Source Rock Units Research Articles

Petroleum generation modeling of the organic-rich shales of Late Jurassic – Early Cretaceous succession from Mintaq-01 well in the Wadi Hajar sub-basin, Yemen

Late Jurassic – Early Cretaceous shales of the Naifa, Safer, and Madbi formations were studied to evaluate source rock characterization. The results of the source rock were then incorporated into basin modeling to understand the timing of hydrocarbon (HC) generation and expulsion. The Late Jurassic – Early Cretaceous shales have low to high organic matter, with total organic carbon (TOC) values in the range of 0.50%–28.01%, indicating fair to excellent source rock potential. Main oil and gas are anticipated to be generated from the Naifa, Safer, and Lam shale samples with types I and (or) II and types II–III kerogens. In contrast, the Meem samples are dominated by type III kerogen (hydrogen index, HI < 200 mg HC / g TOC), and are thus considered to be gas prone. The Late Jurassic – Early Cretaceous shale samples have temperatures of maximum pyrolysis yield (Tmax) in the range of 337–515 °C, consistent with immature to post-mature stages. The Tmaxdata also indicate that the Safer and Madbi shale samples have sufficient thermal maturity, i.e., peak–mature oil and gas window. The basin models indicate that the Naifa Formation is early–mature, and the onset oil generation began during the Early Miocene. The models also indicate that the main phase of oil generation in the Safer source rock began during the Late Eocene. In contrast, the Madbi source rock units had passed the peak oil generation window, and the oil was converted to gas during the Late Cretaceous to Late Eocene. The modeled HC expulsion history reveals that most oils are contributed by both Madbi units, with significant amounts of gas originating from the Meem unit.

Hyperspectral logging of middle Cambrian marine sediments with hydrocarbon prospectivity: a case study from the southern Georgina Basin, northern Australia

ABSTRACTThe Georgina Basin is a Neoproterozoic–Paleozoic basin that spans parts of the Northern Territory and Queensland in northern Australia. The basin is prospective for petroleum, phosphate and base metals (copper, lead and zinc). The Dulcie and Toko synclines in the southern part of the basin are prospective for petroleum, where a thick Cambro-Ordovician succession of marine carbonates hosts several source rocks and associated oil and gas shows. The key source rock units occur within the middle Cambrian Narpa Group, including both the Thorntonia Limestone (Series 2 and 3) and the Arthur Creek Formation (Series 3). The base of the Arthur Creek Formation is characterised by organic-rich ‘hot’ shales (associated with a prominent gamma spike in well logs) that have been targeted by petroleum explorers for both conventional and unconventional oil and gas. For this study, hyperspectral logging data collected by HyLogger™ instruments were evaluated from 13 wells in the southern Georgina Basin, including petroleum, mineral and stratigraphic wells. Formation boundaries are commonly (but not always) characterised by distinctive changes in mineralogy, as determined by spectral and X-ray diffraction data. Key source rock units in the southern Georgina Basin were characterised and mapped in terms of their mineralogy, and other spectral properties (e.g. Short-Wave Infrared (SWIR) reflectance and spectral contrast). Interpretation of the hyperspectral data alongside wireline log data supports the differentiation of two successions within the Arthur Creek Formation that are each characterised by basal organic-rich shales, previously distinguished on the basis of biostratigraphic and well-log data. The older succession in the Dulcie Syncline is spectrally characterised as being quartz and carbonate dominated. The younger succession, distributed across the eastern part of the Dulcie Syncline and fully across the Toko Syncline, is spectrally characterised as quartz and carbonate dominated, with variable white-mica contributions. Key associations are observed between the HyLogger mineralogy and geophysical-log data. Peaks in the gamma log intensity in the middle Cambrian sediments commonly correspond to elevated measured total organic carbon contents, decreased carbonate contribution, SWIR reflectance and spectral contrast, and relatively increased proportions of white micas and quartz. This study demonstrates that HyLogging data can provide an improved understanding of the sedimentological, mineralogical and diagenetic characteristics, as well as associated spatial heterogeneity, of prospective hydrocarbon formations in sedimentary basins.

