Hydrocarbon Source and Reservoir Rock Potential of the Paleocene Hangu Formation in the Himalayan Foreland Basin, North West Pakistan: Insight from Geochemical and Diagenetic Study

The detail study of the Paleocene Hangu Formation consisting of sandstone, carbonaceous shale, coal, and laterite has been carried out for its source and reservoir rock potential in the Salt Range, Surghar Range, and Attock-Cherat Ranges. The TOC values of the shales range from 0.33-11.19 (2.97 wt. %) and are characterized as good to very good quality source rock except the samples from Attock-Cherat Ranges. Similarly, the free (S1) and cracked hydrocarbons (S2) amount are very small suggesting Hangu Formation as a poor source rock for free and cracked hydrocarbons except the samples from the Lumshiwal Nala. The generative potential, type of kerogen and thermal maturity calculated on the basis of TOC, S1, S2, HI, PI and Tmax all characterized Hangu Formation as fair to excellent gas or oil source, type III and mixed type III/II kerogen and immature source rock. The Hangu Formation sandstone is brownish to yellowish brown, fine to coarse grained, medium to thick bedded and massive in places. The major diagenetic changes observed in a sandstone of the Hangu Formation are; compaction, cementation, replacement and grain fracturing. The effect of mechanical compaction is more evident than that of chemical compaction. Grain contact ranges from pointed to long through sutured. The type of cement present includes silica-cement, calcite-cement, dolomite-cement, and iron-oxide cement. Silica-cement is present as both overgrowth and pore-filling cement. Clay rim is present around few grains. The process of early calcite cementation, mechanical compaction, silica, and iron oxide cementation destroys the reservoir properties of the Hangu Formation sandstone. There is no visible porosity observed except the dissolution of few grains at their margins. However, during the process of uplifting such porosity usually filled by the iron- oxide cementation. Hence, Hangu Formation is an immature source rock with a poor reservoir potential.

Making oil from magma

Petroleum systems within rifted margin basins affected by volcanism continue to remain challenging for the exploration of hydrocarbons, most notably owing to the volume of intrusions that pose imaging, drilling and exploration problems. Typically, intrusions possess small thermal aureoles, but despite this, there is evidence that intrusions could none the less be responsible for the generation of commercial volumes of hydrocarbons. Here we shed new light on this petroleum systems challenge by integrating organic geochemical and Raman spectroscopic techniques to produce potential volumetric data for hydrocarbons generated as a result of igneous intrusion. The results indicate that, in areas with immature source rock intervals, it may be possible for intrusions to generate volumes of oil that would be capable of comfortably filling likely known oil reservoirs. This is a critical step forward in integrating several analytical techniques, indicating that under the right conditions there is the potential for hydrocarbon generation as a result of igneous intrusion.

DETERMINATION FROM WELL LOGS OF THE TOTAL ORGANIC CARBON CONTENT IN POTENTIAL SOURCE ROCKS

This paper discusses, in some detail, the log responses to total organic carbon (TOC) in the Upper and Middle Velkerri Formation in an area of the McArthur Basin, Northern Territory, Australia. The Formation Density log was found to be superior to other standard well logs in assessing values of TOC in the area studied. A theoretical model was used to estimate TOC from the Formation Density log. The model was established and its applicability was verified by comparison with other models. Based on geochemical properties the Upper and Middle Velkerri Formation is classified into three categories: nonsource rocks, mature source rocks and immature source rock. They show significant differences in the well log responses, and different models had to be established for the three categories to determine the TOC content from well logs. Comparison of the results of using a different model for each category instead of a single model to cover the three categories shows that the former approach gives more meaningful answers.