Hydrocarbon Expulsion Research Articles

Basin and petroleum system modeling of the Cretaceous and Jurassic source rocks of the gas and oil reservoirs in Darquain field, south west Iran

In south west Iran, in the Abadan Plain, there are several giant gas and oil reserves in Jurassic and Cretaceous carbonates, such as Darquain, where there are excellent source rocks in the Early Cretaceous and Jurassic successions. In present study, petroleum generation and migration from these source rocks were evaluated. Maturity state of organic matter was determined with Organic petrography and results were used for calibration of thermal model. Basin modeling was used for investigation of petroleum generation and migration history. Burial history and 3D thermal model were constructed for the study area using Temis suite and Genex software. Modeling shows source rocks of Jurassic, such as Sargelu and Neyriz are in gas maturity state, oil generation phase passed before Cenozoic. It appears that gas from Jurassic source rocks accumulated in Najmeh and did not reach to Cretaceous Fahliyan reservoir. Cretaceous reservoir in Fahliyan Formation has been charged by the Garau Formation. This source rock reached to oil window in Early Cretaceous time and began hydrocarbon expulsion at the end of Cretaceous when the Darquain structure formed. Migration paths of hydrocarbons shifted from NE to SW direction about 11 Ma in response to changes in regional structural dip contemporary with the Zagros Orogeny. Modeling results indicate that the quantity of gas and oil generated in the kitchen area was more than the reservoirs' capacity. Therefore, the surplus hydrocarbon could have migrated laterally out of reservoir area.

Source rock characteristics and hydrocarbon expulsion potential of the Middle Eocene Wenchang formation in the Huizhou depression, Pearl River Mouth basin, south China sea

The Middle Eocene Wenchang (WC) formation in the Huizhou depression of the Pearl River Mouth basin is an important geological element for petroleum exploration in the South China Sea. In this study, the geological and geochemical characteristics of the WC source rocks, including the distribution, sedimentary environment, organic matter type, hydrocarbon generation potential and thermal maturity were investigated. Hydrocarbon generation history and hydrocarbon expulsion intensity and quantities were evaluated through one dimensional basin modelling and an improved hydrocarbon generation potential methodology. The WC source rocks are widely distributed and have an elevated thickness (mostly thicker than 200 m, with a maximum thickness greater than 1000 m); they were deposited in a lacustrine weak oxidation–weak reduction sedimentary environment with low salinity. The source rocks have low to high organic matter abundance (TOC mainly ranges from 0.27 to 3.59 wt% with an average of 1.39 wt%) dominated by II1–type and II2–type kerogen, resulting in significant hydrocarbon generating potential under moderate–high thermal evolution (Ro mainly ranges from 0.65% to 1.2% on the margins of sags and greater than 1.2% in the centre of sags). The source rocks became mature (Ro = 0.5%) in the early Miocene and began to generate hydrocarbons. They reached the hydrocarbon expulsion threshold at 0.8% Ro and the hydrocarbon expulsion rate became greatest at 1.1% Ro. The expulsion intensities in the H26 sag, H21 sag, X24 sag and X23 sag are relatively large, with their greatest expulsion intensities being 104 × 106, 71 × 106, 62 × 106 and 53 × 106 t/km2, respectively. The comprehensive hydrocarbon expulsion efficiency was approximately 75%. About 690.1 × 108 t of hydrocarbons were expulsed from the WC source rocks in the Huizhou depression.

Source rock characterization of the Albian Kazhdumi formation by integrating well logs and geochemical data in the Azadegan oilfield, Abadan plain, SW Iran

Abstract There are several source rock units in the Zagros Basin. Nevertheless, the Cretaceous Kazhdumi formation has presumably produced the majority of the commercial hydrocarbons in this area. The presence of organic matter rich and thermally mature rock units containing oil or gas prone kerogen is the key factor controlling the hydrocarbon generation potential. Owing to the lack of organic geochemical studies such a potential is poorly investigated in the Azadegan oilfield. In this study, firstly we investigate the lower Cretaceous Kazhdumi formation potential source rock based on geochemical parameters including type and amount of kerogen and thermal maturity, obtained from analyzing 45 cutting samples from 9 wells by using Rock-Eval 6 apparatus. Moreover, vitrinite reflectance measurements were carried out on 11 samples utilizing Zeiss Axioplan II microscope for further examination of the thermal maturation. Burial history analysis and thermal maturity modeling suggests that Kazdumi formation is marginally mature (vitrinite reflectance in the range of 0.5–0.7%) with hydrocarbon expulsion beginning since about 14 Ma. The results indicate increasing maturity from south to the north as a result of burial deepening of the Kazhdumi Formation. It contains type II and mixed types II/III kerogen with TOC (Total Organic Carbon) values up to 4.88 wt% and Source Potential Index (SPI) value of 3.72 t HC/m 2 providing a moderate source for the hydrocarbons encountered in the reservoir rocks. In the second part of this research, we attempt to characterize the Kazhdumi source rock by using intelligent systems. In this regard, a three-layered back-propagation Artificial Neural Network (ANN) with Levenberg–Marquardt (LM) training algorithm was designed to predict TOC values from well log data (RHOB, THOR, SGR, NPHI, DT). This network is capable of predicting TOC with correlation coefficient of 98.63% and 82.62% and MSE of 0.0067 and 0.1772 for training and testing steps, respectively. According to the ANN modeling and TOC distribution map, organic richness of the Kazhdumi formation increases from south to the north over the study area.