Genetic and grade and tonnage models for sandstone-hosted roll-type uranium deposits, Texas Coastal Plain, USA

The coincidence of a number of geologic and climatic factors combined to create conditions favorable for the development of mineable concentrations of uranium hosted by Eocene through Pliocene sandstones in the Texas Coastal Plain. Here 254 uranium occurrences, including 169 deposits, 73 prospects, 6 showings and 4 anomalies, have been identified. About 80million pounds of U3O8 have been produced and about 60million pounds of identified producible U3O8 remain in place. The development of economic roll-type uranium deposits requires a source, large-scale transport of uranium in groundwater, and deposition in reducing zones within a sedimentary sequence. The weight of the evidence supports a source from thick sequences of volcanic ash and volcaniclastic sediment derived mostly from the Trans-Pecos volcanic field and Sierra Madre Occidental that lie west of the region. The thickest accumulations of source material were deposited and preserved south and west of the San Marcos arch in the Catahoula Formation. By the early Oligocene, a formerly uniformly subtropical climate along the Gulf Coast transitioned to a zoned climate in which the southwestern portion of Texas Coastal Plain was dry, and the eastern portion humid. The more arid climate in the southwestern area supported weathering of volcanic ash source rocks during pedogenesis and early diagenesis, concentration of uranium in groundwater and movement through host sediments. During the middle Tertiary Era, abundant clastic sediments were deposited in thick sequences by bed-load dominated fluvial systems in long-lived channel complexes that provided transmissive conduits favoring transport of uranium-rich groundwater. Groundwater transported uranium through permeable sandstones that were hydrologically connected with source rocks, commonly across formation boundaries driven by isostatic loading and eustatic sea level changes. Uranium roll fronts formed as a result of the interaction of uranium-rich groundwater with either (1) organic-rich debris adjacent to large long-lived fluvial channels and barrier–bar sequences or (2) extrinsic reductants entrained in formation water or discrete gas that migrated into host units via faults and along the flanks of salt domes and shale diapirs. The southwestern portion of the region, the Rio Grande embayment, contains all the necessary factors required for roll-type uranium deposits. However, the eastern portion of the region, the Houston embayment, is challenged by a humid environment and a lack of source rock and transmissive units, which may combine to preclude the deposition of economic deposits. A grade and tonnage model for the Texas Coastal Plain shows that the Texas deposits represent a lower tonnage subset of roll-type deposits that occur around the world, and required aggregation of production centers into deposits based on geologic interpretation for the purpose of conducting a quantitative mineral resource assessment.

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.

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.

Organic petrographic characteristics of the Crocker Formation, NW Sabah, Malaysia

The deep marine Crocker Formation in NW Sabah, Malaysia has been well studied in terms of sedimentology, stratigraphy and structural geology. However, not much is known about its potential as a petroleum source rock. This study partly addresses this subject by means of petrographic analysis to characterise the Crocker sediments in terms of its organic matter content and thermal maturity. Crushed rock samples mounted in resin blocks were examined under reflected white and ultraviolet light. Petrographic analysis indicates that the Crocker Formation samples have low phytoclast content (<2%). The mostly indigenous phytoclasts (microscopic plant fragments) can be divided into 4 groups based on their reflectance values; vitrinite with dark inclusions (lowest reflectance), vitrinite, oxidised vitrinite and inertinite (highest reflectance). These phytoclast groups exhibit a reflectance profile of 0.6, 0.8, 1.0 and 1.2%Ro respectively. Such an approach (measuring the reflectance of different phytoclast groups) can aid the petrographer to evaluate and validate vitrinite reflectance measurements in samples such as the Crocker that has a variable phytoclast assemblage. The average vitrinite reflectance is 0.82%Ro, which indicates that the Crocker sediments analysed were once buried to a depth of 4.1 km on average. Although its thermal maturity is within the oil generation window at present day, the Crocker Formation is considered a poor petroleum source rock because it is poor in phytoclast content (<2%) and appears to lack oil-prone liptinitic macerals. However, favourable source rock units could exist within the Crocker in the form of slump or mass- transport units, if the organic or phytoclast content is high enough and oil-prone organic matter is sufficiently present. Further geochemical analysis and regional data need to be incorporated for a more comprehensive analysis and assessment of the Crocker as a petroleum source rock and/or an analogue for subsurface geological units.

