Search results for: Kerogen

Authors: Anton G. Kalmykov, Andrew Yu. Bychkov, Georgy A. Kalmykov

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Nowadays, most oil reserves in Russia and all over the world are hard to recover. That is the reason oil companies are searching for new sources for hydrocarbon production. One of the sources might be high-carbon formations with unconventional reservoirs. Bazhenov formation is a huge source rock formation located in West Siberia, which contains unconventional reservoirs on some of the areas. These reservoirs are formed by secondary processes with low predicting ratio. Only one of five wells is drilled through unconventional reservoirs, in others kerogen has low thermal maturity, and they are of low petroliferous. Therefore, there was a request for tertiary methods for in-situ cracking of kerogen and production of oil. Laboratory experiments of Bazhenov formation rock hydrous pyrolysis were used to investigate features of the oil generation process. Experiments on Bazhenov rocks with a different mineral composition (silica concentration from 15 to 90 wt.%, clays – 5-50 wt.%, carbonates – 0-30 wt.%, kerogen – 1-25 wt.%) and thermal maturity (from immature to late oil window kerogen) were performed in a retort under reservoir conditions. Rock samples of 50 g weight were placed in retort, covered with water and heated to the different temperature varied from 250 to 400°C with the durability of the experiments from several hours to one week. After the experiments, the retort was cooled to room temperature; generated hydrocarbons were extracted with hexane, then separated from the solvent and weighted. The molecular composition of this synthesized oil was then investigated via GC-MS chromatography Characteristics of rock samples after the heating was measured via the Rock-Eval method. It was found, that the amount of synthesized oil and its composition depending on the experimental conditions and composition of rocks. The highest amount of oil was produced at a temperature of 350°C after 12 hours of heating and was up to 12 wt.% of initial organic matter content in the rocks. At the higher temperatures and within longer heating time secondary cracking of generated hydrocarbons occurs, the mass of produced oil is lowering, and the composition contains more hydrocarbons that need to be recovered by catalytical processes. If the temperature is lower than 300°C, the amount of produced oil is too low for the process to be economically effective. It was also found that silica and clay minerals work as catalysts. Selection of heating conditions allows producing synthesized oil with specified composition. Kerogen investigations after heating have shown that thermal maturity increases, but the yield is only up to 35% of the maximum amount of synthetic oil. This yield is the result of gaseous hydrocarbons formation due to secondary cracking and aromatization and coaling of kerogen. Future investigations will allow the increase in the yield of synthetic oil. The results are in a good agreement with theoretical data on kerogen maturation during oil production. Evaluated trends could be tooled up for in-situ oil generation by shale rocks thermal action.

Keywords: Bazhenov formation, fossil fuels, hydropyrolysis, synthetic oil

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Authors: Temitope L. Baiyegunhi, Kuiwu Liu, Oswald Gwavava, Christopher Baiyegunhi

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Shale gas has recently been the exploration focus for future energy resource in South Africa. Specifically, the black shales of the lower Ecca Group in the study area are considered to be one of the most prospective targets for shale gas exploration. Evaluation of this potential resource has been restricted due to the lack of exploration and scarcity of existing drill core data. Thus, only limited previous geochemical data exist for these formations. In this study, outcrop and core samples of the Ecca Group were analysed to assess their total organic carbon (TOC), organic matter type, thermal maturity and hydrocarbon generation potential (SP). The results show that these rocks have TOC ranging from 0.11 to 7.35 wt.%. The SP values vary from 0.09 to 0.53 mg HC/g, suggesting poor hydrocarbon generative potential. The plot of S1 versus TOC shows that the source rocks were characterized by autochthonous hydrocarbons. S2/S3 values range between 0.40 and 7.5, indicating Type- II/III, III, and IV kerogen. With the exception of one sample from the collingham formation which has HI value of 53 mg HC/g TOC, all other samples have HI values of less than 50 mg HC/g TOC, thus suggesting Type-IV kerogen, which is mostly derived from reworked organic matter (mainly dead carbon) with little or no potential for hydrocarbon generation. Tmax values range from 318 to 601℃, indicating immature to over-maturity of hydrocarbon. The vitrinite reflectance values range from 2.22 to 3.93%, indicating over-maturity of the kerogen. Binary plots of HI against OI and HI versus Tmax show that the shales are of Type II and mixed Type II-III kerogen, which are capable of generating both natural gas and minor oil at suitable burial depth. Based on the geochemical data, it can be inferred that the source rocks are immature to over-matured variable from localities and have potential of producing wet to dry gas at present-stage. Generally, the Whitehill formation of the Ecca Group is comparable to the Marcellus and Barnett Shales. This further supports the assumption that the Whitehill Formation has a high probability of being a profitable shale gas play, but only when explored in dolerite-free area and away from the Cape Fold Belt.

