Source Rock Characteristics Research Articles

RockFlow: Fast Generation of Synthetic Source Rock Images Using Generative Flow Models

Image-based evaluation methods are a valuable tool for source rock characterization. The time and resources needed to obtain images has spurred development of machine-learning generative models to create synthetic images of pore structure and rock fabric from limited image data. While generative models have shown success, existing methods for generating 3D volumes from 2D training images are restricted to binary images and grayscale volume generation requires 3D training data. Shale characterization relies on 2D imaging techniques such as scanning electron microscopy (SEM), and grayscale values carry important information about porosity, kerogen content, and mineral composition of the shale. Here, we introduce RockFlow, a method based on generative flow models that creates grayscale volumes from 2D training data. We apply RockFlow to baseline binary micro-CT image volumes and compare performance to a previously proposed model. We also show the extension of our model to 2D grayscale data by generating grayscale image volumes from 2D SEM and dual modality nanoscale shale images. The results show that our method underestimates the porosity and surface area on the binary baseline datasets but is able to generate realistic grayscale image volumes for shales. With improved binary data preprocessing, we believe that our model is capable of generating synthetic porous media volumes for a very broad class of rocks from shale to carbonates to sandstone.

Production Allocation: Rosetta Stone or Red Herring? Best Practices for Understanding Produced Oils in Resource Plays

The production of crude oil from resource plays has increased enormously over the past decade. In the USA, around 63% of total output in 2019 was from unconventional production. The major unconventional plays in the USA (e.g., Permian Basin, Anadarko Basin, Eagle Ford, etc.) have become some of the world’s largest oil producers. However, unlike “conventional” exploitation, the target zones in unconventional systems are generally the source rocks themselves or adjacent strata and require numerous horizontal wells and stimulation via hydraulic fracturing to meet production targets. In order to maximize production, operators have developed various well stacking methods, all of which require some form of monitoring to ensure that well spacing is optimized and fluid production is not being “stolen” from adjacent formations, thereby reducing the production potential in associated wells. This necessity, amongst other geochemical considerations related to source rock characterization, has resulted in the expansion of “production allocation” and “time lapse geochemistry” methods. These methods were initially developed for conventional production decades ago, but have since been adapted to unconventional systems. However, the direct applicability of this method is not straightforward and numerous considerations need to be taken into account, foremost among which are: (1) “What defines your end-members?” (2) “Are these end-members valid across a meaningful development area?” and (3) “What is the most appropriate use of geochemistry data in these systems?”. Reservoir geochemistry studies, which include both “time lapse geochemistry/production monitoring” and “production allocation”, are valuable geochemical methods in unconventional plays but need to be used appropriately to provide the cost savings and business direction that operators expect. In this paper, we will discuss a number of case studies, both theoretical and natural, and outline the important factors which need to be considered when designing a reservoir geochemistry study and the common pitfalls which exist. The case studies and best practice approach discussed are designed to highlight the power and flexibility of geochemical data collection methods, integration with the operator’s knowledgebase, and other analytical methods to customize the program for individual development programs. Emphasis is placed upon developing robust and applicable fluid relationships from geochemical data and evidence for statistically significant changes through time.

Local high-salinity source rock and origin of crude oil in the xianshuiquan structure in the northwestern Qaidam Basin, China

Despite its importance as an oil-bearing structure in the northwest Qaidam Basin, the development characteristics of source rocks and the origin of crude oil in the Xianshuiquan structure have not been clarified. Based on total organic carbon, extracted chloroform bitumen “A”, kerogen maceral, vitrinite reflectance, light hydrocarbon, biomarker compositions and seismic profiles, comprehensive analyses are performed on the origin and accumulation of crude oil in the Xianshuiquan structure. The results show that: 1) unlike the conclusions of existing research in the northwest Qaidam Basin, the Upper Youshashan (N21) member of the Xianshuiquan structure developed a set of high-salinity source rocks with a hydrocarbon generation capacity; 2) the crude oil in the shallow members (above the Lower Youshashan (N1) formation) of the Xianshuiquan structure originated from the N21 high-salinity source rock that developed locally in the Xianshuiquan structure, rather than from the generally believed N1 source rock; 3) two sets of fault systems were developed in the Xianshuiquan structure and formed two types of petroleum system, deep and shallow, and the crude oil generated from the Upper Ganchaigou (E32) and N1 source rocks did not migrate into the shallow members for accumulation. 4) The light hydrocarbons of crude oil are lost seriously and the preservation conditions of crude oil in the Xianshuiquan structure are poor. According to the above results, the hydrocarbon accumulation model of the Xianshuiquan structure is established, and it is proposed that the deep members of the Xianshuiquan structure have considerable exploration and development prospects. These results are of great significance to the exploration and development of the northwestern Qaidam Basin.

