Active Source Rocks Research Articles

Integrating strike-slip tectonism with three-dimensional basin and petroleum system analysis of the Salinas Basin, California

The Salinas Basin is a strike-slip basin in central California with stratigraphy dominantly composed of Miocene Monterey Formation. Despite a long history of oil production, aspects of petroleum system development in the basin remain poorly understood. Of the seven main oil fields, one—San Ardo field—has produced more than 500 million bbl of oil or 99% of all oil found in the basin. The evolution of this basin was profoundly influenced by strike-slip movement on the Rinconada Fault, which bisected the depocenter beginning circa 15 Ma. To address the influence of strike-slip motion on petroleum system development, we constructed a three-dimensional (3-D) basin and petroleum system model that incorporates strike-slip displacement. Seismic reflection profiles from a 3-D survey reveal four main tectonic stages that correspond to events in petroleum system evolution. Petroleum generation from type II kerogen source rock began circa 11 Ma, approximately 4 m.y. after strike-slip faulting began to offset a once-contiguous sedimentary depocenter. Two separate petroleum provinces—an eastern one and a western one—developed, and the fault zone likely was a conduit for petroleum, if nonsealing. Most accumulated petroleum was derived from the eastern pod of active source rock because of greater sedimentary burial east of the fault. Our model roughly replicates the skewed distribution in oil-field size. Factors controlling field size distribution include trap size and connectivity to source.

A Review of the Geology and the Petroleum Potential of the Cretaceous Tano Basin of Ghana

This is a review of the geology and the petroleum potential of the Cretaceous Tano Basin of Ghana, one of the coastal sedimentary basins in Ghana. It is located on the West African Transform Margin. It initially evolved as a pull-apart basin and later became modified by wrench faulting in the Cretaceous period. It has been known to have potentials for hydrocarbons, as indicated by oils seeps observed in the late 19th century. The presence of active source rocks deposited in the Albian to Cenomanian as well as the Turonian charges the Upper Cretaceous reservoirs sealed by widespread marine shales, as well as faulted traps and pinch-outs, has spurred exploration efforts. Thus, as expected, commercial discoveries of oil and gas have been made in the Tano Basin which evidently has become a ‘hot cake’ in deepwater exploration, even though the ultradeep water could show even more exciting hydrocarbon plays.

Hydrocarbon-generating potential of the Eocene Thebes Formation, Gulf of Suez: 1D basin modeling as a supplementary tool for source rock evaluation

The present work provides high-resolution modeling of the thermal maturation of the Eocene Thebes Formation using a multi-1D approach. The model focuses not solely on the thermal maturity but also on timing of hydrocarbon generation (primary generation and secondary cracking), adsorption by organic matter, and expulsion. The time-lapse conceptual model was developed using well log data, geochemical analyses, and composite logs. The stratigraphic sequence of the Belayim Marine oil field was subdivided into a time series based on the tectonic framework of the Gulf of Suez. An elevated basal heat flow has been assigned throughout the rifting phases and basin evolution. The simulation developed for seven wells reveals variations in burial, thermal history, and accordingly the thermal maturity. The predicted thermal maturity ranges from immature to mature with a different tendency to generate hydrocarbons (both primary generation of oil and/or gas secondary cracking) dependent on kerogen type, basin development, and burial history. Hydrocarbon generation (oil) starts after the Messinian Time Event during the deposition of the Post-Zeit Formation. Hydrocarbon generation was related to burial rather than basin evolution for the 113-M-27, BM-23, BM-65, and BM-70 wells. Conversely, generation correlated principally to basin development particularly Messinian Time Event for the 113-M-34 well. Expulsion occurred subsequent to generation of thermogenic gas (secondary cracking of generated oil). It is not possible to investigate the relationship between the production index and thermal maturity as a consequence of expulsion that reduced the S1 values. The different levels of thermal maturity (potential, active, and effective source rock) allow for the differentiation of regions of potential hydrocarbon accumulation that were charged from the Thebes Formation.