Keywords: source rock, organic matter type, thermal maturity, hydrocarbon generation potential, Ecca Group

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Authors: Mohamed Ibrahim, Suzan Kholeif

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The Cenomanian-Turonian boundary was a ‘greenhouse’ period. The atmosphere at that time was characterized by high CO₂; in addition, there was the widespread deposition of organic-rich sediments anomalously rich in organic carbon. The sediments, palynological, total organic carbon (TOC), stable carbon and oxygen isotopes (δ¹³C, δ¹⁸O, organic) of the Cenomanian-Turonian Bahariya and basal Abu Roash formations at the southern Tethys margin were studied in two deep wells (AG5 and AG-13), Abu Gharadig Oil Field, North Western Desert, Egypt. Some of the marine (dinoflagellate cysts), as well as the terrestrial palynoflora (spores and pollen grains), reveal extinction and origination patterns that are known elsewhere, although other species may be survived across the Cenomanian-Turonian boundary. This implies control of global changes on the palynoflora, i.e., impact of Oceanic Anoxic Event OAE2 (Bonarelli Event), rather than changes in the local environmental conditions. The basal part of the Abu Roach Formation ('G' and 'F' members, late Cenomanian) shows a positive δ ¹³C excursion of the organic fraction. The TOC is generally high between 2.20 and 3.04 % in the basal Abu Roash Formation: shale of 'G' and carbonate of 'F' members, which indicates that these two members are the main Cretaceous source rocks in the Abu Gharadig Basin and have a type I-II kerogen composition. They are distinguished by an abundance of amorphous organic matter AOM and Chlorococcalean algae, mainly Pediastrum and Scenedesmus, along with subordinate dinoflagellate cysts.

Keywords: oceanic anoxic event, cenomanian-turonian, palynofacies, western desert, Egypt

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Authors: Dhruvit S. Berawala, Jann R. Ursin, Obrad Slijepcevic

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Shale gas is one of the most rapidly growing forms of natural gas. Unconventional natural gas deposits are difficult to characterize overall, but in general are often lower in resource concentration and dispersed over large areas. Moreover, gas is densely packed into the matrix through adsorption which accounts for large volume of gas reserves. Gas production from tight shale deposits are made possible by extensive and deep well fracturing which contacts large fractions of the formation. The conventional reservoir modelling and production forecasting methods, which rely on fluid-flow processes dominated by viscous forces, have proved to be very pessimistic and inaccurate. This paper presents a new approach to forecast shale gas production by detailed modeling of gas desorption, diffusion and non-linear flow mechanisms in combination with statistical representation of these processes. The representation of the model involves a cube as a porous media where free gas is present and a sphere (SiC: Sphere in Cube model) inside it where gas is adsorbed on to the kerogen or organic matter. Further, the sphere is considered consisting of many layers of adsorbed gas in an onion-like structure. With pressure decline, the gas desorbs first from the outer most layer of sphere causing decrease in its molecular concentration. The new available surface area and change in concentration triggers the diffusion of gas from kerogen. The process continues until all the gas present internally diffuses out of the kerogen, gets adsorbs onto available surface area and then desorbs into the nanopores and micro-fractures in the cube. Each SiC idealizes a gas pathway and is characterized by sphere diameter and length of the cube. The diameter allows to model gas storage, diffusion and desorption; the cube length takes into account the pathway for flow in nanopores and micro-fractures. Many of these representative but general cells of the reservoir are put together and linked to a well or hydraulic fracture. The paper quantitatively describes these processes as well as clarifies the geological conditions under which a successful shale gas production could be expected. A numerical model has been derived which is then compiled on FORTRAN to develop a simulator for the production of shale gas by considering the spheres as a source term in each of the grid blocks. By applying SiC to field data, we demonstrate that the model provides an effective way to quickly access gas production rates from shale formations. We also examine the effect of model input properties on gas production.

Keywords: adsorption, diffusion, non-linear flow, shale gas production

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Authors: K. S. Rao, Ankesh Kumar

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The search for alternative energy sources to petroleum has increased these days because of increase in need and depletion of petroleum reserves. Therefore the importance of oil shales as an economically viable substitute has increased many folds in last 20 years. The technologies like hydro-fracturing have opened the field of oil extraction from these unconventional rocks. Oil shale is a compact laminated rock of sedimentary origin containing organic matter known as kerogen which yields oil when distilled. Oil shales are formed from the contemporaneous deposition of fine grained mineral debris and organic degradation products derived from the breakdown of biota. Conditions required for the formation of oil shales include abundant organic productivity, early development of anaerobic conditions, and a lack of destructive organisms. These rocks are not gown through the high temperature and high pressure conditions in Mother Nature. The most common approach for oil extraction is drastically breaking the bond of the organics which involves retorting process. The two approaches for retorting are surface retorting and in-situ processing. The most environmental friendly approach for extraction is In-situ processing. The three steps involved in this process are fracturing, injection to achieve communication, and fluid migration at the underground location. Upon heating (retorting) oil shale at temperatures in the range of 300 to 400°C, the kerogen decomposes into oil, gas and residual carbon in a process referred to as pyrolysis. Therefore it is very important to understand the physico-mechenical behavior of such rocks, to improve the technology for in-situ extraction. It is clear from the past research and the physical observations that these rocks will behave as an anisotropic rock so it is very important to understand the mechanical behavior under high pressure at different orientation angles for the economical use of these resources. By knowing the engineering behavior under above conditions will allow us to simulate the deep ground retorting conditions numerically and experimentally. Many researchers have investigate the effect of organic content on the engineering behavior of oil shale but the coupled effect of organic and inorganic matrix is yet to be analyzed. The favourable characteristics of Assam coal for conversion to liquid fuels have been known for a long time. Studies have indicated that these coals and carbonaceous shale constitute the principal source rocks that have generated the hydrocarbons produced from the region. Rock cores of the representative samples are collected by performing on site drilling, as coring in laboratory is very difficult due to its highly anisotropic nature. Different tests are performed to understand the petrology of these samples, further the chemical analyses are also done to exactly quantify the organic content in these rocks. The mechanical properties of these rocks are investigated by considering different anisotropic angles. Now the results obtained from petrology and chemical analysis are correlated with the mechanical properties. These properties and correlations will further help in increasing the producibility of these rocks. It is well established that the organic content is negatively correlated to tensile strength, compressive strength and modulus of elasticity.