BURIAL AND THERMAL HISTORY MODELLING OF THE MURZUQ AND GHADAMES BASINS (LIBYA) USING THE GALO COMPUTER PROGRAMME

The GALO computer programme was used to model the thermal and burial histories of the Murzuq and Ghadames Basins, Libya. The model was based on recent drilling and seismic data from the basins, and used published deep temperature and vitrinite reflectance measurements. The model provides more accurate results than previous studies which were based on constant geothermal gradients during the basins' histories, and variations in heat flux at the base of the sedimentary cover were chosen so that calculated values of vitrinite reflectance coincide with those observed. The Murzuq Basin and Libyan part of the Ghadames Basin contain similar source rock units but have different burial histories. In the Murzuq Basin, maximum present‐day burial depths of Cambrian sediments range from 2200 to 2800 m and only locally reach 3000 – 3600 m; in the Ghadames Basin, however, burial depths can exceed 4–5 km. The burial history of the Murzuq Basin includes several periods of intense erosion and lithospheric heating which produced significant lateral variations in thermal maturity, leading in places to unexpected results. For example, relatively shallow‐buried Lower Silurian source rocks in the A‐76 area on the flank of the Murzuq Basin have a thermal maturity of Ro = 1.24% which is higher than the maturity of the same interval in more deeply buried areas (wells D1‐NC‐58 or J1‐NC101). In the central part of the Ghadames Basin, the modelling suggests a higher level of thermal maturity for organic matter in Silurian strata (Ro 0.8 to 1.3%), confirming the generation potential of Lower Silurian “hot shales”. Significant hydrocarbon generation began here in the Late Carboniferous and continues at the present day. Modelling of the Late Devonian (Frasnian) Aouinat Ouinine Formation “hot shales” suggests limited hydrocarbon generation depending strongly on burial depth, with the main phase of hydrocarbon generation taking place during the final episode of thermal activation in the Cenozoic. In the wells studied in the Ghadames Basin, the “oil window” extends over a considerable part of the present‐day sedimentary column.

Relationship between heterogeneity of source rocks and genetic mechanism of abnormally high pressure

Based on the micro-fluorescence observation of polished sections of source rocks, two types of micro-layers with different wetting properties formed in thermal evolution, i.e., oil-wetting and water-wetting micro-layers, are distinguished. The wetting property is found closely related to the abundance of organic matter and its occurrences with inorganic minerals. The alternating distribution and intercrossing of two types of micro-layers formed many separated spaces with different wettabilities. The strong capillary forces in these separated spaces with different wettibilities obstruct the cross flows of pore fluids and result in nearly independent and closed fluid systems. As a consequence, these spatially superposed spaces in source rocks bear the overburden pressure and then abnormally high pressures have developed in the whole source rock unit. Therefore, the abundance and occurrences of organic matter are the main inner factors influencing the formation of abnormally high pressures, whereas the formation, distribution and development of micro-layers with different wettabilities during the evolution of source rock determine the intensity and spatial distribution of abnormally high pressures.

Petroleum geochemistry and oil–oil correlation of the Fahliyan and Surmeh reservoirs in the Garangan and Chilingar oilfields, the Dezful embayment (Sw Iran)

The Dezful embayment located in southwest of Iran is one of the most potential areas for exploration and development of hydrocarbon reservoirs in the world. There are several source rock units with different geological ages. In this research, the Fahliyan and Surmeh reservoirs from the Garangan and Chilingar Dezful oilfields were studied using geochemical techniques including gas chromatography and carbon and sulfur stable isotope measurements. Carbon preference index of both reservoir oils was around one, indicating mature oil samples. The collected oil from both the fields was paraffinic in nature. Pr/nC17 and Ph/nC18 sand ratio and the plot of δ¹³C (arom) versus δ¹³C (sat), both indicated that a marine reducing environment prevailed during the deposition of their progenitor source rock. The organic matter deposited in this sediment is of kerogen type II (algal). Plot of stable carbon isotope values versus Pr/Ph ratio indicates that both oils originated from the same shaly limestone belonging to Mesozoic. The results of isotopic and geochemical studies show that a single source rock contributed to the oil family found in both fields.

