Abstract
The present study details the hydrocarbon source rock geochemistry and organic petrography of the outcrop and subsurface samples of the Middle Jurassic Chiltan Formation and the Lower Cretaceous Sembar Formation from the Sann #1 well Central and Southern Indus Basin, Pakistan. The total organic carbon (TOC), Rock–Eval pyrolysis, vitrinite reflectance (Ro) % and Maceral analysis techniques were used and various geochemical plots were constructed to know the quality of source rock, type of kerogen, level of maturity and migration history of the hydrocarbons. The outcrop and Sann #1 well data on the Sembar Formation reveals poor, fair, good and very good quality of the TOC, type II–III kerogen, immature–mature organic matter and an indigenous hydrocarbon generation potential. The outcrop and Sann #1 well data on the Chiltan Formation show a poor–good quality of TOC, type II–III kerogen, immature–mature source rock quality and having an indigenous hydrocarbon generation potential. The vitrinite reflectance [Ro (%)] values and Maceral types [fluorescent amorphous organic matter, exinite, alginite and inertnite] demonstrate that maturity in both Sembar and the Chiltan formation at surface and subsurface fall in the oil and gas generation zone to cracking of oil to gas condensate zone. Recurrence of organic rich and poor intervals within the Sembar and Chiltan formation are controlled by the Late Jurassic thermal uplift preceding the Indo-Madagascar separation from the Afro-Arabian Plate and Early Cretaceous local transgressive–regressive cycles. From the current study, it is concluded that both Sembar and Chiltan formation can act as a potential hydrocarbon source rock in the study area.
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Introduction
The Indus Basin is one of the major sedimentary basins of Pakistan comprising sediments of Precambrian to recent (Fig. 1). Potential hydrocarbon source rocks occur within the Middle Jurassic Chiltan Formation and the Lower Cretaceous Sembar Formation in the Sulaiman–Kirthar fold belt of Indus Basin. Exploration of hydrocarbons in this region faces the challenging complex geology of the area that hinders detailed investigation of the petroleum system of the region. This study area is still underexplored and the advancement of petroleum exploration and production technology provides a hope for the discovery of economically viable hydrocarbon reserves. The petroleum generation, migration, and preservation potential of the strata exposed in the study area demands the integration of a detailed geological investigation at the outcrop and subsurface level. The Sembar Formation shows vertical variation in the lithofacies assemblage and very thick organic rich clays are reported in different parts of the Indus Basin. However, the available limited geochemical data from the Sann #1 well which was a wildcat exploratory well drilled in 1984 and studied by Robison et al. (1995), favor a Sembar source rock in the region. The Chiltan Formation also contains organic rich clays in the Indus Basin as reported from different outcrops (Shah 1977) and the Sann #1 well (Robison et al. 1995). This study, tries to investigate for the first time the outcrop based hydrocarbon source rock potential and comparison with the subsurface occurrence of the Middle Jurassic Chiltan and the Lower Cretaceous Sembar formation in the Mughal Kot Section and San #1 well, using bulk rock geochemical analysis and organic petrographic methods. The extrapolation of the results of outcrop data has added advantages of determining the lateral and vertical thicknesses of the potential organic shale intervals, variation in the depositional trends across the basin, quantifying the associated network of fractures for devising successful franking strategies, comparison of outcrop, core, and log observed fractures, effect of depositional processes on geomechanical properties, integration of multidisciplinary properties observed, and the effects of depositional properties on hydrocarbon migration pathways.
In-place estimates with a robust connection to geological studies are widely considered an excellent tool for initial estimates of the Shale Gas reserves. The British Geological Survey (BGS) have employed the methodology of using outcrop based geological studies, volumetrics and gas contents to study the Carboniferous Bowland Shale gas geology and resource estimation. Similarly the success of the Shale Gas is greatly influenced by the detailed outcrop based geological investigation and utilization of the subsequent geo-modeling of the Antrim Shale, Michigan, the Antrim Shale of Upper Devonian age, Barnett Shale, Caney Shale, Oklahoma Conesauga Shale, Alabama Fayetteville Shale, Arkansas, Floyd Shale, Alabama, Gothic Shale, Colorado; Haynesville Shale, Louisiana, Collingwood-Utica Shale, Michigan; New Albany Shale, Illinois Basin; Pearsall Shale, Texas; Devonian shales, Appalachian Basin; Chattanooga and Ohio Shales; Marcellus Shale; Utica Shale, New York and Ohio; Woodford Shale, Oklahoma.