The Pliocene-age Stirone River hydrocarbon chemoherm complex (Northern Apennines, Italy)

The Stirone River section in the Italian Northern Apennines hosts a rare example of Pliocene age hydrocarbon-imprinted carbonates in the Mediterranean Basin associated with deep-water hemipelagic lithologies. These include meter-sized, dolomite-cemented chimneys, micritic brecciated limestones, lucina-mudstones and chemosymbiotic bivalve shells. Some such chimneys show δ13C values as low as −37.5‰ VPDB, suggesting subsurface precipitation of authigenic dolomite induced by anaerobic oxidation of methane triggered by consortia of sulphate reducing bacteria. These carbonates are interpreted as part of the plumbing system related to hydrocarbon expulsion onto the seafloor, resulting from hydrocarbon-enriched defluidization processes dated at an interval at 3.6–3.3 Ma and associated with the thrust-related “Salsomaggiore structure”.

Quantitative estimation of overpressure caused by gas generation and application to the Baiyun Depression in the Pearl River Mouth Basin, South China Sea

AbstractHydrocarbon generation can yield high fluid pressures in sedimentary basins as the conversion of solid kerogen to hydrocarbons can result in an increase in fluid volume. To quantify the relationship between gas generation and overpressure in source rocks, a set of equations for computing the pressure change due to gas generation has been derived. Those equations can be used to quantitatively estimate overpressure generated by type III kerogen in source rocks by considering gas generation and leakage, gas dissolution in formation water and residual oil, thermal cracking of oil to gas, and hydrocarbon episodic expulsion from source rocks. The equations also take consideration of other factors including source rock porosity, transformation ratio, total organic carbon (TOC), hydrogen index, and compressibility of kerogen, oil, and water. As both oil and gas are taken into account in the equations, they can also be used to estimate the evolution of overpressure caused by hydrocarbon generation of type I and type II kerogen source rocks. Sensitivity analyses on the type III kerogen source rock indicate that hydrogen index is the most influential parameter for overpressure generation, while TOC and residual gas coefficient (β: ratio of residual gas over the total gas generated) have a moderate effect. Overpressure can be generated even if the gas leakage/loss in the source rock is up to 80% of the total gas generated. This suggests that the internal pressure seal of the source rock is not a critical factor on the pressure change as long as the source rocks are capable of sealing liquid oil. The equations were applied to evaluate the overpressure in the Eocene–Oligocene Enping Formation source rocks due to hydrocarbon generation in the Baiyun Depression, the Pearl River Mouth Basin by considering the source rock properties, hydrocarbon generation history, and hydrocarbon expulsion timing. Two episodes of overpressure development due to gas generation and release were modeled to have occurred in the Enping Formation source rock since 16 Ma. The overpressure release at 10.2–5.3 Ma via hydrocarbon expulsion was apparently related to the Dongsha phase of tectonic deformation, whereas the pressure release at 2–0 Ma was due to pressure generation that was exceeded the fracture‐sealing pressure in the source rocks.