Organic geochemistry and petrography of Kazhdumi (Albian–Cenomanian) and Pabdeh (Paleogene) potential source rocks in southern part of the Dezful Embayment, Iran

There are several source rock units in the Zagros Basin, but the Cretaceous Kazhdumi and Paleogene Pabdeh formations probably have produced the majority of the commercial hydrocarbons in this area. Among the hydrocarbon provinces of Iran, the Dezful Embayment, which is located southwest of Zagros Mountains, is one of the most prolific regions in the Middle East. Numerous studies have been made in the northern part of the Dezful Embayment, but relatively few have been done in its southern part. The present study focuses on organic matter characterization of two potential source rocks (Kazhdumi and Pabdeh formations) in southern part of the Dezful Embayment. Cuttings samples (114) were collected from 10 wells and evaluated using Rock–Eval pyrolysis and organic petrography in order to characterize the content and type of organic matter and thermal maturity. The results showed that the average total organic carbon (TOC) content of Kazhdumi and Pabdeh formations are 2.48 and 1.62wt%, respectively. The highest TOC contents for both formations are found in the northern compartment and decreased gradually toward the south. Pyrolysis data reveal that organic matter has a fair to very good hydrocarbon generation potential and are classified as Type II–III and Type III. Rock–Eval Tmax and vitrinite reflectance show that the majority of samples are in the early mature to mature stage of the oil generation window.

Migrated oil on Novaya Zemlya, Russian Arctic: Evidence for a novel petroleum system in the eastern Barents Sea and the Kara Sea

In this article, we present evidence for the migration of Cretaceous or younger oil into Paleozoic strata on the islands of Novaya Zemlya, Russian Arctic, originating from the surrounding basins of the Barents Sea and the Kara Sea. We thus suggest a novel petroleum system for the greater Barents Sea and Kara Sea regions. Organic geochemical data reveal that medium mature petroleum is hosted in overmature Paleozoic rocks onshore Novaya Zemlya. This petroleum likely migrated from the surrounding offshore sedimentary basins of the Kara and Barents seas into the onshore strata on a broad front, covering 400 km (248 mi) along the archipelago. Thus, the findings describe the remnants of petroleum migration on a regional scale. High maturities of the examined onshore strata (vitrinite reflectance [Ro] of 1.9–4.0% and conodont color alteration index values of 4–6) render the indigenous origin of the medium mature petroleum unlikely. Organic geochemical characteristics of the migrated hydrocarbons lead us to suggest the existence of a hitherto undescribed marine shale source rock with some contribution of terrigeneous organic matter. The 13C isotope values varying within a range of 5 for bulk extracts as well as for individual n-alkanes and isoprenoids suggest isotopic heterogeneity of the organic source facies. The source rock units are inferred to have released hydrocarbons mostly at oil window maturities (higher than 0.6% Ro). The occurrence of n-alkanes and isoprenoids, as well as abundant and partially degraded tricyclic terpanes indicates mixed undegraded and heavily biodegraded oil. This suggests several petroleum charges with varying degrees of microbial degradation. Occurrences of oleanane, high ratios of C28 to C29 steranes and elevated 24-norcholestane and 24-nordiacholestane ratios suggest Cretaceous or Tertiary source rocks.

Palynofacies, organic geochemistry and depositional environment of the Tartan Formation (Late Paleocene), a potential source rock in the Great South Basin, New Zealand