Keywords: oil shale, producibility, hydro-fracturing, kerogen, petrology, mechanical behavior

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Authors: M. Dieb, T. Hodairi

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In the Southwest Libya area, the Palaeozoic deposits are an important petroleum system, with Silurian shale considered a hydrocarbon source rock and Cambro-Ordovician recognized as a good reservoir. The Palaeozoic petroleum system has the greatest potential for conventional and is thought to represent the significant prospect of unconventional petroleum resources in Southwest Libya. Until now, the lateral and vertical heterogeneity of the source rock was not well evaluated, and oil-source correlation is still a matter of debate. One source rock, which is considered the main source potential in Marzuq Basin, was investigated for its uranium contents using gamma-ray logs, rock-eval pyrolysis, and organic petrography for their bulk kinetic characteristics to determine the petroleum potential qualitatively and quantitatively. Thirty source rock samples and fifteen oil samples from the Tannezzuft source rock were analyzed by Rock-Eval Pyrolysis, microscopely investigation, GC, and GC-MS to detect acyclic isoprenoids and aliphatic, aromatic, and NSO biomarkers. Geochemistry tools were applied to screen source and age-significant biomarkers to high-spot genetic relationships. A grating heterogeneity exists among source rock zones from different levels of depth with varying uranium contents according to gamma-ray logs, rock-eval pyrolysis results, and kinetic features. The uranium-rich Tannezzuft Formations (Hot Shales) produce oils and oil-to-gas hydrocarbons based on their richness, kerogen type, and thermal maturity. Biomarker results such as C₂₇, C₂₈, and C₂₉ steranes concentrations and C₂₄ tetracyclic terpane/C₂₉ tricyclic terpane ratios, with sterane and hopane ratios, are considered the most promising biomarker information in differentiating within the Silurian Shale Tannezzuft Formation and in correlating with its expelled oils. The Tannezzuft Hot Shale is considered the main source rock for oil and gas accumulations in the Cambro-Ordovician reservoirs within the Marzuq Basin. Migration of the generated and expelled oil and gas from the Tannezzuft source rock to the reservoirs of the Cambro-Ordovician petroleum system was interpreted to have occurred along vertical and lateral pathways along the faults in the Palaeozoic Strata. The Upper Tannezzuft Formation (cold shale) is considered the primary seal in the Marzuq Basin.

Keywords: heterogeneity, hot shale, kerogen, Silurian, uranium

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Authors: Margarita S. Tikhonova, Alireza Baniasad, Anton G. Kalmykov, Georgy A. Kalmykov, Ralf Littke

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There is a high complexity in the pore structure of organic-rich rocks caused by the combination of inter-particle porosity from inorganic mineral matter and ultrafine intra-particle porosity from both organic matter and clay minerals. Fluids are retained in that pore space, but there are major uncertainties in how and where the fluids are stored and to what extent they are accessible or trapped in 'closed' pores. A large degree of tortuosity may lead to fractionation of organic matter so that the lighter and flexible compounds would diffuse to the reservoir whereas more complicated compounds may be locked in place. Additionally, parts of hydrocarbons could be bound to solid organic matter –kerogen– and mineral matrix during expulsion and migration. Larger compounds can occupy thin channels so that clogging or oil and gas entrapment will occur. Sequential extraction of applying different solvents is a powerful tool to provide more information about the characteristics of trapped organic matter distribution. The Upper Jurassic – Lower Cretaceous Bazhenov shale is one of the most petroliferous source rock extended in West Siberia, Russia. Concerning the variable mineral composition, pore space distribution and thermal maturation, there are high uncertainties in distribution and composition of organic matter in this formation. In order to address this issue geological and geochemical properties of 30 samples including mineral composition (XRD and XRF), structure and texture (thin-section microscopy), organic matter contents, type and thermal maturity (Rock-Eval) as well as molecular composition (GC-FID and GC-MS) of different extracted materials during sequential extraction were considered. Sequential extraction was performed by a Soxhlet apparatus using different solvents, i.e., n-hexane, chloroform and ethanol-benzene (1:1 v:v) first on core plugs and later on pulverized materials. The results indicate that the studied samples are mainly composed of type II kerogen with TOC contents varied from 5 to 25%. The thermal maturity ranged from immature to late oil window. Whereas clay contents decreased with increasing maturity, the amount of silica increased in the studied samples. According to molecular geochemistry, stored hydrocarbons in open and closed pore space reveal different geochemical fingerprints. The results improve our understanding of hydrocarbon expulsion and migration in the organic-rich Bazhenov shale and therefore better estimation of hydrocarbon potential for this formation.