The results of this study are very important in knowing the source rock quality, type of kerogen, source rock maturity, the expulsive and non-expulsive history of the source rock and indigenous vs non-indigenous hydrocarbon character both at surface and depth of the Sembar and Chiltan formation.
Stratigraphic framework
The Mughal Kot Section
The oldest rocks exposed in the Mughal Kot Section (Fig. 1) are represented by the Middle Jurassic Chiltan Formation also known as the Suleiman Limestone Group. This unit is disconformably overlain by the Cretaceous Sembar, Goru, Parh, Mughal Kot formations and Pab Sandstone (Plate 1, Figs. 1–6). A brief description of these rocks is provided in the following paragraphs.
Chiltan Formation
The Chiltan Formation consists of hard, fetid, thin to massive bedded, dark gray to blue oolitic limestone, contains some secondary calcite and chert nodules (Plate 1, Fig. 1). Blue black calcareous claystone intercalations are common in the lower part of the unit (Plate 1, Fig. 2). The lower contact is not exposed and the upper contact is disconformable with the Sembar Formation. Macrofossils of the Chiltan Formation include ostracods, algae, corals, bryozoans, brachiopods, mollusks, crinoids and foraminifers. These fossils indicate that Chiltan Formation was deposited in a shallow carbonate platform (Shah 1977).
Sembar Formation
The Sembar Formation consists of black soft shale, claystone with thin beds of nodular limestone and sandstone (Plate 1, Fig. 3) (William 1959). The lower contact is unconformable with the Chiltan Formation and the upper contact with Goru Formation is gradational. Fossils in the Sembar Formation consist of belemnites, ammonoids, foraminifers and nano-fossils. The age of Sembar Formation spans the entire Neocomian (Early Cretaceous) time and the paleoenvironmental setting are interpreted as shallow marine to open marine (Bender 1995).
Parh Limestone
The Parh Limestone is a hard, well bedded, and lithographic to porcellaneous, limestone with marl intercalations (William 1959). The unit is light gray, and cream to tan in color (Plate 1, Fig. 4). The upper contact is conformable with the overlying Mughal Kot Formation. The Parh Limestone is highly fossiliferous and yielded abundant planktonic foraminifers and nannofossils. Based on the fossil assemblage present in the unit the Parh Limestone is Turonian to Campanian (Late Cretaceous) in age. The depositional environment is interpreted as open-deep marine.
Mughal Kot Formation
The Mughal Kot Formation is comprised of dark gray calcareous mudstone with scattered intercalations of sandstone, conglomerate, and argillaceous limestone (Plate 1, Fig. 5). The sandstone is dark gray sub litharenite to litharenite that contains volcanic rock fragments. Sandstone and conglomerate inter-beds fine upward and contain typical Bouma turbidite sequence. The Formation locally contains olistostromes and pebbles of basalt. The upper contact of the formation with the Pab Sandstone is gradational. Fossils in the Mughal Kot Formation include smaller benthic and planktonic foraminifers that indicate Late Cretaceous (Campanian–Maastrichtian) age. The deposition of Mughal Kot Formation is interpreted as occurring in an outer shelf-open marine environment.
Pab Sandstone
The Pab Sandstone is a gray to brown, thick to massive bedded quartzose sandstone (Plate 1, Fig. 6) with intercalation of clays and siltstone. The upper contact with Ranikot Formation is disconformable. In the Mughal Kot Section the Pab Sandstone is devoid of fossils. However, based on the fossils recorded from other localities the Pab Sandstone is Late Cretaceous (Maastrichtian) in age (Shah 1977).
Stratigraphy of the Sann #1 well
The stratigraphic units encountered in the San 1 well includes the Eocene Laki Formation (94 m thick sequence of limestone), Ranikot Group of Paleocene age (940 m thick sequence of shale, sandstone and limestone), the Cretaceous Pab Sandstone (77 m thick sandstones), Mughal Kot and Parh Limestone (188 m thick limestone and marl), Guru Formation (1325 m thick shale and sandstone), Sembar Formation (877 m thick, shale and calcareous sandstone) and the Jurassic Chiltan Formation (314 m thick limestone and grey-black shale).