The “chimney forest” of the deep Montenegrin margin, south-eastern Adriatic Sea

A spectacular field of columnar carbonates has been discovered on the Montenegrin margin in the southern Adriatic Sea at a depth of about 450 m. The site exposes many columnar carbonates protruding from the substrate or abated on the bottom. Such carbonates attain maximum visible lengths of ca. 60 cm with diameters up to 20 cm; display an annular growth, and are either hollow or plugged by indurated sediment. Petrographic and geochemical analyses document the pervasive presence of dolomite, and δ13C values as low as −30‰ VPDB. These ‘chimneys’ are therefore interpreted as former conduits related to hydrocarbon expulsion in this sector of the Adriatic basin. However, available data suggest that hydrocarbon flows at this site have ceased. Our results show that chimneys formed inside the local depositional units, glacial Pleistocene shelf shelly-rich muddy sediment and were successively exhumed from the host sediment. Today, the chimneys offer substrate to benthic life, including cold water corals and sponges. The U-series dating of these carbonate concretions is complicated by the presence of a significant fraction of detrital sediment, which represents a major source of initial 230Th. AMS-14C and 87Sr/86Sr dating of shells embedded in one of the chimney provided ages beyond the range of radiocarbon dating and <600 kyrs, indicating a Pleistocene age of the host sediment. Uncorrected U-series dating of the carbonate chimneys yielded and age of ca. 250–270 kyrs, providing a temporal upper limit for conduit formation driven by lithification caused by the degradation of seeping hydrocarbons. In addition, U/Th dating of cold water coral bases settled on chimneys indicates a Holocene age for their first exposure after exhumation and subsequent function as hard substrate for benthic organisms. The Montenegrin ‘chimney forest’ is a rare case where many such carbonate columnar concretions are still in their original vertical position.

Is there a pre-Cretaceous source rock in the Colombia Putumayo Basin? Clues from a study of crude oils by conventional and high resolution geochemical methods

A geochemical characterization of sixteen crude oil samples from the Putumayo Basin, southern Colombia, was carried out. This basin is located to the north of Ecuador's Oriente Basin, one of the most prolific hydrocarbon basins in South America. Regardless of the fact that these two basins seem to share the same geological evolution, the volume of hydrocarbon reserves found in the Oriente Basin is five times greater than in the Putumayo Basin. This represents an exploratory opportunity to the extent that a better understanding of the petroleum system processes in the Putumayo Basin can be achieved. Newly available geochemical technology shows evidence that these crude oils originated from Late Cretaceous source rocks. The novel application of an age-related biomarker, the C25-highly branched isoprenoid, has constrained the age of the principal source of all these oils as Late Cretaceous or younger. Advanced geochemical technologies, such as compound specific isotope analyses of biomarkers (CSIA-B) and diamondoids (CSIA-D), and quantitative extended diamondoid analysis (QEDA), have confirmed, repeatedly, that the oil samples are all related to the same source with minor facies variations. The integration of these results with geological data suggests the presence of a very efficient petroleum system, characterized by an alternating sequence of soA§urce and reservoir rocks. Thermal maturity of the oils from biomarker and diamondoid parameters ranges from well before the peak of hydrocarbon expulsion to the beginning of the late hydrocarbon generation phase. The aerial distribution of these maturity parameters suggests the existence of two, or possibly three, pods of active source rocks, located to the southwest and to the east of the basin, and possibly to the north. This would modify the classic hydrocarbon migration model for the Putumayo Basin, increasing the hydrocarbon potential of the basin. Given the low level of thermal maturity documented in the Cretaceous sequence that has been drilled, the possibility to evaluate the presence of a very reactive kerogen with hydrocarbon expulsion thresholds at lower temperatures is proposed.

The Influence of the Karatau Fault on Hydrocarbon Migration in the Aryskum Depression, Kazakhstan

In this paper, the history of Karatau strike-slip fault and its control on inversion structures and hydrocarbon migration of the Aryskum depression were discussed. Karatau fault was characterized by sinistral strike-slip in the early stage and dextral strike-slip in the late stage. Lots of positive inversion structures in the Aryskum depression formed by the dextral strike-slip movement during Eocene-Oligocene, which synchronized with the main generation and expulsion stages of major source rocks, becoming favorable traps for hydrocarbon accumulation. Karatau fault also dominated the direction of hydrocarbon expulsion and migration in the J1 and J2 source rocks by altering their layer shapes, resulting in higher hydrocarbon enrichment in the depression center than that in the flanks. Meanwhile, as the thickness of regional cap rock in the middle and northern parts of the Aryskum depression is obviously higher than that in the relevant vertical fault throws which has caused little hydrocarbon dissipation from the fault, the hydrocarbon enrichment in the middle and northern parts of the depression is higher than that in the southern part.