Integration of 1D and 3D modeling schemes to establish the Farewell Formation as a self-sourced reservoir in Kupe Field, Taranaki Basin, New Zealand

Along with conventional methods, this paper proposed a method in which 1D and 3D models are integrated to identify the self-sourced reservoir potential of the Farewell Formation in the Kupe Gas Field within the Taranaki Basin, New Zealand. Source rock characteristics were evaluated at both field and basin scales by investigating source rock maturity, type of organic matter, and hydrocarbon generation potential by rock pyrolysis, using Rock-Eval 2 and 6. The 1D thermal and burial history model established the rate of sedimentation and thermal history of the Kupe 4 well. Reservoir characterization at field-scale was determined by seismic interpretation, well log analysis, and 3D structural and petrophysical models. The sediments of the Farewell Formation contain types II–III (oil/gas prone) and type III (gas prone) and have fair-to-excellent generation potential. The oxygen and hydrogen indices ranged from 3 to 476 mg CO2/g TOC and 26 to 356 mg HC/g TOC, respectively, whereas the thermal maturity determined by vitrinite reflectance values ranged between 0.3% and 0.72%, indicating that the Farewell Formation is in immature-to-mature hydrocarbon generation stage. Thus, Farewell Formation was verified to be a good source rock. Additionally, structural interpretations demonstrated the structural complexity of an extensional and contractional regime within the reservoir package. Multiple faults indicated a good reservoir property there with a trapping mechanism as well as migration paths. A well-log-based petrophysical analysis established the presence of up to 70% hydrocarbon saturation within the pore spaces of Farewell sandstones. The 3D models confirmed that the Farewell Formation has significant sand zones and hydrocarbon-saturated zones, thereby proving its very good reservoir characteristics. It has been proved that the 1D and 3D structural schemes, integrated with geological techniques, was vital in identifying the Kupe Field as a self-sourced reservoir.

Evaluation of hydrocarbon source rock potential: Deep marine shales of Belaga Formation of Late Cretaceous-Late Eocene, Sarawak, Malaysia

In the Sibu-Tatau region of Sarawak, the Belaga Formation (Late Cretaceous- Late Eocene turbidites) is interpreted in relation to a submarine fan model deposited in the extinct ocean basin of the proto-South China Sea. A number of clastic rocks, which include sandstone, siltstone, mudstone, and black shale, define the formation. While it is considered one of the Rajang group's extensive and well-studied formations, yet no comprehensive studies have been carried out on the shales in Sarawak, Malaysia, to interpret their importance as a source rock to oil and gas fields. The present study highlights the prominent lithofacies in addition to the detailed source rock characterization of each member of Belaga Formation to discuss the potential source rock intervals present in these Cretaceous to Eocene rock units. Four major types of shales and mudstones facies were observed in the field, i.e. (i) Variegated colored shale facies (VSF), (ii) Black “Papery” shale facies (BSF), (iii) Gray to black mudstone facies (GMF), (iv) Silty/sandy shale facies (SSF). They show hemipelagic settling in a calm environment to turbiditic deposition at levees as well as distal lobe depositional environment. In this study primary geochemical studies such as Rock-Eval pyrolysis and Total Organic Carbon (TOC) analysis were used to classify the thermal maturity, organic matter richness, and kerogen type of the studied shales. Forty-six selected shale samples were studied from the formation, including samples from members of the Layar (Upper Cretaceous), Kapit (Paleocene to Early Eocene), Pelagus (Early to Middle Eocene), Metah (Middle to Late Eocene) and Bawang (Eocene). The shales of Belaga Formation typically display low to moderate source rock potential, which is obvious by low TOC contents between 0.14 wt% and 7.22 wt% (average of about 2.97 wt%) and show a wide range of maturity (immature to over mature) evident from very low to very high Tmax values ranging from 293 °C to 610 °C. The results show that the kerogen is of type IV, with some units can be potential sources of gas.

