Crude Oil Migration Research Articles

Molecular insight into the oil charging mechanism in tight reservoirs

Tight oil reservoirs are dominated by nano-pore throats that significantly impede the migration of crude oil. Understanding the oil charging behavior in these nanoscale channels is critical to assess the oil accumulation. In this work, molecular dynamics (MD) simulations were adopted to uncover molecular insights into the oil charging and migration through differently-sized hydrophilic nano-pore throats. On the one hand, the dynamic pathway and the energetic driving force of the oil charging process were clarified. On the other hand, with analyzing the force that the oil undergoes when going across nano-pore throats, the capillary pressure for different throat sizes was calculated; based on which, we propose an MD simulation method to assess the oil accumulation threshold of tight reservoirs. Taken together, this work expends our knowledge of the fluid migration through nano-pores, and it could facilitate future studies on the evaluation of tight oil reservoirs.

Hydrocarbon accumulation period and process in Baobab area of Bongor Basin

The hydrocarbon reservoirs of Baobab area in the Northern Slope of the Bongor Basin in Chad, are very important petroleum exploration region in the basin. Baobab area could be divided into BS zone, BC zone and BN zone according to the tectonic distribution characteristics. All the three zones develop sandstone reservoirs, and the BC zone is mainly buried-hills reservoirs. Based on the analysis of the oil-source relationship of BS, BN and BC zone, the hydrocarbon accumulation period and adjustment process was investigated using a suite of hydrocarbon generation and expulsion history, tectonic thermal evolution history, GOI characteristics of fluid inclusions, microfluorescence determination and temperature measurement technology. The results show that crude oils of BS zone were sourced from BS zone source rock, oils of BN zone from BN zone source rock, and oil of BC zones from both of BS and BN source rocks. The history of hydrocarbon generation and expulsion history of source rock shows that the source rocks in BS zone matured earlier than the source rocks of BN. The hydrocarbon accumulation occurred in the early Late Cretaceous in BS zone, and in the middle Late Cretaceous in BN zone. The hydrocarbon accumulation period in the BC reservoirs was controlled by the hydrocarbon generation and expulsion history of source rock in BS and BN zones, which was a continuous process with different accumulation intensities during the Late Cretaceous. Due to the effects of tectonic events during Late Cretaceous, buried hill reservoirs of BC zone experienced the primary hydrocarbon accumulation of about 80-55 Ma and the secondary hydrocarbon accumulation at about 25 Ma. The reconstruction of buried-hill reservoirs in BC zone is obvious. The migration of crude oils from the ancient reservoir to the higher part of the Baobab structure along the faults and fractures due to tectonic inversion formed a new reservoir, and the oil-water contact became shallower about 357 m.

Lead isotopes as tracers of crude oil migration within deep crustal fluid systems

Although Pb, U, and Th may be fractionated between crude oil and formation waters, Pb isotopes are not. This unique property makes Pb isotopes a particularly useful marker of hydrocarbon generation and migration. Here we show that Pb isotopes offer a new vision of long-range (secondary) oil migration relevant to the formation of oil fields. North Sea oils are largely generated from Jurassic black shales, yet their Pb isotopes are mixtures of Cenozoic to Proterozoic end-members. The same observation is made for crude oils from the Paris Basin, the Barents Sea, Libya, Kuwait, Kazakhstan, and Australia. Bulk Pb in crude oil therefore, for the most part, is foreign to its source rock(s). Our high-precision Pb isotope data on 195 crude oils worldwide, the first such data set in the published literature, and 17 Northern European black shales indicate that deep-seated Pb components originating beneath the source rocks are ubiquitous in crude oil. This implies that oil fields are embedded in basinal convective systems of hydrous fluids heated from below. Plumes of hot fluids rise from the lower thermal boundary layer, which Pb isotopes require douse the basement, into the core of the porous-flow convective cell where they dissolve the newly formed hydrocarbons sequestered in the source rocks. The fluids finally unload unmixed formation waters and crude oil at the base of the upper (conductive) boundary layer where they can be trapped in favorable sites. Based on these new insights we argue that Pb isotopes in crude oil constitute a good tracer of oil migration.