Keywords: Bazhenov formation, bitumen, molecular geochemistry, sequential extraction

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Authors: Ahmed M. Al-Mutarreb, Shiferaw R. Jufar

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Global shale gas resource assessment is still in its preliminary stage in most of the countries including the development of shale gas reservoirs in Malaysia. This project presents the main geochemical and mineral characteristics of few Malaysian’s shale samples which contribute on evaluating shale gas reserve world resource evaluations. Three shale samples from the western part of Peninsular Malaysia (Batu-Caja, Kuala Lumpur, and Johor Baru shale formations) were collected for this study. Total organic carbon wt.%, thermal maturity, kerogen type, mineralogy and adsorption/desorption characteristics are measured at Universiti Teknologi PETRONAS laboratories. Two samples show good potential in TOC results exhibited > 2wt.% exceeding the minimum values of Shale gas potential, while the third revealed < 1.5wt. Mineralogical compositions for the three samples are within the acceptable range percentage% of quartz and clays compared to shale plays in USA. This research’s results are promising and recommend to continue exploring and assessing unconventional shale gas reserves values in these areas.

Keywords: shale gas characterizations, geochemical properties, Malaysia, shale gas reserve

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Authors: M. Ben Jrad, A. Belhaj Mohamed, S. Riahi, I. Bouazizi, M. Saidi, M. Soussi

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The generative potential, depositional environment, thermal maturity and oil seeps of the organic-rich Bou Dabbous Formation (Ypresian) from the thrust belt northwestern Tunisia, were determined by Rock Eval and molecular analyses. The paleo-tectonic units in the area show some similarities with equivalent facies in Mediterranean Sea and Sicilian. The Bou Dabbous Formation displays variable source rock characteristics through the various units Tellian and Numidian nappes Units. Organic matter contents and petroleum potentials are fair to high (reaching 1.95% and 6 kg of HC/t of rock respectively) marine type II kerogen. An increasing SE-NW maturity gradient is well documented in the study area. The Bou Dabbous organic-rich facies are marginally mature stage in the Tellian Unit (Kasseb domain), whilst they are mature-late mature stage within Nefza-Ain Allega tectonic windows. A long and north of Cap Serrat-Ghardimaou Master Fault these facies are overmature. Oil/Oil and Oil/source rock correlation, based on biomarker and carbon isotopic composition, shows a positive genetic correlation between the oil seeps and Bou Dabbous source rock.

Keywords: biomarkers, Bou Dabbous Formation, Northern Tunisia, source rock

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Authors: Lauti Dwita Santy, Hermes Panggabean, Syahrir Andi Mangga

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The Bengkulu Basin is part of the Sunda Arc system, which is a classic convergent type margin that occur around the southern rim of the Eurasian continental (Sundaland) plate. The basin is located between deep sea trench (Mentawai Outer Arc high) and the volvanic/ magmatic Arc of the Barisan Mountains Range. To the northwest it is bounded by Padang High, to the northest by Barisan Mountains (Sumatra Fault Zone) to the southwest by Mentawai Fault Zone and to the southeast by Semangko High/ Sunda Strait. The stratigraphic succession and tectonic development can be broadly divided into four stage/ periods, i.e Late Jurassic- Early Cretaceous, Late Eocene-Early Oligocene, Late Oligocene-Early Miocene, Middle Miocene-Late Miocene and Pliocene-Plistocene, which are mainly controlled by the development of subduction activities. The Pre Tertiary Basement consist of sedimentary and shallow water limestone, calcareous mudstone, cherts and tholeiitic volcanic rocks, with Late Jurassic to Early Cretaceous in age. The sedimentation in this basin is depend on the relief of the Pre Tertiary Basement (Woyla Terrane) and occured into two stages, i.e. transgressive stage during the Latest Oligocene-Early Middle Miocene Seblat Formation, and the regressive stage during the Latest Middle Miocene-Pleistocene (Lemau, Simpangaur and Bintunan Formations). The Pre-Tertiary Faults were more intensive than the overlying cover, The Tertiary Rocks. There are two main fault trends can be distinguished, Northwest–Southwest Faults and Northeast-Southwest Faults. The NW-SE fault (Ketaun) are commonly laterally persistent, are interpreted to the part of Sumatran Fault Systems. They commonly form the boundaries to the Pre Tertiary basement highs and therefore are one of the faults elements controlling the geometry and development of the Tertiary sedimentary basins.The Northeast-Southwest faults was formed a conjugate set to the Northwest–Southeast Faults. In the earliest Tertiary and reactivated during the Plio-Pleistocene in a compressive mode with subsequent dextral displacement. The Block Faulting accross these two sets of faults related to approximate North–South compression in Paleogene time and produced a series of elongate basins separated by basement highs in the backarc and forearc region. The Bengkulu basin is interpreted having evolved from pull apart feature in the area southwest of the main Sumatra Fault System related to NW-SE trending in dextral shear.Based on Pyrolysis Yield (PY) vs Total Organic Carbon (TOC) diagram show that Seblat and Lemau Formation belongs to oil and Gas Prone with the quality of the source rocks includes into excellent and good (Lemau Formation), Fair and Poor (Seblat Formation). The fine-grained carbonaceous sediment of the Seblat dan Lemau Formations as source rocks, the coarse grained and carbonate sediments of the Seblat and Lemau Formations as reservoir rocks, claystone bed in Seblat and Lemau Formation as caprock. The source rocks maturation are late immature to early mature, with kerogen type II and III (Seblat Formation), and late immature to post mature with kerogen type I and III (Lemau Formation). The burial history show to 2500 m in depthh with paleo temperature reached 80oC. Trapping mechanism occur during Oligo–Miocene and Middle Miocene, mainly in block faulting system.