Source rock characterization of the upper Barremian, Albian and Cenomanian–Turonian organic-rich strata outcropping in Oued Bazina area, NE of Thibar diapir: Northern Tunisia

Rock-Eval pyrolysis, total organic carbon (TOC) determination and gas chromatography-mass spectrometry (GC-MS) analysis were performed on samples from outcrop sections of the upper Barremian (M’Cherga Formation), Albian (Fahdene Formation) and Cenomanian–Turonian (Bahloul Formation) in the Oued Bazina area located in the NE of the diapiric structure of Thibar, northern Tunisia. The upper Barremian and Cenomanian–Turonian organic-rich strata display high TOC values with a mean of 3.39% and 2.82%, respectively, while the Albian succession deposits exhibit TOC values lesser than 2%. The half-graben structures developed at these epochs have acted as restricted mini-basins favouring the water stagnation, the accumulation and the preservation of the organic matter and consequently the development of locally euxinic conditions in the bottom waters. The generative petroleum potential (S1 + S2) of the upper Barremian and Cenomanian–Turonian studied organic-rich strata is good to very good and appears to be moderate for the Albian organic-rich deposits. The n-alkane distributions of the Cretaceous source rocks are typical for a marine planktonic origin. The Pristane/Phytane ratio indicates a sub-oxic depositional environment for the upper Barremian and Albian successions and a sub-oxic to anoxic environment for the Cenomanian–Turonian organic-rich strata. Regarding the maturity degree of the three studied organic-rich strata, only the upper Barremian source rock presents a high maturity level with Tmax values ranging from 441 °C to 448 °C, which indicates that the deposits have been deeply buried and consequently have generated hydrocarbons that have been recognized in the studied oil seep. The integration of our results with available data of Tmax values on other outcrops in the salt dome zone allowed drafting a maturity trend of the studied source rocks. A general northeast–southwest trend of maturity increase is observed with Tmax values varying from 436 to 446 °C.

Integrated isotopic and organic geochemical constraints on the depositional controls and source rock quality of the Neogene Kalamaki sedimentary successions (Zakynthos Island, Ionian Sea)

This study investigates the oxygen and carbon (δ18O, δ13C) stable isotope ratios, as well as the organic geochemical features of the 146-m-thick composite Kalamaki section located in the southwest margin of the Hellenic Fold and Thrust Belt (Zakynthos Island). The section includes Late Miocene–Pliocene pre-evaporitic, evaporitic, and post-evaporitic deposits. The obtained bulk geochemical data (Rock–Eval II, bitumen extraction, and fractionation) and biomarker compositions indicate poor–fair source-rock potential predominantly promising for gas production. TOC values indicate the presence of samples that might be of slight interest (0.50–0.95%) in the evaporitic interval and samples that are worthy of further investigation (up to 1.31%) in the pre-evaporitic sequence. The organic matter type (type III kerogen), along with the presence of plant remains (leaves) in the studied deposits reflect the mainly terrestrial origin of the organic material. Tmax and Production Index values further indicate that most of the sediments (138 out of 195 samples) are immature for oil generation and were not under high temperature conditions during burial, whereas 29 of them correspond to the mature oil stage. Oil generation requires deeper burial, which may have occurred offshore in the Ionian Sea. A marine paleoenvironment is indicated that received organic material from both marine and terrigenous sources. Isotopic values imply influence of continental fresh-water inputs in a high salinity, evaporative depositional setting. Furthermore, our findings provide evidence that the climate has favored the development of these source rocks by triggering relative sea-level fall, which in turn enhanced the preservation of organic matter by increasing sea-water salinity and suppressing carbonate deposition.