Materials and Methods
The detailed geochemical and organic petrographic investigations of the outcrop samples of Chiltan and Sembar formation were carried out at the Hydrocarbon Development Institute of Pakistan (HDIP) Labs, while the subsurface geochemical data came from the selected eighteen (18) samples of the Sann #1 well. The samples were analyzed using the TOC, Rock Eval Pyrolysis, vitrinite reflectance and Maceral analysis techniques.
The Rock–Eval parameters are calculated according to Johannes et al. (2006). The hydrocarbon source rock maturation level as a function of Production Index (PI) and Tmax for different types of kerogen (after Bacon et al. 2000) are used to construct various geochemical cross plots. These cross plots include the HI vs OI cross plot for determining the Kerogen type; the Tmax vs HI cross plot for both the kerogen type and maturation level; the GP vs TOC cross plot for the source rock quality; the Tmax vs PI cross plot for the maturation level and the S1 vs TOC cross plot for the knowing the indigenous or non-indigenous hydrocarbons generation potential of the source rock.
Based on the high TOC content, the selected samples of the Sembar and Chiltan formation were studied using the Carl Zeiss Axio Imager Z1M for the microscopic imaging of the Maceral types and vitrinite reflectance [Ro (%)] measurements at the HDIP. The analyses were carried out using the reflected white light. Relative abundance of inert and reactive constituents of organic clays was determined during this study. A polished block of rock sample is prepared and placed under the microscope to identify Maceral group in an immersion medium with the help of their reflectance, morphology and color, the quantitative composition is determined (ICCP 2001).
Results and discussion
Organic richness and source rock quality
The total organic carbon (TOC) analysis is used to measure the organic richness of a rock (Jarvie 1991). The TOC is reported in weight percent (wt%). It is useful as a qualitative measure of petroleum potential. It is important to consider that TOC decreases with increasing thermal maturity. The TOC of 0.5 wt% is widely regarded as the minimum value for defining a petroleum source rock, but most geochemists consider rocks with less than 1.0 wt% TOC as organically lean and unlikely sources for commercial hydrocarbon accumulations (Hunt 1996). The worldwide average TOC of all shale is about 0.9 wt% and the average TOC of source rock shale is 2.2 wt%. The average TOC of a calcareous shale source rock and carbonate (mudstone) source rock is 1.9 wt% and 0.7 wt%, respectively. The worldwide average TOC of all source rocks is 1.8 wt%, a value much higher than the often quoted minimum of 0.5 to 1.0 wt%. We use here a TOC of 1.0 wt% as a minimum value for defining a potential source rock.
The results of TOC analysis of the outcrop samples (Table 1) and subsurface samples from the Sann #1 well (Table 2) are presented. Based on the highest value of 2.08 TOC (%) from the outcrop samples and 5.43 TOC (%) at depth of 3680 m the Chiltan Formation is considered as a very good source rock. Similarly the outcrop samples of the Sembar Formation having the highest value of 1.54 TOC (%) and 9.48 TOC (%) at a depth of 3520 m suggest it to be a very good source rock (Bacon et al. 2000). The variations in TOC content in the samples from the Chiltan and Sembar Formation with the depths in the Sann #1 well also confirms an overall good–very good source rock potential for both formations as shown in the TOC vs Depth cross plot (Fig. 2) (Maky and Ramadan 2008).
Type of Kerogen and thermal maturity
The hydrogen index (HI) and the oxygen index (OI) are used to define the type of kerogen and approximate level of maturation (Ghori 1998). The oil prone kerogen have a high HI and low OI values while the gas prone kerogen are characterized by a low HI and high OI values (Tissot and Welte 1978). The HI vs OI cross plot (van-Krevelen 1961) show a mix of type II and III kerogen from the outcrop data (Fig. 3), while in the Sann #1 well the type II kerogen is found (Fig. 4).