Keywords: fore arc, bengkulu, sumatra, sundaland, hydrocarbon, trapping mechanism

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Authors: Syed Bilawal Ali Shah

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The investigation of the hydrocarbon source rock potential of Eocene-Paleocene formations of Potwar Basin, part of Upper Indus Basin Pakistan, was done using geochemical and petrological techniques. Analysis was performed on forty-five core-cutting samples from two wells. The sequences analysed are Sakesar, Lockhart and Patala formations of Potwar Basin. Patala Formation is one of Potwar Basin's major petroleum-bearing source rocks. The Lockhart Formation samples VR (%Ro) and Tmax data indicate that the formation is early mature to immature for petroleum generation for hydrocarbon generation; samples from the Patala and Sakesar formations, however, have a peak oil generation window and an early maturity (oil window). With 3.37 weight percent mean TOC and HI levels up to 498 mg HC/g TOC, the source rock characteristics of the Sakesar and Patala formations generally exhibit good to very strong petroleum generative potential. The majority of sediments representing Lockhart Formation have 1.5 wt.% mean TOC having fair to good potential with HI values ranging between 203-498 mg HC/g TOC. 1. The analysed sediments of all formations possess primarily mixed Type II/III and Type III kerogen. Analysed sediments indicate that both the Sakesar and Patala formations can possess good oil-generation potential and may act as an oil source rock in the Potwar Basin.

Keywords: Potwar Basin, Patala Shale, Rock-Eval pyrolysis, Indus Basin, VR %Ro

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Authors: Anis Belhaj Mohamed, Moncef Saidi, Mohamed Soussi, Ibrahim Bouazizi, Monia Ben Jrad

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This paper summarizes the results of Rock-Eval pyrolysis and biomarker data of shale samples collected from the Ordovician age (Llanvirnian-Llandeilian) (Azzel Formation) in the Chotts basin southern part of Tunisia. The results are supported by analysis of cutting samples from wells. The Azzel shales has poor to moderate, occasionally good, potential for sourcing oil and gas with Total Organic Carbon (TOC) content varying from 0.80 to 4.49 % and petroleum potential (PP) values varying between 0.68 to 9.20 Kg of HC/t rock in Baguel and Alaguia wells. However, the Azzel Formation show poor to fair TOC and PP in Elfranig and HajBrahim wells not exceeding 1.10% and 1.05 kg HC/t of rock respectively. The Hydrogen Index (HI) and the Oxygen Index (OI) values of 95–165 mg S2/g TOC and of 33–108 mg CO2/g rock relatively show that the Ordovician shales exhibit type II Kerogen that reached the main oil window stage and that the organic matter was bad preserved, Tmax values of 435 – 448°C indicate the organic matter is mature. The biomarker features of the extract samples are characterized by high proportion of tricyclic terpanes that are dominated by C23 and C21 tricyclic terpanes. The hopanes fraction is dominated by C29 and C30 hopanes. The Ordovician shales show a predominance of C27 over C29 steranes (C27/C29>1) and relatively high proportions of diasteranes supporting the shaly character of the source rock.

Keywords: biomarkers, organic geochemistry, ordovician source rock, diasteranes

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Authors: S. Mahmoudi, A. Belhaj Mohamed, M. Saidi, F. Rezgui

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Depositional environment and source potential of the different organic rich levels of Devonian age (up to 990m thick) from the onshore EC-1 well (Southern Tunisia) were investigated using different geochemical techniques (Rock-Eval pyrolysis, GC-MS) of over than 130 cutting samples. The obtained results including Rock Eval Pyrolysis data and biomarker distribution (terpanes, steranes and aromatics) have been used to describe the depositional environment and to assess the thermal maturity of the Devonian organic matter. These results show that the Emsian deposits exhibit poor to fair TOC contents. The associated organic matter is composed of mixed kerogen (type II/III), as indicated by the predominance of C29 steranes over C27 and C28 homologous, that was deposited in a slightly reduced environment favoring organic matter preservation. Thermal maturity assessed from Tmax, TNR and MPI-1 values shows a mature stage of organic matter. The Middle Devonian (Eifelian) shales are rich in type II organic matter that was deposited in an open marine depositional environment. The TOC values are high and vary between 2 and 7 % indicating good to excellent source rock. The relatively high IH values (reaching 547 mg HC/g TOC) and the low values of t19/t23 ratio (down to 0.2) confirm the marine origin of the organic matter (type II). During the Upper Devonian, the organic matter was deposited under variable redox conditions, oxic to suboxic which is clearly indicated by the low C35/C34 hopanes ratio, immature to marginally mature with the vitrinite reflectance ranging from 0.5 to 0.7 Ro and Tmax value of 426°C-436 °C and the TOC values range between 0.8% to 4%.