Detailed palynofacies analysis of sidewall core samples taken from below, within and above the Tartan Formation (Thanetian, Late Paleocene, 58.7–55.8 Ma), a potential source rock in the epeiric Great South Basin, shows that the formation is characterised by very high percentages of degraded brown phytoclasts, rare marine algae and amorphous organic matter and thereby represents a mix of terrestrial and marine kerogen. The results indicate that the formation was deposited in a marginally marine (hyposaline), proximal environment under bottom conditions that varied from anoxic to oxic along a nearshore–offshore transect. Samples from the upper part of the underlying Wickliffe Formation indicate deposition in a marginal to normal marine, proximal environment under anoxic to oxic bottom environments. The lower part of the overlying Laing Formation was deposited in an open marine, relatively distal setting under anoxic to oxic bottom environments. The palaeodepositional changes observed through this sequence may be best explained as a result of base-level changes in a relatively shallow-water sea. The Tartan Formation was deposited in the central, southern and eastern parts of the Great South Basin during a peak regression in the Thanetian that terminated an overall mid- to Late Paleocene aggradational to regressive trend in the basin and gave way to a latest Paleocene–earliest Eocene transgression. Its earliest and thickest known occurrence is in the Pakaha-1 well, in the centre of the basin. The formation is absent from proximal offshore wells and absent to very thin in onshore Otago drill cores and outcrops, most probably due to sediment bypass or subaerial erosion. The Tartan Formation is characterised by a combination of high organic carbon contents and 13C enrichment relative to the enclosing formations; C org and TOC values are mostly in the range 3.7–17.1% (mean 8.0%) and δ 13C values, −21.4 to −15.8‰, up to c. 9‰ heavier than in the under- and overlying formations. For sidewall core samples, there is a strong correlation between TOC and δ 13C values (R 2 = 0.91). The heavy δ 13C values can only partly be attributed to the global Paleocene Carbon Isotope Maximum, and indicate that other, organic matter source and/or regional depositional factors affected carbon fractionation in the Tartan kerogen. The Tartan Formation displays very good-excellent petroleum generative potential (up to 31 mg HC/g rock), but HI values presented herein range only from 157 to 268 mg HC/g TOC (mean 203 mg HC/g TOC), indicating the potential is primarily for gas, with only minor oil. The relatively poor HI values are attributed to the large influx of degraded woody material, rendering the Tartan Formation less oil-prone than previously inferred. The Tartan Formation is biostratigraphically coeval with the Waipawa Formation of the New Zealand East Coast Basin, which is a similar source rock unit also enriched in 13C. Samples from the Waipawa Formation taken 1000 km north of the Great South Basin share palynofacies and geochemical characteristics with the Tartan Formation, indicating that a base-level fall also controlled the deposition of the Waipawa Formation in the East Coast Basin. The size of the area affected by the base-level fall and the lack of evidence for contemporaneous large-scale tectonic uplift imply that the base-level fall was caused by eustasy. This suggests that the Tartan and Waipawa Formations may be more extensive in New Zealand offshore basins than previously thought.

An outcrop‐based study of the economically significant Late Cretaceous Rakopi Formation, northwest Nelson, Taranaki Basin, New Zealand

The Late Cretaceous Rakopi Formation (Pakawau Group) represents one of the most important petroleum source rock units and a potential reservoir unit in the highly prospective Taranaki Basin. This paper presents a predominantly outcrop‐based study of the sedimentology, petrography, stratigraphy, and depositional environment of the Rakopi Formation in the Paturau River and Pakawau areas of northwest Nelson, southern Taranaki Basin, together with some preliminary insights into the stratigraphie architecture of the Pakawau Group on a more basin‐wide scale. The Rakopi Formation is interpreted here as a terrestrial deposit, representing sedimentation in fluvial channels and their associated overbank and levee environments. However, the presence of dinoflagellates, glauconite, and elevated coal seam sulfur contents is evidence for periodic marine influence during deposition. This could be explained by a low‐gradient coastal plain paleogeography, crossed by a series of rivers and their associated floodplain deposits, episodically inundated by marine incursions during successive transgressions. A modern analogue setting from the present‐day Hauraki Graben, North Island, New Zealand, indicates that marine influence within coastal plain systems can extend several tens of kilometres inland. Given such a physiography, relatively small increases in relative sea level could potentially move the shoreline several kilometres or tens of kilometres farther inland, sufficient to introduce the type of marine influence on sedimentation that we suggest for the Rakopi Formation. The results from this study suggest a greater marine influence within the Rakopi Formation, northward into the greater Taranaki Basin, than has previously been recognised. This raises the possibility of both different reservoir facies as well as potentially a greater proportion of marine mudstones, which would have implications for both reservoir and trapping of hydrocarbons. In addition, marine‐influenced coaly rocks within the Rakopi Formation are expected to have greater petroleum generative potentials and to be more oil‐prone than their fully non‐marine counterparts.