Origin and evolution of oilfield waters in the Tazhong oilfield, Tarim Basin, China, and their relationship to multiple hydrocarbon charging events

We conducted a chemical and isotopic study of oilfield waters from Ordovician limestone reservoirs in the Tazhong oilfield (Tarim Basin, China) to trace the origin and evolution of the waters, and to demonstrate their possible relationship with hydrocarbon charging. The elemental chemistry (Cl, Br, SO4, I, K, Na, Ca, Mg, and Sr) and multiple isotopic compositions (δD, δ18O, 87Sr/86Sr, and 129I/I) of the oilfield waters were determined. The results show that these oilfield waters contain basinal brines that infiltrated in three stages, along with a lesser contribution from meteoric water. The meteoric water appears to have infiltrated downwards during the late Silurian and Carboniferous. The earliest brine had very low I contents (<5.65 mg/L) and migrated upwards from organic-poor Cambrian to Lower Ordovician dolostones during the Late Ordovician. The second brine had high I contents (>50 mg/L), was derived from Cambrian argillaceous source rocks, and migrated upwards into Ordovician reservoirs. This stage was related to the main period of migration of crude oils out of the source rocks into reservoirs during the Silurian and Devonian. Both of these brines incorporated constant levels of fissiogenic 129I from the limestone reservoir rocks (11.8–47.0 atom/μL). Finally, brine with very low I contents, but higher 129I (106–491 atom/μL), began to migrate upwards and infiltrate reservoirs. Given the relatively high fissiogenic 129I, this stage may have occurred during the late Cenozoic, and was associated with migration of dry gas from the same source rocks. Our results, combined with those of a previous study of other oilfields in the basin, suggest that the evolutionary of oilfield waters can be used to constrain hydrocarbon accumulation events, and both of which were ultimately controlled by regional tectonism and local geological factors.

Data modelling for crude oil migration studies using ranking method: a rapid geo-tracer technique for geochemists

The direction of oil charges within a field in the Niger Delta, Nigeria was determined by the sum of differences ranking method of carbazole concentrations after ascertaining other possible geological constraints on their compositional variations. The principle is that the smaller the sum, the closer the well to the source kitchen. The approach makes use of carbazoles’ interaction with the matrix, which leads to a reduction in their concentration with increasing distance from the source kitchen, allowing prediction of the charging direction. A wide range of compositional variations was observed for C1 (806.72–2152.90 μg/g) and C2 (767–2469.72 μg/g) carbazoles within the field. Based on these results, we inferred a filling pathway orientation from west to east. This suggests that the source kitchen—the most promising region for oil exploration—is located in the western part of the oil field.

Enhanced effects of large-scale CO 2 transportation on oil accumulation in oil-gas-bearing basins — Implications from supercritical CO 2 extraction of source rocks and a typical case study

Abstract Large-scale mantle-derived CO2 emplacement and co-accumulation of CO2 and crude oil have been discovered in oil-gas bearing basins in eastern China and many other areas worldwide. To investigate the effect of the natural supercritical CO2 on the migration of crude oil as well as on the formation of oil reservoirs, experiments on supercritical CO2 extraction (SCE) and traditional chloroform extraction (CE) of hydrocarbon source rocks were carried out and the geochemical characteristics of the Huangqiao CO2-oil reservoir in the Subei Basin, eastern China were investigated. The SCE yielded a large proportion of the hydrocarbons in the Permian mudstone source rocks at 110 °C under 30 MPa. Compared with the traditional chloroform extraction (CE), the SCE-retrieved organic compounds are dominated by saturated hydrocarbons and contain a relatively higher concentration of small molecular mass compounds. Many wells in the Huangqiao reservoir yielded large amounts of CO2 from several formations, such as the Triassic Qinglong Formation (T1q) and the Permian Longtang Formation (P2l). Accompanying the CO2 flow, a certain amount of oil is commonly recovered. The oil is mainly light oil or condensate oil with a relative density of 0.7933–0.8308, and it contains 90.06–97.37% saturated hydrocarbons. Compared with hydrocarbons in the Permian source rocks, the oil accompanying the CO2 in the Huangqiao reservoir contains more C20- hydrocarbons and less C21+ hydrocarbons. The oil accompanying the CO2 has a similar composition to the SCE extracts from the source rocks, namely, both contain a relatively high concentration of low molecular mass hydrocarbons. Therefore, it can be concluded that, in the Huangqiao area, during movement upward along deep faults and fractures or flow through source rocks, the deep supercritical CO2 naturally extracted hydrocarbons, especially small molecular hydrocarbons, from the source rocks, and then brought them to the shallow strata to form the CO2-oil coupling reservoirs.

