Lockhart formation provides source rocks for Potwar basin

Aug. 2, 2021
Syed Bilawal Ali Shah
University of MalayaKuala Lumpur

Exploration and production companies should target traps above Potwar basin’s Lockhart formation to increase oil and gas production. Source-rock sedimentology for Potwar basin, host to most of Pakistan’s major hydrocarbon fields, has been well-researched, but potential of the Lockhart formation, one of the sources in the basin, had not yet been fully established.

To understand its source-rock potential, petrological techniques and organic geochemical analysis of Lockhart samples measured the type of organic matter, quality of organic matter, and thermal maturity. Organic petrographic and organic geochemical analyses indicate that the formation has good oil-gas generative capacity and may act as a significant source in the basin.

Geological setting

Potwar basin covers two thirds of eastern Pakistan and has been explored since the first commercial oil discovery at Khaur in 1914 by Attock Oil Co. The first commercial gas discovery was in 1979 in Adhi.

Early Eocene and Paleocene sedimentary deposits are prime hydrocarbon reservoir and source rocks in the basin. Organic-rich shallow marine deposits reported by Fazeelat, et al. prompted a reevaluation of formation source-rock characteristics in Potwar’s Lockhart formation.

The research area lies on the north western part of Indian Shield in the Southern Potwar Deformed zone. The Kirthar Fold belt borders on the west. Potwar basin has a complex tectonic structure containing salt domes, salt-cored anticlines, duplexes, steep faults, reverse faults, and thrust fault systems (Fig. 1).

The basin’s surface geological features do not characterize subsurface structures because exposed younger molasses show anticline with gently dipping limbs. Seismic data, however, reveal overly triangular zones, duplexes, and salt-cored anticlines bounded by steep faults. Large structural patterns vary from east-west structural patterns in the western part to north-east patterns in the eastern part of the area.

The basin consists of sedimentary structures from Late Cambrian to Holocene. Marine sequences from Miocene to Pleistocene are superimposed by 10,000-m thick alluvial sediments. Within the southern boundary of Kishore and Salt Range, rocks of Mesozoic to earlier Infra Cambrian ages are commonly exposed. In western Salt Range, Mesozoic sequence over 1,000 m thick is exposed. In eastern Salt Range, late-Cambrian rocks are exposed.

Himalayan mountain building has highly disturbed the entire northern periphery sedimentary succession between Eurasian and Indian plates since about 50 million years ago.

Petroleum system

Potential source rocks in Potwar basin are mostly Paleocene, and production primarily comes from faulted anticline traps. Identified source rocks include Wargal formation, Lockhart formation, Patala shale formation, and Khewra formation. Patala and Lockhart formations are most likely the predominant oil and gas sources in the basin. In Potwar sub-basin, source rocks are reported to be organic-rich with mature kerogen.

Reservoir rocks includes Paleogene shelf carbonates, Miocene alluvial sandstones, Jurassic and Permian continental sandstones, and alluvial and shoreface Cambrian sandstones. Oil and gas have been explored and produced from Permian Tobra, Wargal, Amb, Cambrian Khewra, Jutana, Kussak, Jurassic Dutta, Patala Shale, Khairabad, Lockhart, Nammal, Sakesar, Margalla Limestone, Chorgali, Bhadrar, and Murree formations. Discovered oilfields in Potwar are either popup structures, salt-cored anticlines, faulted anticline, or fault-block traps.

Lockhart formation tests

Paleocene Lockhart formation sediments came from 23 cuttings in Well A in the study area shown in Fig. 1. The samples were obtained in 1.8-2 m intervals. Laboratory studies include geochemical and petrological analyses. Sample details are shown in Table 1.

Organic petrographic analysis was carried out under oil immersion with plane polarized reflected light using a LEICA DM 600 M microscope and LEICA CTR6000 photometry system equipped with fluorescence illumination.

Samples were prepared for vitrinite reflectance (VR) studies by mounting crushed rock fragments in a mild setting polyester resin (Serifix) mixed with hardener. Cured samples were ground flat on a diamond lap and polished on silicon carbide paper of different grades (P4000, P2400 and P800) using water as a lubricant. Samples were polished to a high surface reflectance using fine alumina powder (0.05 µm, 0.3 µm, and 1 µm particle size).