Petroleum geochemical characterization of Albian-Oligocene sequences in the Campos Basin: “Case study: Eastern Marlim oilfield, offshore, Brazil”

The current research was performed in the eastern portion of the Marlim oilfield to identify the hydrocarbon-generating potential of the Albian-Oligocene sequences (Macaé Group, Ubatuba and Carapebus formations) in the Campos Basin, Brazil. On the basis of petroleum geochemical proxies, an integrated approach was developed using source rock characterizations to establish the distribution of source rock properties, such as organic matter content, hydrocarbon-generating potential, thermal maturity and stratigraphic thickness. The outcomes of a comprehensive petroleum geochemical characterization were integrated with cuttings and core sample descriptions, biostratigraphic controls, well log analyses and 2-D/3-D seismic interpretations. Our results reveal that for the Albian-Oligocene deposits, the key geochemical properties required to develop hydrocarbon source kitchens converge in specific locations, demonstrating a variable hydrocarbon potential ranging from poor to excellent and suggesting the existence of local generation pods in the central and principally northern portions of the research area. The accumulation and preservation of the organic matter were influenced by the paleo-topography and tectonic controls, and the lowest concentrations of organic carbon were attributed to significant siliciclastic dilution taking place mostly toward the middle and southern portions of the Eastern Marlim oilfield. Lateral variations in both the lithofacies and organic facies are the main conditions controlling the behavior of the petroleum potential in the investigated sediments. Our results indicate that the Macaé Group has sufficient source-rock potential, maturation patterns, and hydrocarbon-generating potential to be considered as an active source rock in the Eastern Marlim oilfield, where the petroleum geochemical properties converge and are adequate to generate hydrocarbon compounds. In addition, the Ubatuba and Carapebus formations are also likely to generate oil and/or gas, but due to their relatively low maturity, it is difficult to establish that these rocks can be active source rocks in the study area.

Hydrocarbon source rock evaluation of the Lower Cretaceous system in the Baibei Depression, Erlian Basin

The K1s, K1d, K1t, and K1a Formations are potential source rock intervals for hydrocarbon formation, all of which are part of the Lower Cretaceous system in the Baibei Depression in the Erlian Basin in China. However, no well has found oil flow because the hydrocarbon-generating potential of the source rocks has not been comprehensively evaluated. Based on organic geochemical and petrological analyses, all the source rocks possess highly variable total organic carbon and S1 + S2 contents. Total organic carbon and S1 + S2 contents indicate that the K1a2 Formation through the K1d1 Formation are source rocks that have fair to good generative potential and the K1d2 Formation through the K1s Formation are source rocks that have good to very good generative potential. The organic matter in the K1a2 Formation is dominated by Type I and II kerogen; thus, it is considered to be oil prone based on H/C versus O/C plots. Most of the analyzed samples were deposited in reducing environments and sourced from marine algae; thus, they are oil prone. However, only two source rock intervals were thermally mature with vitrinite reflectance values in the required range. Hydrocarbon-generating histories show that the K1t and K1a2 intervals began to generate hydrocarbons during the depositional period of the K1d2 and K1d3 Formations, respectively, and stopped generating hydrocarbons at the end of the depositional period of the late Cretaceous. Therefore, the main stage of hydrocarbon migration and accumulation was between the depositional period of the K1d2 and K1s Formations, and the critical moment was the depositional period of the late K1s Formation. The generation conversion efficiency reached approximately 55% in the K1a2 Formation and 18% in the K1t Formation at the end of the Cretaceous sedimentary stage. In general, the effective oil traps are those reservoirs that are near the active source rock in the generating sags in the Baibei Depression.