Organic geochemistry indicates source-rock characteristics and hydrocarbon potential: A case study from Early Cretaceous Sembar Formation, southern Indus Basin, Pakistan

Shale samples from the Early Cretaceous Sembar Formation were selected from a well in the southern Indus Basin, Pakistan, and were analyzed for geochemical parameters. The study investigates the source-rock characteristics and hydrocarbon-generation potential indicated by organic richness, organic-matter type, and thermal maturity. The high values of total organic carbon (TOC) content of the Sembar shales indicate favorable source-rock characteristics. The shale samples analyzed in this study have hydrogen index (HI) values in the range 43–238 mg HC/g TOC and oxygen index (OI) values in the range 14–151 mg CO2/g TOC. Accordingly, the organic matter is mainly type III, which is consistent with high amounts of terrestrial organic matter. The dominant presence of type III kerogen suggests mainly gas generation. According to geochemical-maturity indicators, the organic matter in the analyzed Sembar shale is thermally mature, having reached an early peak-window, but commercial amounts of oil and/or gas have not yet been generated. Therefore, further petroleum exploration at depth in the southern Indus Basin, mainly for gas production, is recommended.

Geochemical characterization of hydrocarbon source rocks of the Triassic-Jurassic time interval in the Mandawa basin, southern Tanzania: Implications for petroleum generation potential

Abstract Triassic to mid-Jurassic core samples of the Mandawa basin, southern Tanzania (western coast of the Indian Ocean), were geochemically analyzed in order to constrain source rock potentials and petroleum generation prospects of different stratigraphic formations within the coastal basin complex. The samples were collected from the Mihambia, Mbuo and Nondwa Formations in the basin. Geochemical characterization of source rocks intersected in exploration wells drilled between 503 to 4042 m below surface yielded highly variable organic matter contents (TOC) rated between fair and very good potential source rocks (0.5 to 8.7 wt%; mean ca. 2.3 wt%). Based on bulk geochemical data obtained in this study, the Mandawa source rocks are mainly Type I, Type II, Type III, mixed Types II/III and Type IV kerogens, with a predominance of Type II, Type III and mixed Type II/III. Based on pyrolysis data (Tmax 417 to 473oC; PI = 0.02 to 0.47; highly variable HI = 13 to 1 000 mg/gTOC; OI = 16 to 225 mg/g; and VR values of between 0.24 to 0.95% Ro) we suggest that the Triassic Mbuo Formation and possibly the mid-Jurassic Mihambia Formation have a higher potential for hydrocarbon generation than the Nondwa Formation as they are relatively thermally mature.

Geochemical and palynological characteristics of the Paleogene source rocks in the Northeastern Laizhouwan Sag, Bohai Bay Basin, China: Hydrocarbon potential, depositional environment, and factors controlling organic matter enrichment

The Northeastern Laizhouwan Sag (NLS) is a marginal sag in the Bohai Bay Basin, China. Paleogene source rocks from 3 wells (K-a, K-b and K-c) in this region, i.e., the third to the first member of the Shahejie Formation (Es3, Es2, and Es1), and the third member of the Dongying Formation (Ed3) were investigated for their petroleum potentials and depositional environments using geochemical and palynological methods. Among these members, the Es3 and Es1 members hold considerable hydrocarbon potential, while the rest are relatively fair. Although there are variations between the wells, the organic matter (OM) in the Es3 member is primarily composed of low mature or mature type I-II1 kerogen, which were primarily contributed by lower aquatic organisms and prokaryotes. During the Es3 stage, saline, stratified, and anoxic bottom water prevailed in the K-a well, while freshwater and weak reducing conditions dominated the K-b well. The OM in the Es1 member was contributed more by lower aquatic organisms than that in the Es2 member, but both are primarily composed of types II1-II2 kerogen; further, OM in the Es2 member is low mature, while that for the Es1 member ranges from immature to low mature, and higher maturity is expected in deeper buried places for the two members. Saline and anoxic bottom water prevailed during the both Es2 and Es1 members. Compared with other members, noticeable terrigenous OM was deposited during the Ed3 stage, which is dominated by immature type II2 kerogen. Lower salinity and weak reducing depositional conditions occurred in the Ed3 member. OM enrichment in the Es3 member was mainly determined by primary productivity, while that of the K-a well was also enhanced by the anoxic bottom water condition. The accumulations of OM in other members are speculated to have been controlled by the deposition rate.