Measurements of VR (in % Ro) were carried out under reflected white light using a 50X oil immersion objective with 1.58 reflective index at 23° C. A Ro = 0.589% reflectance sapphire glass standard was used for calibration. VR measurements at 546-nm wavelength were randomly sampled. Reported Ro is the arithmetic mean of 25 measurements per sample. VR for oil generation as the main fluid phase range from 0.6% to 1.3% Ro. Values greater than 2.0% Ro indicate dry gas generation.

To measure total organic content (TOC), core cuttings were crushed to less than 200 mesh. TOC was measured using LECO CS-125 elemental analyzers. Rock-Eval VI equipment was used for pyrolysis. Pyrolysis was performed on about 100 mg of crushed samples in a helium atmosphere, heated to 600° C. Parameters obtained by pyrolysis include:

  • S1, the volatile hydrocarbon (HC) content (mg HC/g rock).
  • S2, the remaining HC generative potential (mg HC/g rock).
  • S3, the carbon dioxide yield (mg CO2/g rock).
  • Tmax, the temperature at which the maximum rate of hydrocarbon generation occurs in a kerogen sample during pyrolysis analysis (°C.).

Other important calculated parameters include oxygen index (OI, mg CO2/g TOC) and hydrogen index (HI, mg HC/g TOC).

Results TOC, pyrolysis

Rock organic richness is represented by TOC wt. %. According to Hunt, clastic source rock should have TOC of 1.0%. Lockhart formation sediments have 2.3% mean TOC, varying between 1.13-3.35%. Overall, the majority of analyzed samples possess good to very good TOC. TOC content decreases as thermal maturity increases, and samples having high thermal maturity would have high original TOC as compared with present day TOC.

S2 is the most useful parameter generated during pyrolysis for determining hydrocarbon generative potential. A minimum of 5 mg/g is essential for good petroleum generation capacity. In Lockhart formation, S2 ranges from 3.88-7.63 mg/g. Crossplots of S2 vs. TOC indicate that Lockhart formation samples have fair to good petroleum generating potential (Figs. 3-4).

The S1/TOC migration index differentiates indigenous and migrated petroleum. Low TOC values with high S1 values show migrated petroleum. A plot of S1 vs TOC shows that all Lockhart formation samples are indigenous (Fig. 5).

Kerogen type

Kerogen types were evaluated based on HI and OI. Lockhart formation HI values range between 201-356 mg HC/g TOC. Kerogen classification came from Van Krevelen diagrams (Figs. 6-7). Analyzed sediments possess primarily mixed Type II-III and Type III kerogen, which agrees with S2 vs. TOC kerogen plots. Lockhart formation sediments can be considered both oil and gas-prone source rock with all samples containing relatively high HI values of 200-356 mg HC/g TOC.

Thermal maturity

Three maturity indicators have been used in this study: Tmax, production index (PI), and VR. Table 2 shows that VR varies between 0.65% and 0.75% Ro and Tmax varies between 434° C. and 439° C. (Table 1). Details of each sample are available in Table 2.

Oil with % Ro ranging from 0.6% to 1.3% is thermogenic which is assumed to come from marine and lacustrine source rocks. Kerogen Type I and II have Tmax ranging from 430° C. to 455° C. Type III ranges from 435° C. to 465° C.

PI can also express organic matter maturity, defined as the ratio of hydrocarbons already generated (S1) to the total amount of hydrocarbons that the organic matter can generate (S1+S2). Samples are considered immature and may have generated little to no petroleum if PI is less than 0.05. If PI varies between 0.05 and 0.10, samples are considered at the end of oil generation and may have entered wet-gas production. The capacity of kerogen to produce hydrocarbons reduces if PI reaches 1.0.

Lockhart formation sediments have PI values ranging between 0.06 and 0.27, indicating that the formation has entered peak maturity for petroleum generation. This is in good agreement with Tmax and VR data (Fig. 8). The formation has good generative capacity and may act as source rock in Potwar basin.


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Dr. Syed Bilawal Ali Shah is a visiting faculty assistant professor at Bahria University, Islamabad, Pakistan. He has an MS (2017) and PhD (2019) in petroleum geology from the University of Malaya, Malaysia. He is a member of the Geological Society of Malaysia.