A Middle–Upper Miocene fluvial–lacustrine rift sequence in theSong Ba Rift, Vietnam: an analogue to oil-prone, small-scale continental rift basins

The small Neogene Krong Pa graben is situated within the continental Song Ba Rift, which is bounded by strike-slip faults that were reactivated as extensional faults in Middle Miocene time. The 500 m thick graben-fill shows an overall depositional development reflecting the structural evolution, which is very similar to much larger and longer-lived graben. The basal graben-fill consists of thin fluvial sandstones interbedded with well-oxygenated lacustrine siltstones in the basin centre, while very coarse-grained fluvial sandstones and conglomerates dominate at the basin margins. With increased subsidence rate and possibly a higher influx of water from the axial river systems the general water level in the graben rose and deep lakes formed. High organic preservation in the lakes prompted the formation of two excellent oil-prone lacustrine source-rock units. In the late phase of the graben development sedimentation rate outpaced the formation of accommodation space and fluvial activity increased again. During periods when the general sedimentation rate was in balance with the creation of accommodation space the environment changed frequently between lake deposition and intermittent vigorous fluvial activity. It is likely that the resulting interbedding of fluvial sandstones and lacustrine sediments reflects variations in precipitation. In periods of little precipitation the lakes diminished and lake bottoms became exposed. After heavy precipitation, transverse river systems transported sands from the rift shoulders across the exposed lake bottom and fluvial sands were deposited on lake bottom sediments. Subsequently, lake level rose due to increased water supply from the axial river and the sands were drowned and topped by transgressive lacustrine mudstones. These sandstones may function as carrier beds, whereas the braided fluvial sandstones and conglomerates along the graben margins may form reservoirs. The Krong Pa graben thus contains oil-prone lacustrine source rocks, effective conduits for generated hydrocarbons and reservoir sandstones side-sealed by the graben faults toward the footwall granites. In addition to the structural and climatic signals recorded by the graben-fill, sediment partitioning among the partly isolated basins along the rift axis seems to have been important.

PETROLEUM POTENTIAL OF THE GREAT SOUTH BASIN, NEW ZEALAND—NEW SEISMIC DATA IMPROVES IMAGING

Much of the Great South Basin is covered by a 30,000 km grid of old seismic data, dating from the 1970s. This early exploration activity resulted in drilling eight wells, one of which, Kawau–1a, was a 461 Bcf gas-condensate discovery. Three other wells had significant oil and gas shows; in particular, Toroa–1 had extensive gas shows and 300 m oil shows. Cuttings are described in the geological logs as dripping with oil. The well was never tested due to engineering difficulties, meaning that much of the bore was accidentally filled with cement while setting casing.In early 2006, Crown Minerals, New Zealand’s petroleum industry regulating body, conducted a new 2D seismic survey in a previously lightly surveyed region across the northern part of the Great South Basin. While previous surveys were generally recorded for five seconds, sometimes six, with up to a 2,500-metre-long cable, the new survey, acquired by CGG Multiwave’s Pacific Titan, employed a 6,000-metre-long streamer and recorded for eight seconds.The dataset was processed to pre-stack time migration (PreSTM) by the GNS Science group using its access to the New Zealand Supercomputer. Increasing the recording time yielded dividends by more fully imaging, for the first time, the nature of rift faulting in the basin. Previous data showed only the tops of many fault blocks. The new data show a system of listric extensional faults, presumably soling out onto a mid-crust detachment. Sedimentary reflectors are observed to seven seconds, implying a thickness of up to 6,000 m of section, probably containing source rock units. The rotated fault blocks provide focal points for large compaction structures. The new data show amplitude anomalies and other features possibly indicating hydrocarbons associated with many of these structures. The region around the Toroa–1 well was typified by anomalously low velocities, which created a vertical zone of heavily attenuated reflections, particularly on intermediate processing products. The new data also show an amplitude anomaly at the well’s total depth (TD) which gives rise to a velocity push-down.Santonian age coaly source rocks are widespread and several reservoir units are recognised. The reservoir at Kawau–1a is the extensive Kawau Sandstone, an Early Maastrichtian transgressive unit sealed by a thick carbonate-cemented mudstone. In addition to the transgressive sandstone target, the basin also contains sandy Eocene facies, and Paleogene turbidite targets may also be attractive. Closed structures are numerous and many are very large with potential to contain billion barrel oil fields or multi-Tcf gas fields.