To determine the maturity stage of the organic matter HI vs Tmax cross plot is used (Figs. 5, 6). The outcrop data from the Mughal Kot Section show mostly immature source rock for both Chiltan and the Sembar formation, while only one sample in the Sembar Formation reflects the mature nature (Fig. 5). The data in Sann #1 well also dominantly show an immature level for both formations (Fig. 6).
Generation potential (GP) of the source rock
The generation potential (GP) gives a qualitative estimate of hydrocarbon resource potential; however, it cannot be used to predict the type of hydrocarbons (gaseous or liquid) produced during pyrolysis (Tissot and Welte 1978).
The quality of source rock and potentiality to generate hydrocarbons in the Chiltan and Sembar formation was determined from the cross plot between the TOC content and the GP values. The outcrop data of Chiltan and Sembar formation from the Mughal Kot Section (Fig. 7) and the Sann #1 well (Fig. 8) show poor to very good source rock quality.
Hydrocarbon migration and expulsion history
The production index (PI) is often used to assess the relative thermal maturity of organic matter, and the presence of migrated hydrocarbons. The PI value for the Type I and II kerogen are > 0.1 while the Type III kerogen commonly have 0.1–0.2 range of PI values.
The production index (PI) and the Tmax cross plot suggested by Espitalli et al. (1977) is used here which shows that all samples are immature (Fig. 9). However, in the PI vs Tmax cross plot adapted from Ghori (2000) only few samples of both Chiltan and Sembar formation in the Sann #1 well are mature (Fig. 10), while only one outcrop sample of the Sembar Formation fall in the oil window (Fig. 11).
The main use of the Bitumen Index which is sometimes also called as the migration index (Hunt 1996), is to determine the depth at which a source rock begins to expel oil. By plotting the S1 and the TOC wt% values against the depth of the samples no expulsion of the hydrocarbons is inferred (Fig. 12). The S1 vs TOC wt% for the analyzed outcrop samples (Fig. 13) and Sann #1 well (Fig. 14) samples of both formations show an Indigenous source of the hydrocarbons.
Vitrinite reflectance measurements [Ro (%)] and Maceral analysis
The term vitrinite commonly refers to reflectance measurements of vitrinite Ro (%) for the reason that optical properties of vitrinite Maceral group change more consistently during the advancement of their grade as compared to those of the other Macerals. A more recent definition explains that vitrinite is a group of Macerals with distinct optical and chemical properties varying with relative effect of temperature and/or time. The vitrinite reflectance [Ro (%)] measurements are commonly used for determining the maturity of rocks. The maturity levels based on vitrinite reflectance [Ro (%)] and Tmax (C) and the occurrence different Maceral types, i.e., fluorescent amorphous organic matter (OM), exinite and alginite (Tables 3, 4) demonstrate that source rock maturity in both Sembar and Chiltan formation falls in the oil and gas generation zone to cracking of oil to gas condensate zone.
The organic rich and organic poor rock intervals within the outcrop and subsurface samples were frequently recorded. These may be controlled by the tectonics and associated sea level perturbations recorded in the form of shallowing-deepening cycles. The deepening and shallowing of facies within the Chiltan Formation was attributed to the Middle–Late Jurassic development of the rift basin and associated thermal uplift in response to the separation of the Indo-Madagascar from the Afro-Arabia. The renewed phase of marine clastic sedimentation is related to the Early Cretaceous sea level rise and local deepening of the basin in response to the local tectonics in the study area. This has resulted in the deposition of shallow-deep cycles of deposition, preserving the organic rich-organic poor intervals within the Sembar Formation.
Summary and conclusions
The detailed geochemical and petrographic analysis of the outcrop data from the Chiltan and Sembar formation exposed in the Mughal Kot Section and the subsurface well cuttings data from the Sann #1 well elucidate and summarizes the significance of hydrocarbon source rock potential in the study area.
In the Mughal Kot Section, the upper part of the Chiltan Formation (outcrop samples 1–2), the source rock quality range from poor to fair, type II Kerogen is recognized and the organic matter is immature. The upper part also indicate indigenous hydrocarbon occurrence which is supported by S1 vs TOC cross plot. In the middle part of the Chiltan Formation (outcrop samples 3–4), the source rock quality ranges from very good to good. Type II Kerogen is recognized and the source rock is immature and indigenous hydrocarbon occurrence is suggested. In the lower part (outcrop samples 5–6), the source rock quality range from poor to good while Type II and type III kerogen, immature source rock and indigenous hydrocarbon occurrence are noted.
