from three exploration wells located in the offshore Nile Delta, East Mediterranean Sea, using organic geochemistry and a 1D basin modeling scheme. The Tineh shales exhibit total organic carbon values ranging between 0.90 and 1.89 wt %, along with hydrogen index values in the range of 54-240 mg hydrocarbon/g rock. The geochemical characterization suggests that the shale intervals of the Oligocene Tineh Formation contain type II-III and type III kerogens and, thereby, could be regarded as promising oil- and gas-prone source rocks with high contributions of gas generation potential. The study also reconstructs the 1D thermal and burial history models, showing that the Oligocene Tineh source rock system is in the main oil and wet gas generation phases from the late Miocene to the present time. The simulated basin models reveal the transformation (TR) of 10-50% kerogen to oil during the late Miocene-early Pliocene period and that the Oligocene Tineh source rock system has larger oil generation and expulsion competency, with a TR value of up to 65% during the early Pliocene-Pleistocene time period. The thermogenic gas was also formed during this time and continued to the present day. This study also investigated the presence of oil and condensate in the Oligocene sandstone reservoir samples and revealed that they were generated from mature source rock, ranging from moderately to highly mature stages. This source rock unit was deposited in fluvial to fluvial-deltaic environments under oxic mixed organic conditions and accumulated during the Tertiary time, as evidenced by the presence of the oleanane biomarker dating indicator. The molecular and isotope compositions of natural gases revealed that most of the natural gases in the Oligocene sandstone reservoir are mainly thermogenic methane gases that were generated from mainly mixed organic matter. The thermogenic methane gases were formed mainly from secondary cracking of oil and gas, with small contributions of primary kerogen cracking. The properties of natural gases together with oil and condensate in the Oligocene reservoir rocks suggest that most of the thermogenic methane gases and associated liquid hydrocarbons are derived primarily from the Oligocene shale source rock system and formed by primary kerogen cracking and secondary oil and oil/gas cracking in different thermal maturity stages. Therefore, the Oligocene Tineh Formation can be regarded as self-source generation and self-reservoir rock; hence, an intensive oil exploration and production program can be recommended whenever the Tineh source rock system is is well developed and deeply buried.

Geochemical and organic petrographic characteristics of high bituminous shales from Gurha mine in Rajasthan, NW India.

A high bituminous shale horizon from the Gurha mine in the Bikaner sub-basin of the Rajasthan District, NW India, was studied using a collection of geochemical and petrological techniques. This study investigated the nature and environmental conditions of the organic matter and its relation to the unconventional oil-shale resources of the bituminous shale. The analyzed shales have high total organic carbon and total sulfur contents, suggesting that these shale sediments were deposited in a paralic environment under reducing conditions. The dominant presence of organic matter derived from phytoplankton algae suggests warm climatic marine environment, with little connection to freshwater enhancing the growth of algae and other microorganisms. The analyzed bituminous shales have high aquatic-derived alginite organic matters, with low Pr/Ph, Pr/n-C17, and Ph/n-C18 ratios. It is classified as Type II oil-prone kerogen, consistent with high hydrogen index value. Considering the maturity indicators of geochemical Tmax (< 430 °C) and vitrinite reflectance values less than 0.40%VRo, the analyzed bituminous shale sediments are in an immature stage of the oil window. Therefore, the oil-prone kerogen Type II in the analyzed bituminous shales has not been cracked by thermal alteration to release oil; thus, unconventional heating is recommended for commercial oil generation.

Quantitative hydro-geophysical analysis of a complex structural karst aquifer in Eastern Saudi Arabia.