Porosity evolution in oil-prone source rocks

The origin of porosity and mechanisms of fluid flow in the presence of organic matter and clay minerals in source rocks are poorly understood. Burial and maturation of the source rock modify or create the pore systems in these rocks. Kerogen decomposition and consequent shrinkage may change the load bearing state of the minerals and organic matter and affect pore system since early stages of maturation. Geochemical evidence confirms that the hydrocarbon expulsion process (i.e. primary migration) is not 100% efficient. Expulsion of hydrocarbon is mainly driven by (1) pressure increase in the source rock due to solid kerogen conversion and volume increase and (2) continued compaction of the sediment. Converted organic matter is partly retained in the source rock diverse framework constituents. Quantitative measurement of and determining producibility of the retained hydrocarbon in the source rock is to date highly debated. The source rock hydrocarbon storage capacity is controlled by pore-hosting particles, pore system topology and rock–fluid interactions.The presence of organic matter and clay minerals affect log responses by generally overestimating porosity, because the low density kerogen is not accounted for, and together with low resistivity caused by presence of clay minerals can result in erroneous saturation calculations; thus, accurate reserve estimation often is challenged if the impact of low organic matter density is not explicitly addressed.In order to understand porosity evolution and the interaction of organic byproducts (i.e. bitumen and pyrobitumen) with rock minerals during thermal maturation, one must study source rock samples with different maturities. For this reason, ten Bakken Shale samples with varying maturity and mineralogy were selected in this study. Pore size distributions (PSD), specific surface areas (SSA) and geochemical characteristics of the samples were measured in native state and after successive solvent extraction.The PSD and SSA measured after each extraction shows recovery of the pore system with successive cleaning. Most significant was the recovery of kerogen-hosted pores with removal of soluble, oil-like organic material. Using successive extractions we are able to determine the evolution of organic matter porosity through maturation which is otherwise not feasible using visual techniques or other conventional laboratory procedures.

Petroleum geology features and research developments of hydrocarbon accumulation in deep petroliferous basins

As petroleum exploration advances and as most of the oil–gas reservoirs in shallow layers have been explored, petroleum exploration starts to move toward deep basins, which has become an inevitable choice. In this paper, the petroleum geology features and research progress on oil–gas reservoirs in deep petroliferous basins across the world are characterized by using the latest results of worldwide deep petroleum exploration. Research has demonstrated that the deep petroleum shows ten major geological features. (1) While oil–gas reservoirs have been discovered in many different types of deep petroliferous basins, most have been discovered in low heat flux deep basins. (2) Many types of petroliferous traps are developed in deep basins, and tight oil–gas reservoirs in deep basin traps are arousing increasing attention. (3) Deep petroleum normally has more natural gas than liquid oil, and the natural gas ratio increases with the burial depth. (4) The residual organic matter in deep source rocks reduces but the hydrocarbon expulsion rate and efficiency increase with the burial depth. (5) There are many types of rocks in deep hydrocarbon reservoirs, and most are clastic rocks and carbonates. (6) The age of deep hydrocarbon reservoirs is widely different, but those recently discovered are predominantly Paleogene and Upper Paleozoic. (7) The porosity and permeability of deep hydrocarbon reservoirs differ widely, but they vary in a regular way with lithology and burial depth. (8) The temperatures of deep oil–gas reservoirs are widely different, but they typically vary with the burial depth and basin geothermal gradient. (9) The pressures of deep oil–gas reservoirs differ significantly, but they typically vary with burial depth, genesis, and evolution period. (10) Deep oil–gas reservoirs may exist with or without a cap, and those without a cap are typically of unconventional genesis. Over the past decade, six major steps have been made in the understanding of deep hydrocarbon reservoir formation. (1) Deep petroleum in petroliferous basins has multiple sources and many different genetic mechanisms. (2) There are high-porosity, high-permeability reservoirs in deep basins, the formation of which is associated with tectonic events and subsurface fluid movement. (3) Capillary pressure differences inside and outside the target reservoir are the principal driving force of hydrocarbon enrichment in deep basins. (4) There are three dynamic boundaries for deep oil–gas reservoirs; a buoyancy-controlled threshold, hydrocarbon accumulation limits, and the upper limit of hydrocarbon generation. (5) The formation and distribution of deep hydrocarbon reservoirs are controlled by free, limited, and bound fluid dynamic fields. And (6) tight conventional, tight deep, tight superimposed, and related reconstructed hydrocarbon reservoirs formed in deep-limited fluid dynamic fields have great resource potential and vast scope for exploration. Compared with middle–shallow strata, the petroleum geology and accumulation in deep basins are more complex, which overlap the feature of basin evolution in different stages. We recommend that further study should pay more attention to four aspects: (1) identification of deep petroleum sources and evaluation of their relative contributions; (2) preservation conditions and genetic mechanisms of deep high-quality reservoirs with high permeability and high porosity; (3) facies feature and transformation of deep petroleum and their potential distribution; and (4) economic feasibility evaluation of deep tight petroleum exploration and development.