Total organic carbon (TOC) enrichment and source rock evaluation of the Upper Jurassic-Lower Cretaceous rocks (Barents Sea) by means of geochemical and log data

The Barents Sea is a typical example of a multiple sourced hydrocarbon system, with several gas and oil fields. Previous studies have suggested a gas and oil-prone character of the source rocks, but a lack of success in oil discoveries characterizes this area. In this work, the geochemical characterization of source rocks using well data from six exploration wells in the south-western part of the Barents Sea is presented. We studied the Upper Jurassic-Lower Cretaceous Knurr, Hekkingen and Fuglen Fms. mainly formed by shales and mudstones. Here, the Passey’s method is applied to characterize the geochemical properties and organic matter of these formations by estimating total organic carbon content (TOC), the quantity of thermally generated hydrocarbons (S2), and hydrogen index (HI). Shale volume was also estimated to check the reliability of the calculated parameters. High shale volume values were found in all the formations, which are generally around 0.8 (volume fraction), indicating a predominance of shaly/muddy lithologies. However, some interbedded sandstones and siltstones are present, together with thinner dolomite and limestone layers. Our results show that Upper Jurassic source rocks such as Knurr Fm., which are often not object of geochemical studies, are mature and characterized by good organic carbon content. Good and very good organic carbon content are measured in the Fuglen and Hekkingen Fms., respectively. The hydrogen index suggests that all the source rocks are mixed gas-oil prone, with the Fuglen Fm. standing out as the most gas-prone between the studied formations. This study demonstrates that the Passey’s method can be an alternative to infer geological information when geochemical data are not available.

Passive continental margin segmentation of the marginal seas and its effect on hydrocarbon accumulation: A case study of the northern continental margin in South China Sea

Global continental marginal basins are often segmented and significantly impact hydrocarbon accumulation. The northern South China Sea is a marginal sea, in which several passive continental marginal basins have been developed. It is represented by the Pearl River Mouth Basin in the eastern part and the Qiongdongnan Basin in the western part, with rich oil and gas resources that exhibit significant differences in hydrocarbon accumulation. However, the impacts on hydrocarbon accumulations due to various segmentations have rarely been discussed. Based on the systematic interpretation of seismic data, paleo-biological data, detailed thickness mappings, sedimentary facies mappings, analyses of organic geochemical characteristics of source rocks, reservoir formation characteristics, and hydrocarbon accumulation patterns, the tectonic segmentation and its effect on hydrocarbon accumulation in the two basins are discussed. The tectonic evolution in the northern part of the South China Sea was characterized earlier in east segmented and later in west segmented; this same pattern is always displayed, wherein the east segmentation occurs one phase earlier than the west segmentation. The tectonic segmentations caused differences in the source rocks, resulting in the formation of two sets of source rocks that were mainly developed in the east basin, namely: the lacustrine source rocks and marine–continental transitional facies coal-series source rocks. Meanwhile, only one set of the marine-continent transitional facies coal-series source rocks and terrestrial marine facies source rocks was developed in the west basin. The segmentations also yielded differences in the reservoir characteristics, even though both basins developed marine–continental transitional facies as well as delta and deep-water gravity flow sandstone reservoirs; meanwhile, the eastern basin developed continental fluvial reservoirs. The differences in hydrocarbon accumulation were controlled by segmentation; at the east basin, structural ridges in shallow layers, deep lithologic–stratigraphic traps, and bulges in sags affected the accumulations of oil and gas. Meanwhile, at the west Qiongdongnan Basin, coal-bearing delta systems produced the gas distributions along the margins of the central subsidence that was adjacent to the source rocks.

Geologic characterization of the type cored section for the Upper Cretaceous Austin Chalk Group in southern Texas: A combination fractured and unconventional reservoir

A rock-based geologic characterization was completed on a continuous core through the Austin Chalk Group section, an active exploration target in southern Texas. Because this core (located in the Pearsall field) is continuous and includes both lower and upper contacts, it can be used as the type cored section for the southern Texas Austin Chalk. Several general lithofacies are defined. Two lithofacies (lithofacies 1 and 2) are highly bioturbated and have low to moderate organic matter content and are poor to moderate source rocks. Two other lithofacies (lithofacies 3 and 4) are laminated, lithofacies 3 containing some burrows and lithofacies 4 containing no burrows. Both lithofacies are good source rocks. Organic matter in the laminated lithofacies 3 and 4 and some of the organic matter in the bioturbated lithofacies 2 are dominated by type II kerogen, suggesting the section can be self-sourcing. A general trend is observed whereby lithofacies that were deposited under more-oxygenated conditions increase in abundance up section and is related to a decrease in total organic carbon and, hence, source-rock quality. The primary oil and gas production is from fractures with possible later production from the nano- to microporous matrix after pressure drawdown. Pore types are predominantly interparticle nano- to micropores and lesser intraparticle nanopores as defined by Loucks et al. (2012). Porosity is less than 8%, and permeability is less than 0.05 md and ranges down into the nanodarcy range. The type cored section adds to the understanding of the southern Texas Austin Chalk by providing a geological description of lithofacies, stacking patterns, source-rock quality characterization, and reservoir quality. The type core can be used as a comparison section to other cored sections of the Austin Chalk.