The Umm er Radhuma (UER) Formation is a major karst aquifer in Saudi Arabia. This study investigated the hydraulic and petrophysical characteristics of the folded UER carbonate aquifer using integrated hydrological and geophysical logging datasets to understand its complex hydraulic setting as well as detect possible water flow. Petrophysical analysis showed that the UER aquifer has three zones with different lithologic and hydraulic properties. The upper zone attains the best properties with average values of 20%, >100 mD, 3.30 × 10-5-1.34 × 10-3 m/s, and 1.49 × 10-3-6.04 × 10-2 m2/s, with respect to effective porosity, permeability, hydraulic conductivity and transmissivity. The gamma-ray logs indicate a good fracture system near the upper zone of the UER Formation. Pumping test measurements of transmissivity, hydraulic conductivity and storage coefficients were matched with those from geophysical logs and found to be within the expected range for confined and leaky aquifers. Hydrogeological properties were mapped to detect possible groundwater flow in relation to the dominant structure. The underground water of the folded UER aquifer was forced along meandering flow patterns from W-E to SW-NE through the anticlinal axes. The integrated approach can be further used to enhance local aquifer models and improve strategies for identifying the most productive zones in similar aquifer systems.

Characterization of a fractured basement reservoir using high-resolution 3D seismic and logging datasets: A case study of the Sab'atayn Basin, Yemen.

The Sab'atayn Basin is one of the most prolific Mesozoic hydrocarbon basins located in central Yemen. It has many oil producing fields including the Habban Field with oil occurrences in fractured basement rocks. A comprehensive seismic analysis of fractured basement reservoirs was performed to identify the structural pattern and mechanism of hydrocarbon entrapment and reservoir characteristics. A 3D post-stack time migration seismic cube and logging data of 20 wells were used and several 2D seismic sections were constructed and interpreted. Depth structure maps were generated for the basement reservoir and overlying formations. The top of the basement reservoir is dissected by a set of NW-SE step-like normal faults (Najd Fault System) and to a lesser extent, by secondary NNE-SSW oriented faults (Hadramauwt System). The Najd Fault System is dominant and dissects the reservoir in the middle of the field into two prospective uplifts. The northern and northeastern areas constitute the deep-seated downthrown side of the reservoir. Hydrocarbon emplacement is through the fault juxtaposition of the fractured basement against the organic shale source rock of the overlying Madbi Formation. Hydrocarbons are hosted in basement horsts formed by fault-controlled blocks and overlain by the regional seal of the Sab'atayn Formation. The basement reservoir rock is mainly composed of granite, quartz-feldspar, weathered silica, and mica minerals. Fractures were identified from the outcrops, cores, image logs, and the petrophysical analysis. Hydrocarbon saturation was observed in the upper and middle parts of the reservoir, more specifically in front of the highly fractured sections. The fracture porosity was less than 5% and the dead oil had an API gravity of 40° with no H2S or CO2. In conclusion, the structural highs of the Habban Field are of interest because most oil producing wells are drilled into them. We recommend extending the drilling and development activities in these uplifts.

Assessing the hydrogeochemical processes affecting groundwater pollution in arid areas using an integration of geochemical equilibrium and multivariate statistical techniques.

Rapid economic expansion poses serious problems for groundwater resources in arid areas, which typically have high rates of groundwater depletion. In this study, integration of hydrochemical investigations involving chemical and statistical analyses are conducted to assess the factors controlling hydrochemistry and potential pollution in an arid region. Fifty-four groundwater samples were collected from the Dhurma aquifer in Saudi Arabia, and twenty-one physicochemical variables were examined for each sample. Spatial patterns of salinity and nitrate were mapped using fitted variograms. The nitrate spatial distribution shows that nitrate pollution is a persistent problem affecting a wide area of the aquifer. The hydrochemical investigations and cluster analysis reveal four significant clusters of groundwater zones. Five main factors were extracted, which explain >77% of the total data variance. These factors indicated that the chemical characteristics of the groundwater were influenced by rock-water interactions and anthropogenic factors. The identified clusters and factors were validated with hydrochemical investigations. The geogenic factors include the dissolution of various minerals (calcite, aragonite, gypsum, anhydrite, halite and fluorite) and ion exchange processes. The anthropogenic factors include the impact of irrigation return flows and the application of potassium, nitrate, and phosphate fertilizers. Over time, these anthropogenic factors will most likely contribute to further declines in groundwater quality.