Hydrocarbon Generation and Expulsion of the Upper Triassic T3x5 Source Rocks in the Western Sichuan Depression: Assessment for Unconventional Natural Gas

AbstractTight‐sand gas in the Jurassic and shale gas within the fifth member of Xujiahe Formation (T3x5) in the Western Sichuan Basin (WSD) are currently regarded as the most prolific emerging unconventional gas plays in China. This study conducted a conventional evaluation of T3x5 source rocks in the WSD, and investigated their hydrocarbon generation and expulsion characteristics, including intensity, efficiency and amount. The results show that, the T3x5 source rocks are thick (generally &gt;200 m), and have a high total organic content (TOC), ranging from 2.5 to 4.5 wt%. It is thus indivative of a great hydrocarbon generation potential when they underwent high thermal evolution (Ro&gt;1.2%) in the area. In addition, an improved method of hydrocarbon generation potential is applied, indicating that the source rocks reached a hydrocarbon expulsion threshold with vitrinite reflectance (Ro) reaching 1.06%, and that the comprehensive hydrocarbon expulsion efficiency is about 60%. The amount of hydrocarbon generation and expulsion from T3x5 source rocks is 3.14×1010 t and 1.86×1010 t, respectively, with a residual amount of 1.28×1010 t within them. Continuous‐type tight‐sand gas is predicted to have developed in the Jurassic in the Chengdu Sag of the WSD because of the good source‐reservoir configuration; the Jurassic sandstone reservoirs are tight, and the gas expelled from the T3x5 source rocks migrates for very short distances vertically and horizontally. The amount of gas accumulation in the Jurassic reservoirs derived from T3x5 source rocks is up to 9.3×108 t. Geological resources of shale gas are up to 1.05×1010 t. Small differences between the amounts calculated by the volumetric method and those obtained by hydrocarbon generation potential method may be due to other gas accumulations present within interbedded sands associated with gas shales.

Characteristics, origin and quantitative evaluation of overpressure in strike-slip and compression-shear booster zone of Tan-Lu Fault:

Abstract In the JZ27-A well block of the strike-slip and compression-shear booster zone in the JZ27 section of the Liaodong Bay in the Bohai Sea area of the Tan-Lu Fault, overpressure developed in the third member of the Shahejie Formation, and the pressure coefficient reached an average of 1.5. Thick mudstones sealed the overpressure on the top. Particle fragmentation was obvious in the overpressure zone. The area and thickness of the overpressure were controlled by the range of the pressure booster zone and the intense development of strike-slip and compression-shear zone, mainly restricted to the third member of the Shahejie Formation in the JZ27-A well block. The origin for overpressure was interpreted to be as follows. From the end of the third member of the Dongying Formation to the early stage of the second member of the Dongying Formation, influenced by the intense dextral strike-slip of the Tan-Lu Fault, stress concentrated in the JZ27-A well block of the strike-slip and compression-shear booster zone. Thereby, horizontal structural compression stress formed. At the same time, because of overlying thick-bedded mudstones, stress could not be released effectively. As a result, overpressure occurred. According to the balance of reservoir pressure, the contribution of strike-slip stress to overpressure was quantitatively evaluated. The contribution of strike - slip stress to overpressure was 30% - 35% and occurred earlier than the period with large amounts of hydrocarbon generation and expulsion. The overpressure impeded the charging of oil tremendously.

南美Llanos 盆地中部地区烃源岩与原油地球化学特征

Abstract The central Llanos Basin in South America is an important petroliferous province. The analysis of the geochemical features of source rocks and crude oils in the study area revealed the process of hydrocarbon expulsion, migration and accumulation as well as the biodegradation features of crude oils. According to rock evaluation and crude oil composition, and combined with a variety of biomarker parameters, the geochemical features of source rocks and crude oils were analyzed systematically and comprehensively. Several conclusions were made as follows. Firstly, source rocks in the Gacheta Formation were deposited in a saline-water and weakly oxidizing to weakly reducing environment with little terrestrial organic matter, and kerogen in the Gacheta Formation was of sapropel-humic type. Source rocks in the Los Cuervos Formation were deposited in an oxidizing brackish-water environment with abundant terrestrial organic matter, and kerogen in the Los Cuervos Formation was of sapropel- humic and humic types. Source rocks in the Gacheta and Los Cuervos formations were both low-maturity and medium-maturity, showing large hydrocarbon-generating potentials. Secondly, 3 crude oil families were found in the central basin, named families A, B and C. Crude oils of family A originated from Cretaceous source rocks, while those of family B from Paleogene, and those of family C were a mixture of families A and B. Thirdly, for most of the crude oil samples, rearranged sterane was abundant, the dibenzothiophene/ phenanthrene ratio was low, and the Pr/Ph value was high, indicating that the source rocks were marine-facies shales rather than carbonates. Finally, crude oil composition was controlled by biodegradation and recharge. From the Santiago Oilfield to the La Gloria Oilfield, biodegradation effect weakened toward the NE. Influenced by the recharge of light oils, crude oils from the Cupiagua and Buenos Aires Oilfields had much higher API gravity values than those from the La Gloria and other oilfields