Characteristics and Hydrocarbon Generation of the Marine Source Rock of the Upper Oligocene Zhuhai Formation in the Baiyun Sag, Pearl River Mouth Basin, South China Sea

The Baiyun Sag, located in the northern South China Sea, is rich in oil and gas. The marine mudstone in the Upper Oligocene Zhuhai Formation of the Upper Oligocene has not previously been considered as the main source rock and was thus selected for a thermocompression simulation experiment to verify its hydrocarbon generation potential. The experimental results were used to calculate the hydrocarbon generation kinetic parameters, and the hydrocarbon generation process of the marine mudstone was simulated. The mudstones of the Upper Oligocene Zhuhai Formation in the deepwater area of the Baiyun Sag are effective source rocks. The dark shallow marine mudstones of the Upper Oligocene Zhuhai Formation from well C generate hydrocarbons at a rate of 179.79 kg/ton of total organic carbon. As a set of active source rocks, the Upper Oligocene Zhuhai Formation has reached the low mature to mature stage and mainly generates oil in the marginal areas of the Baiyun Sag, whereas they have reached a highly overmature st...

Characteristics and Genetic Mechanisms of Overpressure in the Depressions of Bohai Bay Basin, China

AbstractThe distribution and genetic mechanisms of abnormal pressures in the Bohai Bay Basin were systematically analyzed. Abnormal pressures are widely developed in the Bohai Bay Basin, primarily in the Paleogene E2s4, E2s3, Es1, and Ed formations. From the onshore area of the Bohai Bay Basin to the center of the Bozhong area, the top depth of the overpressured zone in each depression increases gradually, the overpressured strata in each depression gradually move to younger formations, and the pressure structure successively alters from single‐bottom‐ overpressure to double‐bottom‐overpressure and finally to double‐top‐overpressure. The distribution of overpressured area is consistent with the sedimentary migration controlled by the tectonic evolution of the Bohai Bay Basin, which is closely related to the hydrocarbon‐generation capability of active source rocks. The overpressured strata are consistent with the source‐rock intervals in each depression; the top of the overpressured zone is synchronous with the hydrocarbon generation threshold in each depression; the hydrocarbon generation capability is positively correlated with the overpressure magnitude in each formation. Undercompaction was the main mechanism of overpressure for depressions with fluid pressure coefficients less than 1.2, whereas hydrocarbon generation was the main mechanism for depressions with fluid pressure coefficients greater than 1.5.

Hydrocarbon Source Rock Potential of the Lacustrine Black Shale Unit, Mamfe Basin, Cameroon, West Africa

The potential for conventional and/or unconventional hydrocarbon exploration requires the presence of organic-rich, thermally mature rock units containing oil or gas-prone kerogen. Thick black, organic rich shale intervals are well exposed along roadside cuts and river banks at several localities in the eastern part of the Mamfe Basin. Earlier described as anoxic lake bottom deposits, these fine grained rocks constitute the probable pod of active source rock in this basin and belonging to the middle stratigraphic unit of the three that make up the basin’s sedimentary fill. Samples collected from representative outcrop sections (Etoko mile 21, Bachuo Ntai, and Satom Bridge) in the study area were subjected to geochemical analytic techniques; Total Organic Carbon (TOC), Rock-Eval Pyrolysis and Vitrinite reflectance (%Ro) values were calculated. TOC data obtained range from 1.06% to 16.10% indicating good to excellent hydrocarbon generative potentials, Rock-Eval Pyrolysis data plotted along Kerogen Types I, II and III with oil and gas generative potentials. 4 out of 9 samples fall within the oil window from the calculated %Ro while temperatures corresponding to the peak of kerogen pyrolysis (Tmax) and Production Index (PI) for the 9 samples range from 398oC to 463oC indicating that the organic matter (OM) are immature to post mature.The black shale unit of this part of the basin therefore contains very high amounts of good to excellent quality of thermally matured organic matter which can produce and expel oil and gas respectively.