Development of Predictive Model for Concentration Distribution of Crude Oil in Polluted Soil Medium

This research deals with the development of predictive model for the concentration distribution of Nigerian crude oil in porous soil media. Three (3) different soil media were considered: sand, loam and clay. Oil spillage has been the most prom inent source of ground water contamination, so, a model has been predicted to access the risk of ground water contamination by crude oil in Niger Delta regions. The migration of crude oil in the soil is only by diffusion and this enables us to predict a mo del of concentration distribution of naphthalene, benzene and toluene (NBT) using an approach called Buckingham’s  theorem. With the theorem, parameters that affect the migration of crude oil in the soil such as viscosity, density, porosity were considere d. The predicted model results were compared with experimental results obtained from literature and it showed reasonable agreement. Simulations of different components with different soil types (sand, clay and loam) were performed and it showed that sand h as the highest porosity followed by loam and least in clay. In all, Benzene shows the highest effect on the depth of soil followed by the double ringed naphthalene.

The “Brecciated Limestones” of Maiella, Italy: Rheological implications of hydrocarbon-charged fluid migration in the Messinian Mediterranean Basin

The upper Messinian “Brecciated Limestones” of the Maiella area (Central Italy) reveal clues to the rheological behavior of the sedimentary column during fluid migration processes, as well as the timing of a major phase of methane release. Seep limestones have been studied worldwide in ancient and present-day settings. However, investigations of the complex rheologic behavior shown by the wide array of brecciated facies have received less attention. In this work special emphasis was placed on fabric and facies analyses, comparisons of the various scales of observation, and integrated stable isotope analyses (δ18O and δ13C), all within the context of the precisely-dated stratigraphy of the late Messinian sediments of the Mediterranean Basin.Above the basin scale Messinian Erosional Surface (MES), widespread brecciated limestone buildups and minor concretions constitute microbial carbonate bodies laterally embedded or passing to a marly-pelitic succession. In situ fluid-driven brecciation, together with the occurrence of fluid migration paths, are interpreted to represent vestiges of a mud volcano feeder system. However, chaotic textures testify to complex rheological behavior, where brittle and plastic responses in the same micro-environments co-occurred during fluid migration through a partially lithified sedimentary column.Different patterns of tar-bearing facies and degrees of brecciation, coupled with a geochemical dataset yielding wide ranges of δ18O (from +4 to −10‰ PDB-1) and δ13C values (from +4 to −40‰ PDB-1), point to two distinct stages of ascending hydrocarbon-charged fluids: in an earlier phase, fluids were mostly typified by low-molecular-weight hydrocarbons and induced widespread brecciation in the sedimentary column; in a later phase, fluid migration was accompanied by crude oil migration. During the early phase, fluid migration through the sedimentary column developed both: (a) with large vigorous fluxes, creating neoformed feeder channels and causing high degrees of brecciation; and (b) via slow seepage, favouring authigenic carbonate precipitation in the host sediment and causing negligible brecciation.In our proposed scenario, the Maiella area witnessed a hydrocarbon-rich fluid migration event (mainly methane) during the late Messinian, accompanied by authigenic carbonate precipitation and widespread brecciation. We suggest that this event was triggered by the sudden depressurization induced by the major drawdown of the Mediterranean Sea in late Messinian times.

Investigation on crude oil penetration depth into soils

The main objectives of this paper are to study crude oil migration as a toxic fluid, its rate of penetration, and its consequences for eventual treatment. To achieve these objectives, an experimental model was designed comprising two separated columns, filled with soil and other rock types to simulate a real case scenario. Crude oil penetration depth versus time was recorded by taking soil samples whereas water samples were collected from the wet system to analyze the penetrating liquid. The results show that penetration depth was greater in the wet system during the early stages rather than in the dry system. However, with time, penetration becomes more developed in both systems. Overall penetration in the final stage was found to be significantly higher in the dry system. In addition, it was observed that during crude oil migration in dry system, chromatographic separation of crude oil components has occurred obviously. The obtained results reveal that immediate treatment must be performed in both systems but particularly in the wet system, due to its higher initial penetration rate.