What can be learned from the K-Ar ages of illite from Rotliegend sandstones of the Fore-Sudetic Monocline, SW Poland?

The all available K-Ar data of authigenic illite from Rotliegend aeolian sandstones of the Fore-Sudetic Monocline, including the results from six samples examined in the present study, are reviewed in terms of their geological meaning, relation to diagenetic processes occurring in the sandstones, and implications for a petroleum system. The majority of ages fall in the range between 195 and 150 Ma, i.e. they correspond to Jurassic times. The results may be grouped in several time intervals, which are almost identical to those identified for Rotliegend sandstones of central and western Europe, and which are interpreted as pulses of intensive illite growth. The K-Ar data corroborate the long-held assumption that throughout the entire Southern Permian Basin Jurassic illite growth was triggered by the same, large-scale underlying processes, which manifested themselves in enhanced heat flow. These processes may also have caused the expulsion of hydrocarbons from source rocks.

A developmental model of lacustrine shale gas genesis: A case from T3y7 shale in the Ordos Basin, China

Exploration for gas producing lacustrine shales in the Ordos Basin has identified considerable capacity in T3y7 shale in the Upper Triassic. The T3y7 shale is a black color, siliclastic organic rich lacustrine mudrock. The mineral components primarily include clay minerals, quartz and feldspar, with the brittle mineral (quartz, feldspar and carbonate) content accounting for 56 wt. %. The presence of type II kerogens, the high TOC contents (most 2%–4%), thermal maturation reaching the oil/gas window and constant organic-rich shale thickness indicate that optimum conditions for shale gas have been reached. The maximum adsorption gas content of T3y7 shale reaches 1 cm3/g at 0.5 MPa, and the value of most samples was more than 2 cm3/g and, at times, even reached 4.6 cm3/g at 5 MPa pressure, which is higher than the main gas shale in the U.S. Organic carbon isotope suggests that the natural gas in T3y7 shale is associated with oil-prone and thermally mature gases. According to the simulation product, three stages can be identified in the shale thermal maturation and hydrocarbon expulsion process: the oil window (0.5% < Ro < 1.1%), wet gas window (1.1% < Ro < 1.8%) and the dry gas window (Ro > 1.8%). These results indicate that the natural gas in T3y7 shale is characterized as wet gas. The relationship between the gas/oil ratio and the conversion degree of organic matter (TRHI) was established in this study. Comprehensive analysis of basin evolution, the development of organic-rich shale and burial history, shale gas – shale oil/gas – shale oil – shale gas was regularly distributed from the bottom to the upper strata. Simultaneously, shale oil – wet gas – shale gas developed from the depression center to the basin slope and, subsequently, to the basin margin. In the lake, the zonation of organic types was obvious, which was manifested as Type I-prone in the semi-deep and deep lake while Type III-prone in the shallow lake. The organic matter of target shale was primarily Type-II. The shale gas of T3y7 shale was mainly pyrolysis yield, which was most associated with oil, and the wet gas appears broadly. Compared with the marine-continent transition and marine shale, T3y7 shale is characterized by a moderate burial depth and thickness, high TOC content, low porosity, high gas content, mostly adsorbed gas and wet gas.

Oil content in argillaceous dolomite from the Jianghan Basin, China: Application of new grading evaluation criteria to study shale oil potential