OIL FAMILY TYPING, BIODEGRADATION AND SOURCE ROCK AFFINITY OF LIQUID PETROLEUM IN THE DANISH NORTH SEA

Variations in liquid petroleum compositions in the Danish Central Graben and Siri Fairway, North Sea, demonstrate the presence of several active source rock facies. To address this issue in detail, a total of 213 samples of liquid petroleum from the Danish Central Graben and the Siri Fairway were typed to eight main oil families and three sub‐families based on characteristic geochemical properties and principal component analysis (PCA). Comparison with source rock extract data made it possible to suggest correlative source rocks for each oil family together with the source rock depositional environments. The main oil families are: 1(B), 2(B), 3a(B), 3b(B), 4(B‐D/E), 5(D/E‐B), 6(D/E‐F) and 7(A), where the capital letters in brackets refer to the organofacies types of Pepper and Corvi (1995), thus directly linking the oil family type to the source rock facies. Oil families 1(B), 2(B), 3a(B) and 3b(B) were charged from marine shales (principally the Upper Jurassic Farsund Formation); oil families 4(B‐D/E) and 5(D/E‐B) are mixed petroleums with both terrigenous and marine components; oil family 6(D/E‐F) was charged from Middle Jurassic coaly units; whereas oil family 7(A) was charged from a carbonate source (Zechstein dolomites). Family 7(A) has only been documented in the form of oil stains. The most widespread oil family is 3a(B), sourced from Upper Jurassic marine shales. Charging from different organofacies is indicated by oil family 3b(B), which was derived from parts of the same shale succession which were more terrigenous‐influenced and possibly slightly more oxic; and families 2(B) and 1(B), which were sourced from more organic‐rich, anoxic parts of the shales. Mildly biodegraded oils (Level 1 to 2) appear mainly to occur in the central to southern parts of the Danish Central Graben.

Could the conventionally known Abu Roash “G” reservoir (upper Cenomanian) be a promising active hydrocarbon source in the extreme northwestern part of Egypt? Palynofacies, palaeoenvironmental, and organic geochemical answers

In different areas of the Western Desert of Egypt, the Abu Roash “G” Member exhibits either a reservoir or source affinity. Thus, thirteen cutting samples covering the Abu Roash “G” Member were selected from the Nest-1A well at Matruh Basin to investigate its hydrocarbon source potential. Palynological age dating of the section that is calibrated with foraminifera and ostracodes enabled a proper identification of the “G” Member. Detailed analysis of the vertical distribution of particulate organic matter of this member shows two palynofacies types. PF-1 reflects an outer middle shelf depositional environment of prevailed reducing (suboxic-anoxic) conditions for the organic-rich shales of the lower “G” Member (samples 1–8). While, PF-2 reflects a minor regression that resulted in deposition of another organic-rich shales of the upper “G” Member (samples 9–13) in an inner middle shelf setting under the same prevailing reducing (suboxic-anoxic) conditions.Organic geochemical analysis reveals good to very good potential of the “G” Member as a hydrocarbon source rock (1.8–2.41, avg. 2.15 total organic content wt %). It also shows good to very good petroleum potential (PP: 4.8–11 , avg. 8 mg HC/g rock). Pyrolsis and palynofacies analyses show kerogen type II for the lower “G” Member (samples 1–8), which is characterized by high Hydrogen index (HI: 396 and 329 mg HC/g TOC at depths 1500 and 1560 m) and very high dominance of oil-prone material (amorphous organic matter “AOM”, marine palynomorphs, and sporomorphs) and very rare occurrence of gas-prone material (brown phytoclasts). The upper “G” Member (samples 9–13) shows kerogen type II-III, which is characterized by a lower HI value of 213 mg HC/g TOC at depth 1340 m and it contains fewer amounts of gas-prone material and relatively lower AOM and marine palynomorphs in comparison to the upper “G” Member. Maturation parameters Tmax (430–433 °C), production index (PI: 0.1 mg HC/g rock), and thermal alteration index (TAI: 2+) indicate the lower “G” Member has already entered the early oil-window kitchen, and it is expected to produce oil. The upper “G” Member is expected to produce only oil with no gas shows, because it is marginally mature (Tmax 426 °C, PI 0.2, TAI 2). The source potential index (SPI: 5.3 t HC/m2) of the “G” Member shows it as currently generating moderate quantities of oil in the area of Nest-1A well.Consequently, the organic-rich shales of the “G” Member are suggested here as a promising, active oil source rock in that extreme northwestern part of the Western Desert of Egypt. However, for commercial oil recovery from the Abu Roash “G” Member, it is highly recommended to explore the depocentre of Matruh Basin at about 150 km east the Nest-1A well.