Biomarker assessment of oil biodegradation, water washing, and source rock characteristics of oil seeps from the Foothill Zone along the Tigris River, Northern Iraq

Oil seep samples from the Foothill Zone of northern Iraq were geochemically characterized to determine the level of biodegradation and water washing of the seeps and to determine the depositional environment (including sedimentary facies, oxicity, and organic matter type) of correlative source rocks. Eight samples from three seeps sites (Hammam Al-Alil, Qaiyarah, and Fat'ha) were investigated. Detailed saturated and aromatic biomarkers were analyzed using GC-FID and GC-MS, in addition to measurement of carbon isotopes and the sulphur content. Qaiyarah samples range from non-biodegraded to moderately biodegraded; whereas Hammam Al-Alil and Fat'ha samples are moderately biodegraded. The Hammam Al-Alil and Fat'ha samples are also affected by water washing. Biomarker, carbon isotope, and sulphur data suggest that these oil seeps contain oil expelled during the early oil window from carbonate source rocks of Jurassic age. Correlative source rocks were deposited in an anoxic marine environment. The most likely source rock candidates include the Sargelu, Naoklekan, and Chia Gara formations.

Depositional environment and thermal maturity of the coal-bearing Longtan Shale in southwest Guizhou, China: Implications for shale gas resource potential

Significant knowledge has been assembled on the marine Longmaxi Shale in the Sichuan Basin over the past ten years. However, the distribution of shale gas resources on the periphery of the Sichuan Basin and in other source rock formations are still not sufficiently understood. To improve our understanding on the depositional environment and thermal maturity, and their relevance to the source rock quality and shale gas potential of the thick, coal-bearing Longtan Shale, 36 organic-rich shale samples were selected from a single borehole located in the southwestern Guizhou Province for geochemical and petrographic analysis.Total organic carbon (TOC) contents are high with 7.7 wt% on average, reaching partly up to 28.21 wt%, while carbonate contents are low. Vitrinite reflectance (VRr) values and Rock-Eval Tmax temperatures range from 1.48 to 1.84% and 482 to 583 °C, respectively, indicating a high thermal maturity which is in accordance with aromatic molecular parameters. The remaining, present day hydrocarbon generation potential (Rock-Eval S2) is rather low due to the high maturity. Microscopic investigations further show that the organic matter in the rocks is mainly composed of higher land plant particles, present as large and poorly rounded vitrinite and inertinite particles indicating a rather short transport distance.TOC vs. total sulfur (TS) relationships as well as specific hydrocarbon ratios (e.g. pristane/phytane) and framboidal pyrite size distributions indicate a variable either marine or freshwater environment for the shales in the coal-bearing sequence and suggest that original kerogen was either type III or type II-III. Bottom water during deposition was probably oxygen depleted but not anoxic. High sedimentation rates can be assumed for the now 700 m thick, compacted sequence, favorable for the preservation of organic matter.Overall, the present results are in accordance with previous studies of the Longtan Shale which initially had a high hydrocarbon (mainly gas) generation potential; furthermore the thickness of the formation is much larger in the here studied southwestern part of the Guizhou Province than in the previously studied northern parts.