Chemical speciation of redox sensitive elements during hydrocarbon leaching in the Junggar Basin, Northwest China

Bleaching related to seepage of petroleum fluids and subsurface migration of crude oil and natural gas can alter the chemical and mineralogical properties of rocks, while concurrently depleting hydrocarbon reservoirs. Mud volcanoes constitute one type of petroleum seepage present in several areas on the southern margin of the Junggar Basin in the Xinjiang Uygur Autonomous Region, NW China. The results of XRD, XRF, XANES, and Mössbauer spectroscopy on rock samples collected from areas affected by these mud volcanoes revealed an enrichment of certain minerals and elements, as well changes in mineralogical, molecular, or ionic carrier (“species”). After bleaching, reddish sedimentary rocks showed depletion in silica and enrichment of calcium, magnesium, manganese, and iron. Other elements, including aluminum, potassium, sodium, and titanium, were largely unchanged. Reduced iron and sulfur compounds predominated in the bleached rocks, producing changes in color from the original reddish into green, deep gray, and black. Iron and calcium were associated with carbonates, indicating carbonation of these elements during the bleaching processes. Manganese also appeared to be associated with carbonate, though not with sulfate even though sulfate was present in the bleached rocks. Alkaline conditions were apparently the dominant because reduced manganese would have been absent under acidic condition. The alteration of certain minerals, clay minerals in particular, was also observed in bleached rocks, the alteration of smectite-group minerals to chlorite and muscovite, for example. Mineralogical and geochemical changes in rocks bleached by hydrocarbon fluids could provide a better overall understanding of bleaching processes, and may have applications in surface geochemical exploitation and remote imaging.

Odometers for crude-oil migration

Trace molecules present in crude oils may hold the key to knowing how far oil has migrated in the Earth's subsurface. If so, improved mapping of migration pathways can aid in the search for new petroleum reserves.

Application of carboxylic acid biomarkers as indicators of biodegradation and migration of crude oils from the Maracaibo Basin, Western Venezuela

The acid fractions of 15 crude oils of different degrees of maturity, biodegradation, and origin, from the Maracaibo Basin, western Venezuela, were analyzed by high-resolution gas chromatography/ mass spectrometry (GC/MS) to determine their usefulness as indicators of biodegradation and oil migration. Acyclic as well as tri- and pentacyclic (hopanoic) monocarboxylic acids were identified and quantified for this purpose. The total acidity as well as the ratio of tricyclic to pentacyclic acids were good parameters of biodegradation in these oils. When used in conjunction, they differentiated “mixed” oils (biodegraded with non-biograded) and early generated oils from others. Contrary to previous reports, hopanoic acids (HAs) were found to be morre resistant to biodegradation than their alkane counterparts. The isomeric distribution of the HAs as well as the carbon preference index (CPI) and the C 28/C 18 ratio of the n-acids were found to be useful in determining the migration histories of the oils.