Thermal maturity history reconstruction and hydrocarbon generation/expulsion modeling of the syn-rift Rudeis and Kareem source rocks in the Red Sea Rift Basin, Sudan

Modeling of maturity and hydrocarbon generation has been performed on syn-rift Rudies and Kareem source rocks from four wells along the Sudanese Red Sea Basin to examine their hydrocarbon generation and expulsion history. The reconstruction of the burial and thermal history curves show that the Red Sea evolved initially as a rift basin during late Eocene-Oligocene that accelerated considerably during early Miocene with strong regional uplift in the late Miocene. Heat flow models show that the present-day heat flow in the Sudanese Red Sea Basin varies from 72 to 109 mW/m2. The great differences in the present-day heat flow values have been attributed to the regularly increasing geothermal gradient from margins to the east toward offshore, where the axial trough is the main source of the heat. The paleo-heat flow increased from Oligocene to Early Pliocene, reached peak heat flow values of approximately 103–107 mW/m2, since the main rifting occurred during Oligocene and lasted through the Early Pliocene. These in turn explain the high heat flow values reported in Oligocene to Early Pliocene, thus has a considerable influence on source rock maturation and hydrocarbon generation as quite younger rock is currently passing oil generation window. The modeled thermal history indicates that the syn-rift Rudies and Kareem source rocks were passed late oil generation stage and generated oils that converted to dry gas during late Miocene. The modeled hydrocarbon expulsion suggests that the Rudeis and Kareem are active source rock units and have probably completed all their potential hydrocarbon commenced since end of late Miocene time.

Chemometric recognition of genetically distinct oil families in the Los Angeles basin, California

The prolific Los Angeles basin in California may be the most petroliferous province on Earth per volume of sedimentary fill. However, because most exploration in the basin occurred prior to the advent of modern geochemical methods, genetic relationships among the various petroleum accumulations and their source rocks have remained speculative. A training set of 24 source-related biomarker and stable carbon isotope ratios for 111 non- or mildly biodegraded oil samples from the basin was used to construct a chemometric (multivariate statistics) decision tree. The decision tree allows genetic classification of additional oil or source-rock extract samples that might be collected. The decision tree identifies 6 tribes and a total of 12 genetically distinct oil families. The families have different bulk properties, such as API gravity and sulfur content, which were previously explained as resulting from secondary processes, including thermal maturity or biodegradation. However, the chemometric assignments are based on genetic properties that reflect distinct organofacies. The oil families occur in different locations and reservoir intervals in the basin, consistent with their origins from different organofacies of active source rock. The source-rock depositional environment for each oil family can be inferred using biomarker and isotope ratios. The samples show stable carbon isotope ratios for saturate and aromatic hydrocarbons that indicate different organofacies of Miocene marine source rocks. Tribes 1 and 2 straddle the central trough, mainly occur east of the Newport-Inglewood fault zone (NIFZ), and show evidence of proximal, clay-rich source rock deposited under suboxic conditions with elevated angiosperm input. Tribes 3–6 occur west of the NIFZ and show evidence of more distal, clay-poor source rock deposited under anoxic conditions. Geochemistry and stratigraphy of the oil tribes (1–6 below) suggest the following source-rock organofacies:

The source kitchen of the Niger Delta oils: case study on Nembe Creek E1.0 and the Kolo Creek E2.0 reservoirs