Shale oil resources are found in the argillaceous dolomite in the Xingouzui Formation of the Jianghan Basin. The grading evaluation criteria based on the oil content was established to discuss the shale oil potential. The parameter of hydrocarbon potential index, (S1+S2)/TOC×100, suggests that the hydrocarbon potential of the argillaceous dolomite becomes lower significantly with the type of kerogen changing from I to III. However, a corresponding decrease in the amount of residual hydrocarbon (S1/TOC) is within a small range, because the argillaceous dolomite with I and II1 kerogen (especially I kerogen) have relatively larger hydrocarbon expulsion amount. For shale oil exploration, besides type I source rocks, source rocks with II1 and II2 kerogen should also be focused. However, source rocks with III kerogen bear no exploration significance owing to the low hydrocarbon generation capacity and unfavorable molecular configuration. According to the relationship between S1 and TOC, combined with parameter of the relative oil content, the shale oil resources can be divided into four classifications: enriched resources (S1>4mg/g and S1/TOC>1), moderately enriched resources (1mg/g<S1<4mg/g and S1/TOC>1), less efficient resources (1mg/g<S1<4mg/g and S1/TOC<1), and ineffective resources (S1<1mg/g and S1/TOC<1). The continuous distribution of the oil content of the argillaceous dolomite in the Lower Xingouzui Formation can be obtained using the method of Δlog R. The enriched or moderately enriched resources are primarily distributed in the argillaceous dolomite with kerogen types I and II1. In addition, moderately enriched resources also exist in the argillaceous dolomite with kerogen type II2 in the middle and bottom of the Lower Xingouzui Formation, but the distribution is more dispersed.

Impact of hydrocarbon expulsion efficiency of continental shale upon shale oil accumulations in eastern China

Core samples were taken from two formations (the Qingshankou Formation in northern Songliao Basin and the third member of the Shahejie Formation of Zhanhua Sag) to carry out a study of impact of hydrocarbon expulsion from continental shale upon shale oil accumulations in eastern China. Total Organic Carbon (TOC) and pyrolysis data of these samples were used to establish an evaluation criterion with absolute and relative oil content indexes for determining oil potential of shale. As a result, a correspondence relationship between shale oil content and organic types was established. Factors that may affect oil content of shale were discussed through study of fractures, pore development, minerals and lithological assemblage of the samples. The results show that oil content of mature petroleum source rocks is firstly controlled by fracture growth and secondly by pore development. They played both negative and positive roles in hydrocarbon flow and accumulation in shale. Overpressure caused by hydrocarbon generation and existence of organic acid corrosion are two important factors affecting the formation of fractures and pores in shale, respectively. Intervals with type I organic matter are not favorable shale oil exploration targets because they contain little oil. Shale with type I organic matter tends to generate large amount of hydrocarbon, but these hydrocarbon will escape with a high efficiency through over-pressurized fractures caused by hydrocarbon generation and lack of pore space, which in turn is the result of absence of oxygen that is essential for forming organic acid to create secondary pores in shale. On the contrary, intervals with type II organic matters are potential shale oil exploration targets for that they offered just right conditions for oil to stay inside: higher content of oxygen that is helpful in forming organic acid, moderate hydrocarbon generation capacity that will not cause over-pressurized fractures in shale with secondary pores. While intervals with type III organic matter bear no exploration significance due to the fact that this type of kerogen produces less oil because of low hydrocarbon generation capacity and unfavorable molecular configuration. Shale intervals with thin sandstone interbeds provide favorable passageways for dissolved carbonate by organic acid to flow out, avoiding secondary precipitation. The pores left behind can be excellent space for generated hydrocarbon to linger around. These interbeds are also favorable for later reservoir stimulation measures such as hydraulic fracturing. Shale oil exploration shall be focused on finding sweet spots with greater pores, which are the main reservoir space.

Gas generation and expulsion characteristics of Middle–Upper Triassic source rocks, eastern Kuqa Depression, Tarim Basin, China: implications for shale gas resource potential

Frontier exploration in the Kuqa Depression, western China, has identified the continuous tight-sand gas accumulation in the Lower Cretaceous and Lower Jurassic as a major unconventional gas pool. However, assessment of the shale gas resource in the Kuqa Depression is new. The shale succession in the Middle–Upper Triassic comprises the Taliqike Formation (T3t), the Huangshanjie Formation (T3h) and the middle–upper Karamay Formation (T2–3k), with an average accumulated thickness of 260 m. The high-quality shale is dominated by type III kerogen with high maturity and an average original total organic carbon (TOC) of about 2.68 wt%. An improved hydrocarbon generation and expulsion model was applied to this self-contained source–reservoir system to reveal the gas generation and expulsion (intensity, efficiency and volume) characteristics of Middle–Upper Triassic source rocks. The maximum volume of shale gas in the source rocks was obtained by determining the difference between generation and expulsion volumes. The results indicate that source rocks reached the hydrocarbon expulsion threshold of 1.1% VR and the hydrocarbon generation and expulsion reached their peak at 1.0% VR and 1.28% VR, with the maximum rate of 56 mg HC/0.1% TOC and 62.8 mg HC/0.1% TOC, respectively. The volumes of gas generation and expulsion from Middle–Upper Triassic source rocks were 12.02 × 1012 m3 and 5.98 × 1012 m3, respectively, with the residual volume of 6.04 × 1012 m3, giving an average gas expulsion efficiency of 44.38% and retention efficiency of 55.62%. Based on the gas generation and expulsion characteristics, the predicted shale gas potential volume is 6.04 × 1012 m3, indicating a significant shale gas resource in the Middle–Upper Triassic in the eastern Kuqa Depression.