Keywords: biomarker, depositional environment, devonian, source rock

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Authors: Vaishali Sharma, Anirbid Sircar

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Energy is one of the most eminent and fundamental strategic commodity, scarcity of which may poses great impact on the functioning of the entire commodity. According to the present study, the estimated reserves of gas in India as on 31.03.2015 stood at 1427.15 BCM. It is expected that the gas demand is set to grow significantly at a CAGR of 7% from 226.7 MMSCMD in 2012-13 to 713.5 MMSCMD in 2009-30. To bridge the gap between the demand and supply of energy, the interest towards the exploration and exploitation of unconventional resources like – Shale gas, Coal bed methane, Gas hydrates, tight gas etc has immensed. Nowadays, Shale gas prospects are emerging rapidly as a promising energy source globally. The United States of America (USA) has 240 TCF of proved reserves of shale gas and presently contributed more than 17% of total gas production. As compared to USA, shale gas production in India is at nascent stage. A resource potential of around 2000 TCF is estimated and according to preliminary data analysis, basins like Gondwana, Cambay, Krishna – Godavari, Cauvery, Assam-Arakan, Rajasthan, Vindhyan, and Bengal are the most promising shale gas basins. In the present study, the careful evaluation of Cambay Shale (Indian Shale) properties like geological age, lithology, depth, organically rich thickness, TOC, thermal maturity, porosity, permeability, clay content, quartz content, Kerogen type, Hydrocarbon window etc. has been done. And then the detailed comparison of Indian shale with USA shale will be discussed. This study investigates qualitative and quantitative nature of potential shale basins which will be helpful from exploration and exploitation point of view.

Keywords: shale, shale gas, energy source, lithology

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Authors: Morteza Taherinezhad, Ahmad Reza Rabbani, Morteza Asemani, Rudy Swennen

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Oil-oil correlation is one of the most important issues in geochemical studies that enables to classify oils genetically. Oil-oil correlation is generally estimated based on non-polar fractions of crude oil (e.g., saturate and aromatic compounds). Despite several advantages, the drawback of using these compounds is their susceptibility of being affected by secondary processes. The polar fraction of crude oil (e.g., asphaltenes) has similar characteristics to kerogen, and this structural similarity is preserved during migration, thermal maturation, biodegradation, and water washing. Therefore, these structural characteristics can be considered as a useful correlation parameter, and it can be concluded that asphaltenes from different reservoirs with the same genetic signatures have a similar origin. Hence in this contribution, an integrated study by using both non-polar and polar fractions of oil was performed to use the merits of both fractions. Therefore, five oil samples from oil fields in the Persian Gulf were studied. Structural characteristics of extracted asphaltenes were investigated by Fourier transform infrared (FTIR) spectroscopy. Graphs based on aliphatic and aromatic compounds (predominant compounds in asphaltenes structure) and sulphoxide and carbonyl functional groups (which are representatives of sulphur and oxygen abundance in asphaltenes) were used for comparison of asphaltenes structures in different samples. Non-polar fractions were analyzed by GC-MS. The study of asphaltenes showed the studied oil samples comprise two oil families with distinct genetic characteristics. The first oil family consists of Salman and Reshadat oil samples, and the second oil family consists of Resalat, Siri E, and Siri D oil samples. To validate our results, biomarker parameters were employed, and this approach completely confirmed previous results. Based on biomarker analyses, both oil families have a marine source rock, whereby marl and carbonate source rocks are the source rock for the first and the second oil family, respectively.

Keywords: biomarker, non-polar fraction, oil-oil correlation, petroleum geochemistry, polar fraction

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Authors: Syed Mamoon Siyar, Fayaz Ali, Sajjad Ahmad, Samina Jahandad, George Kontakiotis, Hammad T. Janjuhah, Assimina Antonarakou, Waqas Naseem

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The Cretaceous Chichali Formation in the Chanda-01, Chanda-02, Chanda-03 and Mela-05 wells and the oil samples from Chanda-01 and Chanda-01 wells located in the Kohat Basin, Pakistan, were analyzed with the objectives of evaluating the hydrocarbon generation potential, source, thermal maturity and depositional of organic matter, and oil-source correlation by employing geochemical screening techniques and biomarker studies. The total organic carbon (TOC) values in Chanda-02, Chanda-03 and Mela-05 indicate, in general, poor to fair, fair and fair to good source rock potential with low genetic potential, respectively. The nature of organic matter has been determined by standard cross plots of Rock Eval pyrolysis parameters, indicating that studied cuttings from the Chichali Formation dominantly contain type III kerogen at present and show maturity for oil generation in the studied wells. The organic petrographic study also confirmed the vitrinite (type III) as a major maceral in the investigated Chichali Shales and its reflectance values show maturity for oil. The different ratios of non-biomarkers and biomarkers i.e., steranes, terpenes and aromatics parameters, indicate the marine source of organic matter deposited in the anoxic environment for the Chichali Formation in Chanda-01 and Chanda-02 wells and mixed source input of organic matter deposited in suboxic conditions for oil in the same wells. The CPI, and different biomarkers parameters such as C29 S/S+R, ββ/αα+ββ), M29/H30, Ts/Ts+Tm, H31 (S/S+R) and aromatic compounds methyl phenanthrene index (MPI) and organic petrographic analysis (vitrinite reflectance) suggest mature stage of oil generation for Chichali Shales and oil samples in the study area with little high thermal maturity in case of oils. Based on source and thermal maturity biomarkers and non-biomarkers parameters, the produced oils have no correlation with the Cretaceous Chichali Formation in the studied Chanda-01 and Chanda-02 wells in Kohat Basin, Pakistan, but it has been suggested that these oils have been generated by the strata containing high terrestrial organic input compare to Chichali Shales.