The source kitchen of a petroleum system is that part of the pod of active source rock which is mature and generates the petroleum that charges the reservoir rock. The location of the source kitchen of a petroleum system is vital to the explorationist, its knowledge fosters the prediction of migratory pathways and the migratory losses prior to present times, also estimates potential volume of accumulation. Hither to, mapping of the petroleum basins was based on total organic carbon (TOC), hydrogen index (HI) signatures and maturity history of the source rock and has been used as the basis to suggest locations of petroleum kitchens. In contemporary times, 4D seismic or 3D time lapse geochemistry had been used to suggest location of source kitchen. However, settled is the concept of lateral maturity gradients, implying that within reservoir scales of a kilometer to tens of kilometers, regional petroleum emplacement direction could be deduced from subtle changes in maturity of successive charges of petroleum into the reservoir. In this study, the sterane isomerization ratio (20S/20S + 20R αααC29) was used to determine the maturities of the hydrocarbons from various wells in the Kolo Creek and the Nembe Creek reservoirs. Subtle increases in maturities were observed to be in a NE–SW direction for the Kolo Creek reservoir and in a NW–SE direction for the Nembe Creek reservoir. The direction of increasing maturities relative to the location of the reservoirs could be extrapolated for both reservoirs towards offshore Gulf of Guinea; this is invariably the direction of location of the source kitchen for the Niger Delta oils.

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.

Geologic evolution of the Iraqi Zagros, and its influence on the distribution of hydrocarbons in the Kurdistan region

Whereas the vast majority of discovered hydrocarbon reserves in Iraq reside in Cretaceous and Cenozoic reservoirs, numerous oil and gas fields have been discovered recently in deeper Jurassic and Triassic reservoirs in the Kurdistan region of Iraq. This study presents a Middle–Upper Jurassic thermal maturity map for the Kurdistan region of Iraq and demonstrates that regional first-order trends in Jurassic source rock maturity show a close correlation to the spatial distribution of oil gravities within the overlying Jurassic (and Cretaceous) reservoirs. This distribution is consistent with compartmentalization of the active source rock kitchens due to Zagros folding, resulting in relatively short-distance migration and charge of the anticlinal structures from the adjacent synclinal lows. The thermal maturity map confirms relatively low maturity over the Mosul high, where the Cretaceous and Cenozoic section overlying the source rock interval is relatively thin, and increasing maturity to the southeast as the thickness of the Cenozoic foredeep sediments increases toward the depocenter located in the southeastern Iraqi Zagros and the adjacent Iranian Zagros. The correlative trend in oil gravities is exemplified by the recent Jurassic discoveries: low to medium gravity oils (14–27° API) in Shaikan and Atrush to the northwest, light oil (39–47° API) in Mirawa and Bina Bawi, and gas condensate (55° API) in Miran West to the southeast. Understanding thermal maturity patterns and hydrocarbon fluid-type distributions will help to guide risk assessment for remaining prospectivity and future exploration drilling within the Kurdistan region of Iraq.

Khatatba Formation as an active source rock for hydrocarbons in the northeast Abu Gharadig Basin, north Western Desert, Egypt

Rock samples and a suite of oil samples collected from wells drilled in the northeastern part of the Abu Gharadig Basin were studied to determine the petroleum potential of the Middle to Late Jurassic Khatatba Formation as a source rock for oil produced in the basin. Twenty-four cuttings and two cores in addition to three oil samples from the Riviera-1, Swag-2, and Spyglass-1 wells retrieved from the Upper Cretaceous reservoirs were analyzed. Analyses include total organic carbon (TOC), Rock-Eval pyrolysis, and vitrinite reflectance for rock samples and biomarker analyses for liquid hydrocarbons. Results reveal that the Khatatba Formation is an organic-rich source rock with TOC ranging from 1 to 5 wt%, locally exceeding 21 wt% due to the presence of coal interbeds in the depth interval 4,386–4,388 m. Rock-Eval pyrolysis data show that the Khatatba Formation is dominated by algal type II and mixed type II/III kerogens, but type III and type I kerogens also occur. The Khatatba shales and carbonaceous shales have entered the peak-mature stage of the oil generation window. Tmax for the samples ranges from 436 to 449 °C and vitrinite reflectance measurements between 0.76 and 0.92 %Ro. Geochemical analyses reveal that all analyzed oils were generated from thermally mature and organic-rich shale and carbonaceous shale belonging to Middle–Upper Jurassic and Lower Cretaceous source rocks during early and peak stages of the oil window. The correlation between oil samples from NE Abu Gharadig Basin shows that these oils are quite similar and were generated from mixed marine–terrigenous organic matter formed under suboxic–oxic depositional paleoenvironments. However, the differences in bulk and biomarker properties and light-end content of the oil samples can be attributed to thermal maturation, source rock facies variations, or secondary reservoir transformation, such as evaporative fractionation.