Hydrocarbon generation and expulsion of Middle Jurassic lacustrine source rocks in the Turpan–Hami Basin, NW China: Implications for tight oil accumulation

In recent years, new oil reservoirs have been discovered in the middle Jurassic tight mixed rocks of the Turpan–Hami Basin. However, the generation potential of the J2q2 source rocks remains poorly understood. Petrographic, petrological, and geochemical analyses were carried out to assess the quality of the J2q2 source and reservoir rocks. The hydrocarbon generation potential method was utilized to evaluate the hydrocarbon generation and expulsion potentials. The results indicated that the rocks can be classified as high-quality source rocks with a relative lower degree of maturity. The hydrocarbon bearing zones are classified as tight reservoirs (average porosity of 5.90% and permeability of 0.18 mD) with an average pore throat radius >150 nm, which is higher than the cut-off pore-throat radius. The source rocks start to expel hydrocarbons when Ro% is 0.56%. Bulk hydrocarbon generation and expulsion intensities in the center of the study area were calculated with the values of 900 × 104 t/km2 and 400 × 104 t/km2, while the weights of these hydrocarbons were 48.8 × 108 t and 27.3 × 108 t, respectively. The tight oil reservoir-forming conditions are superior, and the hydrocarbon generation and expulsion intensities are more remarkable in controlling the tight oil distribution. This study provides an important example for the Jurassic source rocks in Western China, and indicates that middle Jurassic lacustrine source rocks deserve attention in future exploration.

Upper Cretaceous-Paleogene stratigraphy and development of the Mímir High, Vøring Transform Margin, Norwegian Sea

Transform margins represent strike-slip type of plate boundaries that form during continental breakup and initial ocean opening. They are often characterized by margin-parallel highs with exposed pre- and syn-rift sequences. The Vøring Transform Margin, offshore mid-Norway, initiated in the earliest Eocene during the opening of the NE Atlantic. Here, 2D seismic reflection data reveal a transform margin high, the Mímir High. The western flank of this undrilled structure is a kilometer-high escarpment where seismic reflections of pre-breakup age are truncated at the seafloor. The aim of this study was to recover seabed rock samples from the outcropping or shallowly buried sedimentary sequences to provide a geological tie to the regional seismic framework, thereby constraining the basin history and tectono-stratigraphic development. Seabed samples were successfully collected from 14 gravity core and Selcore stations and 10 ROV (remotely operated vehicle) sites along a 750 m high sampling profile, recovering clay, shales, sandstones and glacial dropstones. Biostratigraphy results revealed that the ages of the sedimentary rocks follow the stratigraphic order predicted by the initial seismic interpretation, with Upper Cretaceous sediments at the base and lower Eocene sediments at the top. The integrated interpretation shows that the Mímir High area, including parts of the outer Vøring and Møre basins and the proto-Jan Mayen Microplate Complex, were characterized by the deposition of late Campanian to early Maastrichtian, near coastal and shale-dominated sequences with poor source rock qualities. The early Paleocene samples indicate deep marine conditions that abruptly ended by rapid uplift of the Mímir High in the earliest Eocene. Finally, a reworked Pliensbachian palynomorph assemblage in potential early Eocene strata indicate the presence of exposed Mesozoic sequences in the vicinity of the Mímir High. We argue that some of the lower Eocene sediments where deposited within a hypothetical drainage system sourced from Greenland (Traill Ø or Jameson Land) and/or from the Jan Mayen Ridge prior to continental separation, and not the result of recent ice-rafting.

Regional hydrocarbon potential and thermal reconstruction of the Lower Jurassic to lowermost Cretaceous source rocks in the Danish Central Graben

The Danish part of the Central Graben (DCG) is one of the petroliferous basins in the offshore region of north-western Europe. The source rock quality and maturity is here reviewed, based on 5556 Rock-Eval analyses and total organic carbon (TOC) measurements from 78 wells and 1175 vitrinite reflectance (VR) measurement from 55 wells, which makes this study the most comprehensive to date. The thermal maturity is evaluated through 1-D basin modelling of 46 wells. Statistical parameters describ-ing the distribution of TOC, hydrocarbon index (HI) and Tmax are presented for the Lower Jurassic marine Fjerritslev Formation, the Middle Jurassic terrestrial-paralic Bryne, Lulu, and Middle Graben Formations and the Upper Jurassic to lowermost Cretaceous marine Lola and Farsund Formations in six areas in the DCG. For the Farsund Formation the source-rock richness is presented for selected stratigraphic sequences. The upper part of the Farsund Formation is immature in the southern part of the Salt Dome Province, and late oil mature in and near the Tail End Graben and in the Søgne Basin. The lower part of the Farsund Formation is immature in local areas, yet post-mature in the Tail End Graben and in the Salt Dome Province. The Lower and Middle Jurassic shales are gas-prone in most of the DCG. The depth of the oil window, as defined by a VR of 0.6% Ro, ranges between 2200 and 4500 m. The variations are ascribed to heat flow differences in the DCG and can be modelled by a simple depth model, which includes the thickness of the Cretaceous to Palaeo-gene Chalk and Cromer Knoll Groups. According to the model, a thick Chalk Group offsets the oil window to deeper levels, which likely can be attributed to the thermal properties of the highly thermally conductive chalk compared to the underlying less thermally conductive clays. The DCG is an overpressured basin, and high-pressure, high-temperature conditions are expected to occur deeper than 3.8 km except for the Feda and Gertrud Grabens where such conditions, due to generally lower tem-peratures, are expected to occur deeper than around 4.7 km.