In the Sann #1 well, the upper part of the Chiltan Formation (represented by well samples 8, 9, 10, 11), the source rock quality range from fair to good and Type II–III Kerogen are recognized. The hydrocarbon potentially is fair to poor. The organic matter is immature–mature, did not expel any hydrocarbons. The middle part of the Chiltan Formation (represented by the well samples 12, 13, 14, 15) the source rock quality range from very good to good. Kerogen is type II except for sample 13 which is type III. The Hydrocarbon potentiality is good–poor. The organic matter is immature, however, the maturity level indicated by depth vs PI cross plot suggests that the organic matter is mature. The middle part of the Chiltan Formation shows no expulsion of hydrocarbon and indigenous hydrocarbon occurrence is suggested. In the lower part of the Chiltan Formation (represented by the well samples 16, 17, 18) the source rock quality is very good except in the lowermost part which is good. Kerogen recognized is type II. The organic matter is immature, however, the well sample 17 is mature and fall in zone of oil window.
In the Mughal Kot Section, the upper part of Sembar Formation is represented by the outcrop samples 1–7, the source rock quality is fair and Type III Kerogen is recognized. The Organic Matter is mature, and indigenous hydrocarbon occurrence is noted. In the middle part (outcrop samples 8 and 9), the source rock quality is poor. Type III Kerogen is recognized, the maturity plots indicate immature level and an indigenous hydrocarbon occurrence is suggested. In the lower part of the Sembar (outcrop sample 10), the source rock quality is fair, Type II Kerogen is recognized, the organic matter is mature, having an indigenous hydrocarbon occurrence.
In the Sann #1 well, the upper part of Sembar Formation (well sample 1 and 2) the source rock quality is very good and type II Kerogen is recognized. The organic matter fall in the immature–mature nature of the source rock, no expulsion of hydrocarbon and an indigenous hydrocarbon occurrence is noted. In the middle part represented by well samples 3 and 4, the source rock quality is very good and type II Kerogen is recognized. The organic matter is of immature nature except for the Tmax vs PI cross plot that indicate oil window for the well sample 4. In the middle part non-expulsion and indigenous hydrocarbon occurrence is noted. The lower part of the Sembar Formation is represented by well samples 5 and 6, the geochemical parameters are similar to the middle part except the quality of the source rock degrades from very good to good.
The Vitrinite Reflectance [Ro (%)] values of the outcrop samples from the Sembar Formation range from 0.6 to 0.93, and range 0.6–0.88 in the samples of Sann #1 well. Similarly the Vitrinite Reflectance [Ro (%)] values of the outcrop samples of the Chiltan Formation range 0.9–1.1 and range 0.7–1.5 in the samples of Sann #1 well. The different Maceral types, i.e., fluorescent amorphous organic matter (OM), exinite, alginite and inertinite are recorded in the outcrop and Sann #1 well samples. The surface and subsurface Maceral data suggest that both Sembar and Chiltan Formation fall in the oil and gas generation zone to cracking of oil to gas condensate zone.
Based on the current investigations it is concluded that sufficient vertical thickness of organic rich facies, their lateral continuity, High TOC content, appropriate Kerogen type, thermal maturity reflecting oil–gas generation zone to cracking of oil to gas condensate zone, and indigenous hydrocarbon exists in the Chiltan and Sembar formation.
Change history
22 March 2019
In the original publication, one of the co-author Khalid Latif’s name and affiliation were incorrectly published. The correct name and affiliation are given below.
22 March 2019
In the original publication, one of the co-author Khalid Latif���s name and affiliation were incorrectly published. The correct name and affiliation are given below.
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Ahmad, S., Ahmad, F., Ullah, A. et al. Integration of the outcrop and subsurface geochemical data: implications for the hydrocarbon source rock evaluation in the Lower Indus Basin, Pakistan. J Petrol Explor Prod Technol 9, 937–951 (2019). https://doi.org/10.1007/s13202-018-0569-6
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DOI: https://doi.org/10.1007/s13202-018-0569-6