A basin modeling and organic geochemistry study in the Vallecitos syncline, San Joaquin Basin, California

The Vallecitos syncline is a westerly structural extension of the San Joaquin Basin. The Vallecitos oil field, comprised of eight separate areas that produce from Cretaceous and Paleogene reservoirs, accounted for 5.4 MMB of oil and 5.6 BCF associated of gas through 2010. However, exploration for oil and gas in the Vallecitos area is challenging due to structural complexity and limited data. The purpose of this study is to evaluate whether source rocks are actively generating petroleum in the Vallecitos syncline and to improve our understanding of burial history and timing of hydrocarbon generation. We conducted biomarker analysis on twenty-two oil samples from the Vallecitos syncline. Source-related biomarkers show two genetic groups of oil, which originated from two different source rocks. These results differ from earlier published interpretations in which the Kreyenhagen Formation is the only source rock in the Vallecitos syncline, and suggest that the Cretaceous Moreno Formation in the syncline also is an active source rock.Stratigraphic evidence and modeling suggest that late Cenozoic episodes of erosion due to folding and uplift removed significant overburden on the flanks of the syncline. To better understand the petroleum systems and clarify the total active source rocks in the area, 2D burial histories were generated through the Vallecitos syncline. A published cross-section through the deepest part of the syncline was selected to conduct thermal history, basin evolution, and migration analyses. The 2D model results indicate that the lower Kreyenhagen Formation has various maturities within the formation at different locations in the present-day syncline. The basal part of the Kreyenhagen Formation is in the dry gas window and maturity decreases away from the central part to the flanks. It remains immature along shallow portions of the present-day flanks. In contrast, the basal part of the Moreno Formation achieved extremely high maturity (past the gas generation zone) but is in the oil generation zone on the flanks of the syncline at shallow depth. All of our geochemical and 2D model results suggest that there are two active source rocks in the Vallecitos syncline. Accordingly, we propose that there are two active petroleum systems in the Vallecitos syncline.

Petroleum system analysis of the Khatatba Formation in the Shoushan Basin, north Western Desert, Egypt

The Middle Jurassic Khatatba Formation is an attractive petroleum exploration target in the Shoushan Basin, north Western Desert, Egypt. However, the Khatatba petroleum system with its essential elements and processes has not been assigned yet. This study throws the lights on the complete Khatatba petroleum system in the Shoushan Basin which has been evaluated and collectively named the Khatatba-Khatatba (!) petroleum system. To evaluate the remaining hydrocarbon potential of the Khatatba system, its essential elements were studied, in order to determine the timing of hydrocarbon generation, migration and accumulation. Systematic analysis of the petroleum system of the Khatatba Formation has identified that coaly shales and organic-rich shales are the most important source rocks. These sediments are characterised by high total organic matter content and have good to excellent hydrocarbon generative potential. Kerogen is predominantly types II–III with type III kerogen. The Khatatba source rocks are mature and, at the present time, are within the peak of the oil window with vitrinite reflectance values in the range of 0.81 to 1.08 % Ro. The remaining hydrocarbon potential is anticipated to exist mainly in stratigraphic traps in the Khatatba sandstones which are characterised by fine to coarse grain size, moderate to well sorted. It has good quality reservoir with relatively high porosity and permeability values ranging from 1 to 17 % and 0.05–1,000 mD, respectively. Modelling results indicated that hydrocarbon generation from the Khatatba source rocks began in the Late Cretaceous time and peak of hydrocarbon generation occurred during the end Tertiary time (Neogene). Hydrocarbon primarily migrated from the source rock via fractured pathways created by abnormally high pore pressures resulting from hydrocarbon generation. Hydrocarbon secondarily migrated from active Khatatba source rocks to traps side via vertical migration pathways through faults resulting from Tertiary tectonics during period from end Oligocene to Middle Miocene times.