Keywords: Organic geochemistry, Chichali Shales and crude oils, Kohat Basin, Pakistan

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Authors: Sayani Chatterjee, Kusum Lata Pangtey, Sarita Singh, Harvir Singh

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Biodegradation leads to a systematic alteration of the chemical and physical properties of crude oil showing sequential depletion of n-alkane, cycloalkanes, aromatic which increases its specific gravity, viscosity and the abundance of heteroatom-containing compounds. The biodegradation leads to a change in the molecular fingerprints and geochemical parameters of degraded oils, thus make source and maturity identification inconclusive or ambiguous. Asphaltene is equivalent to the most labile part of the respective kerogen and generally has high molecular weight. Its complex chemical structure with substantial microporous units makes it suitable to occlude the hydrocarbon expelled from the source. The occluded molecules are well preserved by the macromolecular structure and thus prevented from secondary alterations. They retain primary organic geochemical information over the geological time. The present study involves the extraction of this occluded hydrocarbon from the asphaltene cage through mild oxidative degradation using mild oxidative reagents like Hydrogen Peroxide (H₂O₂) and Acetic Acid (CH₃COOH) on purified asphaltene of the biodegraded oils of Mansa, Lanwa and Santhal fields in Cambay Basin. The study of these extracted occluded hydrocarbons was carried out for establishing oil to oil and oil to source correlation in the Mehsana block of Cambay Basin. The n-alkane and biomarker analysis through GC and GC-MS of these occluded hydrocarbons show similar biomarker imprint as the normal oil in the area and hence correlatable with them. The abundance of C29 steranes, presence of Oleanane, Gammacerane and 4-Methyl sterane depicts that the oils are derived from terrestrial organic matter deposited in the stratified saline water column in the marine environment with moderate maturity (VRc 0.6-0.8). The oil source correlation study suggests that the oils are derived from Jotana-Warosan Low area. The developed geochemical technique to extract the occluded hydrocarbon has effectively resolved the ambiguity that resulted from the inconclusive fingerprint of the biodegraded oil and the method can be also applied in other biodegraded oils as well.

Keywords: asphaltene, biomarkers, correlation, mild oxidation, occluded hydrocarbon

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Authors: Hui Li, Xiongqi Pang

Abstract:

In recent years, tight oil has become a hot spot for unconventional oil and gas exploration and development in the world. Dongpu Depression is a typical hydrocarbon-rich basin in the southwest of Bohai Bay Basin, in which tight sandstone oil and gas have been discovered in deep reservoirs, most of which are buried more than 3500m. The distribution and development characteristics of deep tight sandstone reservoirs need to be studied. The main source rocks in study area are dark mudstone and shale of the middle and lower third sub-member of Shahejie Formation. Total Organic Carbon (TOC) content of source rock is between 0.08-11.54%, generally higher than 0.6% and the value of S1+S2 is between 0.04–72.93 mg/g, generally higher than 2 mg/g. It can be evaluated as middle to fine level overall. The kerogen type of organic matter is predominantly typeⅡ1 andⅡ2. Vitrinite reflectance (Ro) is mostly greater than 0.6% indicating that the source rock entered the hydrocarbon generation threshold. The physical property of reservoir was poor, the most reservoir has a porosity lower than 12% and a permeability of less than 1×10⁻³μm. The rocks in this area showed great heterogeneity, some areas developed desserts with high porosity and permeability. According to SEM, thin section image, inclusion test and so on, the reservoir was affected by compaction and cementation during early diagenesis stage (44-31Ma). The diagenesis caused the tight reservoir in Huzhuangji, Pucheng, Weicheng Area while the porosity in Machang, Qiaokou, Wenliu Area was still over 12%. In the process of middle diagenesis phase stage A (31-17Ma), the reservoir porosity in Machang, Pucheng, Huzhuangji Area increased due to dissolution; after that the oil generation window of source rock was achieved for the first phase hydrocarbon charging (31-23Ma), formed the conventional oil deposition in Machang, Qiaokou, Wenliu, Huzhuangji Area and unconventional tight reservoir in Pucheng, Weicheng Area. Then came to stage B of middle diagenesis phase (17-7Ma), in this stage, the porosity of reservoir continued to decrease after the dissolution and led to a situation that the reservoirs were generally compacted. And since then, the second hydrocarbon filling has been processing since 7Ma. Most of the pools charged and formed in this procedure are tight sandstone oil reservoir. In conclusion, tight sandstone oil was formed in two patterns in Dongpu Depression, which could be concluded as ‘density fist then accumulation’ pattern and ‘accumulation fist next density’ pattern.