Evaluation of kinetic uncertainty in numerical models of petroleum generation

Oil-prone marine petroleum source rocks contain type I or type II kerogen having Rock-Eval pyrolysis hydrogen indices greater than 600 or 300–600 mg hydrocarbon/g total organic carbon (HI, mg HC/g TOC), respectively. Samples from 29 marine source rocks worldwide that contain mainly type II kerogen (HI = 230–786 mg HC/g TOC) were subjected to open-system programmed pyrolysis to determine the activation energy distributions for petroleum generation. Assuming a burial heating rate of 1C/m.y. for each measured activation energy distribution, the calculated average temperature for 50% fractional conversion of the kerogen in the samples to petroleum is approximately 136 7C, but the range spans about 30C (121–151C). Fifty-two outcrop samples of thermally immature Jurassic Oxford Clay Formation were collected from five locations in the United Kingdom to determine the variations of kinetic response for one source rock unit. The samples contain mainly type I or type II kerogens (HI = 230–774 mg HC/g TOC). At a heating rate of 1C/m.y., the calculated temperatures for 50% fractional conversion of the Oxford Clay kerogens to petroleum differ by as much as 23C (127–150C). The data indicate that kerogen type, as defined by hydrogen index, is not systematically linked to kinetic response, and that default kinetics for the thermal decomposition of type I or type II kerogen can introduce unacceptable errors into numerical simulations. Furthermore, custom kinetics based on one or a few samples may be inadequate to account for variations in organofacies within a source rock. We propose three methods to evaluate the uncertainty contributed by kerogen kinetics to numerical simulations: (1) use the average kinetic distribution for multiple samples of source rock and the standard deviation for each activation energy in that distribution; (2) use source rock kinetics determined at several locations to describe different parts of the study area; and (3) use a weighted-average method that combines kinetics for samples from different locations in the source rock unit by giving the activation energy distribution for each sample a weight proportional to its Rock-Eval pyrolysis S2 yield (hydrocarbons generated by pyrolytic degradation of organic matter).

North Slope, Alaska: Source rock distribution, richness, thermal maturity, and petroleum charge

Four key marine petroleum source rock units were identified, characterized, and mapped in the subsurface to better understand the origin and distribution of petroleum on the North Slope of Alaska. These marine source rocks, from oldest to youngest, include four intervals: (1) Middle–Upper Triassic Shublik Formation, (2) basal condensed section in the Jurassic–Lower Cretaceous Kingak Shale, (3) Cretaceous pebble shale unit, and (4) Cretaceous Hue Shale. Well logs for more than 60 wells and total organic carbon (TOC) and Rock-Eval pyrolysis analyses for 1183 samples in 125 well penetrations of the source rocks were used to map the present-day thickness of each source rock and the quantity (TOC), quality (hydrogen index), and thermal maturity (Tmax) of the organic matter. Based on assumptions related to carbon mass balance and regional distributions of TOC, the present-day source rock quantity and quality maps were used to determine the extent of fractional conversion of the kerogen to petroleum and to map the original TOC (TOCo) and the original hydrogen index (HIo) prior to thermal maturation. The quantity and quality of oil-prone organic matter in Shublik Formation source rock generally exceeded that of the other units prior to thermal maturation (commonly TOCo 4 wt.% and HIo 600 mg hydrocarbon/g TOC), although all are likely sources for at least some petroleum on the North Slope. We used Rock-Eval and hydrous pyrolysis methods to calculate expulsion factors and petroleum charge for each of the four source rocks in the study area. Without attempting to identify the correct methods, we conclude that calculations based on Rock-Eval pyrolysis overestimate expulsion factors and petroleum charge because low pressure and rapid removal of thermally cracked products by the carrier gas retards cross-linking and pyrobitumen formation that is otherwise favored by natural burial maturation. Expulsion factors and petroleum charge based on hydrous pyrolysis may also be high compared to nature for a similar reason.