Petroleum charging and leakage in the BZ25-1 field, Bohai Bay basin

This paper discusses origin and charging histories of the Bozhong (渤中) 25-1 field (BZ25-1) in the Bozhong sub-basin, Bohai (渤海) Bay basin. Petroleum is contained in both Paleogene and Neogene reservoirs in the BZ25-1 field. The origin of the field was studied using biomarker distributions for 61 source rock samples and 34 oil samples. Oil in the Paleogene reservoirs was derived from the third member (Es3, 43.0–38.0 Ma in age) of the Eocene Shahejie (沙河街) Formation, whereas oil in the Neogene reservoirs was a mixtures of oil generated from the third member and the first member (Es1, 35.8–32.8 Ma) of the Eocene Shahejie Formation. Charging of the shallow Neogene reservoirs was dynamic, probably ongoing, which was a combined result of the existence of active source rocks, the development of overpressure and the fault reactivation since about 5.1 Ma. On the contrary, the deep Paleogene reservoirs experienced intensive oil leakage as indicated by the high GOI (grains-containing-oil-inclusions) values (up to 30%) for samples below the present-day oil-water contact. Part of the oil that leaked from the Paleogene reservoirs re-accumulated in the shallow Neogene reservoirs. The variation of oil origins within the BZ25-1 field, and the dynamic petroleum charging into the shallow Neogene reservoirs and leakage from the deep Paleogene reservoirs have important implications for petroleum exploration.

Madbi-Biyadh/Qishn (!) petroleum system in the onshore Masila Basin of the Eastern Yemen

The Masila Basin is one several onshore Mesozoic basins in Yemen. However, a full petroleum system, with its essential elements and processes, has not been assigned yet. In this study, one petroleum system in the Masila Basin was identified and named Madbi-Biyadh/Qishn (!) petroleum system. An extensive overview study showed that the main source and reservoir rocks in the Masila Basin are the Upper Jurassic Madbi shales and Lower Cretaceous Biyadh/Qishn sandstones, respectively; hence it appears that the most important effective petroleum system of the Masila Basin becomes the Madbi-Biyadh/Qishn (!) petroleum system. Organic-rich shales of the upper part of the Madbi Formation, deposited during the upper Jurassic, constitute the main source rock of the crude oils in the basin. These shales contain high total organic carbon content (TOC >2.0 wt.%) and predominantly algal Type II with minor Type I kerogen. The Madbi shales are mature and, at the present time, are within the oil window with determined vitrinite reflectance values in the range of 0.53–0.91 Ro%. The Biyadh/Qishn sandstones are the main reservoir and were deposited in braided river channels, shoreface and shallow-marine environments, and consist of fine to coarse-grained, moderate to well sorted grains. Seal rocks are Cretaceous limestone and shales of the Qishn and Harshiyat Formations and Tertiary shales. Overburden rocks include the Cretaceous rocks and the Tertiary sediments deposited simultaneously with development of the traps during Oligocene–Middle Miocene time. Burial/thermal histories models demonstrate that hydrocarbon generation from the Madbi shales commenced in the Late Cretaceous and maximum rates of hydrocarbon expulsion occurred during the Early Tertiary. Geochemical oil-source rock correlation studies showed that regional distribution of the oil fields almost overlap with the previously constructed pod of active Madbi shales indicating that oil migrated from the active Madbi source rock to trapping sites via vertical migration pathways through faults as a result of Tertiary rifting during Oligocene–Middle Miocene time.