Thermal maturity history and petroleum generation modelling for the Upper Jurassic Madbi source rocks in the Marib-Shabowah Basin, western Yemen

Widely exposed in the Marib-Shabowah Basin, the early Upper Jurassic Madbi Formation is divided into two units (Lam and Meem, youngest to oldest) believed to be major source rocks. The Madbi source rocks are characterized by relatively high total organic carbon contents (TOC) ranging from 0.5 to 10.0 wt%, meeting the standard as a fair to excellent source rock generative potential. They contain Type II kerogen grading to mixed Type II/III kerogens and Type III kerogen with HI values between 40 and 620 mg HC/g TOC. Vitrinite reflectance values range from 0.41 to 2.61% Ro, indicating sufficient thermal maturity for both oil and gas generation.Burial/thermal history models indicate that the Upper Jurassic Madbi source rocks passed the peak of oil generation stage and convert the oil to dry gas in the Late Jurassic to Late Cretaceous time. Oil generation began immediately after deposition in the Late Jurassic time (150–145 Ma) and maximum rates of oil with significant gas have been generated during Late Cretaceous time (110–65 Ma). The peak gas generation occurred during the early Tertiary. The modelled hydrocarbon expulsion evolution suggests that the timing of hydrocarbon expulsion from the Madbi source rocks began in the early Cretaceous (140 Ma) persisted to present-day. The modelling results also indicate that the peak hydrocarbon generation and expulsion from Madbi source rocks in the studied area occurs well after deposition of the seal rock and formation of traps, ensuring entrapment and preservation of migrated hydrocarbons.

Clay mineral occurrence and burial transformations: reservoir potential of the Permo‐Triassic sediments of the Iberian Range

AbstractThe diagenetic evolution of Permian (Autunian and Saxonian) and Triassic (Buntsandstein) sandstones and mudrocks have been studied over 1000 m sequence from the Sigüenza 44‐3 drill core in the Iberian Range, Spain. We compare and contrast the diagenetic processes in these different lithologies and the timing of clay mineral formation. Moreover, we establish the relationship between clay mineral diagenesis and reservoir potential. Both the Permian and Triassic successions are characterised by conglomerates, sandstones and interbedded mudstones of fluvial origin that change upwards into distal deposits of a fluvio‐deltaic system. The clay minerals are illite, illite‐smectite mixed layers, kaolinite and dickite. The illite content in all sequences is not related to diminished feldspars; it is owing to the initial detrital mineralogical composition of the Autunian sandstones. The effect of feldspar alteration to kaolin minerals has a strong influence on the lost of porosity‐permeability in the Saxonian facies. In contrast, illite and mixed layers illite‐smectite are the main clay rims preserving porosity in the Buntsandstein sandstones. However, fibrous illite is the dominant pore‐filling in the Permian Autunian facies, closing porosity and permeability. Kaolinite and dickite show opposite trends: dickite increases yet kaolinite decreases from Triassic to Permian sandstones. Dickite replaced kaolinite during burial‐thermal evolution of the succession. The δD and δ18O isotopic signatures from silt and clay fractions indicate a mixture of meteoric and marine waters, and suggest a minimum temperature range between 60 and 150 °C for diagenetic pore fluids. The Permian δD values (−24‰ to −44‰) are relatively similar to Buntsandstein values (−24‰ to −37‰). However, the Permian δ18O values (+7.6 and +15.3, average of +13.3‰) are generally higher by ca. 6.2‰ compared to the Buntsandstein data (4.8–10.1‰, average +7.1‰). Such a variation is interpreted as the result of mesodiagenetic pore fluid changes. The extensive dickitisation of kaolinite is attributed to increased hydrogen ions resulting from maturation of organic matter. The vitrinite reflectance of organic matter and the modelled thermal history suggest a maximum burial of 3400 m, accomplished 70 Ma ago. The Permo‐Triassic reached the gas window shortly before major uplift, at 65 Ma, when further maturation and hydrocarbon expulsion ceased.