Hydrocarbon potential and polycyclic aromatic compounds differences of Carboniferous-Permian coaly source rocks, Bohai Bay Basin: An implication for different sources of gas condensate and oils

This study investigates the characteristics of Carboniferous-Permian coaly source rocks in the Bohai Bay Basin, Eastern China, which provides new insights for understanding of hydrocarbon potential of Carboniferous-Permian coaly source rocks worldwide. A total of 37 samples comprising different types of the coaly source rocks were selected for the analysis of lithofacies, total organic carbon (TOC) and pyrolysis, organic petrology, fourier transform infrared spectroscopy (FTIR) and two-dimensional gas chromatography coupled with time-of-flight mass spectrometry (GC × GC-TOFMS). The results show that there are six types of coaly source rocks, including clarain, durain, inferior coal, carbonaceous mudstone, deltaic shale, and lagoonal shale. The clarain and the durain are with Type III-II and II-III kerogen and have high hydrocarbon potential (51–237 mg HC/g rock), while the others are with Type II-III and III kerogen and have low hydrocarbon potential. The high hydrocarbon generation potential of clarain and durain are mainly attributed to hydrogen-rich desmocollinite, cutinite, and sporinite in them. Variance in the abundance of methylfluorene (MF), fluorene (F), dimethylfluorene (DMF), methylphenanthrene (MP) and phenanthrene (P) among different types of coaly source rocks can reveal the genetic relationship between condensates and their source rocks. The condensate associated with shales presents relative low MF/F ratios but high MF/DMF ratios. The condensate associated with coals presents a series of low MF/DMF, MF/F and MP/P ratios. Natural gas and condensate that are associated with coals have been discovered in the Dagang Oilfield of the Bohai Bay Basin, indicating notable hydrocarbon potential of Carboniferous-Permian coaly source rocks in this area.

Organic geochemical characteristics, depositional environment and hydrocarbon potential of bituminous marls in Bozcahüyük (Seyitömer/Kütahya) Basin

In this study, the geochemical properties, sedimentation conditions and hydrocarbon potential of the bituminous marls, having quite rich organic carbon content (average 9.27% TOC), composed of gray-green colored, dominant marl lithology with marl-claystone intercalation in the Bozcahüyük (Seyitömer/Kütahya) Basin has been evaluated. In this context, Rock-Eval pyrolysis, Gas Chromatography (GC), Gas Chromatography-Mass Spectrometry (GC-MS) and Modified Fischer Assay (MFA) analyses of the samples taken from the study area were performed and their organic facies have been evaluated. The marls have an excellent source rock characteristics, and include kerogen predominantly as Type I and rarely as Type II. The precipitation of organic matter took place under reducing anoxic redox conditions where oxygen was limited. Analysed samples contain terrestrial phytoclasts and palynomorphs as well as freshwater algae indicating Type-I kerogen such as Botryococcus braunii. Organic geochemical data show that the study area is deposited in the “AB” organic facies continental-marine transition zone. Carbon preference index (CPI), C₂₇, C28 and C29 steran abundance distribution of the samples as well as presence of Gamesaran as a salty environment indicator indicates that the lake enironment has been under marine environment influence from time to time and thereforethe study area have lagoon character. The average of the Tmax values of analysed samples is 432 °C and it was determined that the bituminous marls in the region could not produce conventional petroleum due to their immaturity. However, it has been evaluated that these marls have the potential to produce synthetic petroleum as the kerogen types are dominantly Type-I, TOC and HI contents are high, as well as the analyzed samples have an average of 12.60% (133 L / ton) MFA oil content.