Keywords: accumulation process, diagenesis, dongpu depression, tight sandstone oil

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Authors: Xin Li, Zhenxue Jiang, Zhuo Li

Abstract:

Generally, shale gas is trapped within shale systems with low porosity and ultralow permeability as free and adsorbing states. Its production is controlled by properties, in terms of occurrence phases, gas contents, and percolation characteristics. These properties are all influenced by porous features. In this paper, porosity differences of marine shales were explored between Lower Cambrian shale and Lower Silurian shale of Sichuan Basin, South China. Both the two shales were marine shales with abundant oil-prone kerogen and rich siliceous minerals. Whereas Lower Cambrian shale (3.56% Ro) possessed a higher thermal degree than that of Lower Silurian shale (2.31% Ro). Samples were measured by a combination of organic-chemistry geology measurement, organic matter (OM) isolation, X-ray diffraction (XRD), N2 adsorption, and focused ion beam milling and scanning electron microscopy (FIB-SEM). Lower Cambrian shale presented relatively low pore properties, with averaging 0.008ml/g pore volume (PV), averaging 7.99m²/g pore surface area (PSA) and averaging 5.94nm average pore diameter (APD). Lower Silurian shale showed as relatively high pore properties, with averaging 0.015ml/g PV, averaging 10.53m²/g PSA and averaging 18.60nm APD. Additionally, fractal analysis indicated that the two shales presented discrepant pore morphologies, mainly caused by differences in the combination of pore types between the two shales. More specifically, OM-hosted pores with pin-hole shape and dissolved pores with dead-end openings were the main types in Lower Cambrian shale, while OM-hosted pore with a cellular structure was the main type in Lower Silurian shale. Moreover, porous characteristics of isolated OM suggested that OM of Lower Silurian shale was more capable than that of Lower Cambrian shale in the aspect of pore contribution. PV of isolated OM in Lower Silurian shale was almost 6.6 times higher than that in Lower Cambrian shale, and PSA of isolated OM in Lower Silurian shale was almost 4.3 times higher than that in Lower Cambrian shale. However, no apparent differences existed among samples with various matrix compositions. At late diagenetic or metamorphic epoch, extensive diagenesis overprints the effects of minerals on pore properties and OM plays the dominant role in pore developments. Hence, differences of porous features between the two marine shales highlight the effect of diagenetic degree on OM-hosted pore development. Consequently, distinctive pore characteristics may be caused by the different degrees of diagenetic evolution, even with similar matrix basics.

Keywords: marine shale, lower Cambrian, lower Silurian, om isolation, pore properties, om-hosted pore

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Authors: Jiahui You, Kyung Jae Lee

Abstract:

Hydraulic fracturing fluid (HFF) is widely used in shale reservoir productions. HFF contains diverse chemical additives, which result in the dissolution and precipitation of minerals through multiple chemical reactions. In this study, a new pore-scale Darcy–Brinkman–Stokes (DBS) model coupled with Level Set Method (LSM) is developed to address the microscopic phenomena occurring during the iron–HFF interaction, by numerically describing mass transport, chemical reactions, and pore structure evolution. The new model is developed based on OpenFOAM, which is an open-source platform for computational fluid dynamics. Here, the DBS momentum equation is used to solve for velocity by accounting for the fluid-solid mass transfer; an advection-diffusion equation is used to compute the distribution of injected HFF and iron. The reaction–induced pore evolution is captured by applying the LSM, where the solid-liquid interface is updated by solving the level set distance function and reinitialized to a signed distance function. Then, a smoothened Heaviside function gives a smoothed solid-liquid interface over a narrow band with a fixed thickness. The stated equations are discretized by the finite volume method, while the re-initialized equation is discretized by the central difference method. Gauss linear upwind scheme is used to solve the level set distance function, and the Pressure–Implicit with Splitting of Operators (PISO) method is used to solve the momentum equation. The numerical result is compared with 1–D analytical solution of fluid-solid interface for reaction-diffusion problems. Sensitivity analysis is conducted with various Damkohler number (DaII) and Peclet number (Pe). We categorize the Fe (III) precipitation into three patterns as a function of DaII and Pe: symmetrical smoothed growth, unsymmetrical growth, and dendritic growth. Pe and DaII significantly affect the location of precipitation, which is critical in determining the injection parameters of hydraulic fracturing. When DaII<1, the precipitation uniformly occurs on the solid surface both in upstream and downstream directions. When DaII>1, the precipitation mainly occurs on the solid surface in an upstream direction. When Pe>1, Fe (II) transported deeply into and precipitated inside the pores. When Pe<1, the precipitation of Fe (III) occurs mainly on the solid surface in an upstream direction, and they are easily precipitated inside the small pore structures. The porosity–permeability relationship is subsequently presented. This pore-scale model allows high confidence in the description of Fe (II) dissolution, transport, and Fe (III) precipitation. The model shows fast convergence and requires a low computational load. The results can provide reliable guidance for injecting HFF in shale reservoirs to avoid clogging and wellbore pollution. Understanding Fe (III) precipitation, and Fe (II) release and transport behaviors give rise to a highly efficient hydraulic fracture project.

Keywords: reactive-transport , Shale, Kerogen, precipitation

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