A review of techniques for the estimation of magnitude and timing of exhumation in offshore basins

Exhumation, the removal of overburden resulting from the vertical displacement of rocks from maximum burial depth, occurs at both regional and local scales in offshore sedimentary basins and has important implications for the prospectivity of petroliferous basins. In these basins, issues to be addressed by the petroleum geologist include, the timing of thermal ‘switch-off’ of source rock units, the compactional and diagenetic constraints imposed by the maximum burial depth of reservoirs (prior to uplift), the physical and mechanical characteristics of cap-rocks during and post-exhumation, the structural evolution of traps and the hydrocarbon emplacement history. Central to addressing these issues is the geoscientist's ability to identify exhumation events, estimate their magnitude and deduce their timing. A variety of individual techniques is available to assess the exhumation of sedimentary successions, but generic categorisation indicates that ‘point’ measurements of rock displacement, in the offshore arena, are made with respect to four frames of reference — tectonic, thermal, compactional or stratigraphic. These techniques are critically reviewed in the context of some of the exhumed offshore sedimentary basins peripheral to the Irish landmass. This review confirms that large uncertainty is associated with estimates from individual techniques but that the integration of seismic interpretation and regional stratigraphic data provides valuable constraints on estimates from the more indirect tectonic, thermal and compactional methods.

HYDROCARBON GENERATION HABITAT OF TWO CRETACEOUS CARBONATE SOURCE ROCKS IN SE TURKEY

A detailed petroleum geochemical study has been carried out on two Cretaceous carbonate source rock units, the Karababa Formation A Member and the Karabogaz Formation, in the Adiyaman area of SE Turkey. The purpose was to compare the hydrocarbon generation habitat of these two units which appear to be almost identical in terms of their bulk source rock characteristics. Thus, the TOC contents of the Karababa Formation A Member and the Karabogaz Formation are 0.24–3.79% and 0.50–5.86%, respectively. Hydrogen Indices are generally greater than 300 mg HC/ g TOC and both units have similar maturity levels. However, the results of pyrolysis‐gas chromatographic analyses showed that the organic matter in the Karababa Formation A Member is richer in sulphur compounds, and the presence of sulphur‐rich kerogen resulted in the early generation of hydrocarbons from this unit. Both the dominant activation energy and the frequency factor turned out to be lower for the Karababa Formation A Member. Consequently, oil generation in the Karababa Formation A Member proceeds more rapidly for a given temperature history than it does in the Karabogaz Formation. Moreover, the results of multi‐step Py‐GC analyses indicated that the composition of hydrocarbons generated in these two carbonate source rocks will be different, particularly during the early stages of maturation. Early‐generated oil from the Karababa Formation A Member has the composition of a mature oil, whereas oil from the Karabogaz Formation reaches the same composition at a higher maturity.

Fault-fracture mesh petroleum plays in the Zhanhua Depression, Bohai Bay Basin: Part 1. Source rock characterization and quantitative assessment

In the prolific Zhanhua Depression of the Bohai Bay Basin, eastern China, over 76% of the proven petroleum reserves occur in the Neogene Guantao and Minhuazhen formations. Detailed geological and geochemical mapping of the Phanerozoic strata in this area reveals that oil shales and dark mudstones in the Es 4, Es 3 and Es 1 members of the Eocene–Oligocene Shahejie Formation have excellent potential as petroleum source rocks. Regional distributions of total organic carbon content, kerogen type and thermal maturation indicate that abundant mature source rocks are present in several discrete sag areas bounded by extensive basement-related fault networks. In contrast, source rocks along the paleo-topographic highs are currently immature with respect to the generation of conventional oils. This study examined the key molecular characteristics for the common isoprenoid, hopanoid and steroid biomarkers, in relation to source facies variations in lacustrine sediments. The hydrocarbon source potential and expulsion efficiency for each of the source rock units were evaluated, which integrated the source rock characteristics with regional thermal subsidence and sediment burial. An important observation made during this study is the striking contrast between the source potential and proven oil reserves within each stratigraphic section, illustrating how significant the migration of hydrocarbon fluids derived from deep mature source kitchens through over 2000 m of fine-grained formations must have been to form several giant oil accumulations in the shallow strata. These results support the concept of the “Neogene fault-fracture mesh petroleum plays” proposed by Zhang et al. (2004) [Marine & Petroleum Geology, 21, 651–668] and the vital role that the faults and fracture systems have in controlling hydrocarbon migration conduits and accumulation habitat in this rift basin.