Fixed-ammonium in clays associated with crude oils

The association of ammonium (NH 4 +) silicates with organic-rich sedimentary environments has stimulated interest in the chemical cycle of N, and its possible application as an indicator of in situ organic maturation reactions or crude oil migration. Fixed-NH 4 in clay minerals was determined from three hydrocarbon occurrences of similar depositional environment but different ages, depth and thermal maturity, to determine whether anomalously high NH 4-substitution occurs near mature hydrocarbons. Results show higher fixed-NH 4 concentrations in marginally mature mudstones than in immature sediments. The highest fixed-NH 4 concentrations were found in clays from sandstone reservoirs containing migrated crude oil. Fixed-NH 4 in clays from Holocene oil seep sediments in the Gulf of Mexico continental slope, offshore Louisiana, averages 0.08 wt % and increases with depth in shallow cores (420 cm), reflecting an early diagenetic trend that is apparently not influenced by migrating crude oil. Programmed pyrolysis shows that the sediments are thermally immature (av.T max = 419°C). High Hydrogen Index values (av.= 359mg/g) are the result of biodegraded crude oil, and a high Oxygen Index (av.= 182mg/g) reflects the presence of authigenic carbonate. Fixed-NH 4 averages 0.16 wt % in Wilcox Group (Eocene) mudstones enclosing two sandstone reservoirs at Fordoche Field, onshore Louisiana. In comparison to these mudstones, anomalously high NH 4-fixation appears to occur in reservoir clay minerals. Pyrolysis shows that the sediments are marginally mature for crude oil generation (av.T max = 432°C). Average Hydrogen Index (187 mg/g) and Oxygen Index values (75 mg/g) are consistent with oil-prone Type II and Type III kerogen. Increased pyrolysis Production Index values and solvent extraction shows the presence of migrated crude oil. This suggests that a reaction which releases NH 3 during crude oil generation or migration is recorded byNH 4 + substitution in clays. Fixed-NH 4 and total organic carbon (TOC) at Fordoche Field show no statistically significant correlation, suggesting that NH 4 + substitution in clay minerals is not simply related to the amount of organic matter in the section, but is also influenced by the presence of crude oil. Once NH 4 + has been fixed in clays, it is a more stable hydrocarbon proximity indicator than pore fluid tracers, because it is less influenced by later chemical or geological changes.

Migration of crude oil from the Smackover source rock to Jurassic and Cretaceous reservoirs of the northern Gulf Rim

Migration of distinctive crude oils from the Upper Jurassic Smackover source rock across the northern Gulf Rim began at various times during the Cretaceous. Regional source rock differences resulted in two compositional subfamilies of Smackover crude oils. Type I crude oils in upper Smackover reservoirs of east Texas, Arkansas, Louisiana, and Mississippi reflect an origin from algal-derived kerogen deposited in an anoxic environment. Type II crude oils in upper Smackover reservoirs of Alabama and Florida reflected an origin from kerogen preserved in a less anoxic environment with a terrestrial component. Comparison of molecular and carbon isotopic compositions of crude oils suggests that vertical migration of Type I Smackover crude oils charged many overlying Upper Jurassic, Lower Cretaceous, and Upper Cretaceous reservoirs. Some lateral migration to Cretaceous reservoirs north of the updip limit of the Smackover Formation also occurred. Both Type I Smackover crude oils and geochemically dissimilar Cretaceous sourced oils are found in Upper Cretaceous Tuscaloosa and Woodbine reservoirs. Because of impermeable barriers to migration, especially in Alabama, vertical migration of Type II crude oils was less significant.

Deposition of magnetic pyrrhotite during alteration of crude oil and reduction of sulfate

Crude oil seepage is widespread in carbonate cap rock and in overlying sediments of the Damon Mound salt dome, Brazoria County, Texas. Scanning electron microscopy of calcite-lined cavities provides insight to the latest stage of mineral deposition in this salt dome environment. Solid crude oil residues and microbes occur in association with surface minerals such as gypsum and barite. Deposition of pyrrhotite, pyrite, marcasite, sphalerite, and elemental sulfur is attributed to microbial sulfate reduction, and deposition of aragonite and calcite is related to microbial oxidation of crude oil hydrocarbons. The C 1—C 4 hydrocarbons in pyrrhotite-bearing cap rock samples are a biodegraded residue derived from crude oil. Higher molecular weight crude oil components in cap rock are altered by water washing and to a lesser extent by biodegradation. Hydrocarbon compositions could be explained by limited aerobic biodegradation, but a component of anaerobic biodegradation cannot be excluded. Some Damon Mound samples are highly magnetic because of abundant ferrimagnetic pyrrhotite. This study provides new evidence of a link between crude oil migration, microbial activity, and diagenetic magnetic anomalies in rocks.

Carboxylic acids as indicators of oil migration—I. Occurrence and geochemical significance of C-22 diastereoisomers of the (17βH,21βH) C 30 hopanoic acid in geological samples

A pair of diastereoisomers of the 17βH,21βHC 30 hopanoic acid were detected in various geological samples such as coals and crude oils. The identifies of the two isomers (22 R and 22 S) were confirmed by comparison of mass spectra and gas chromatographic retention times with those of synthetic reference compounds. Our data indicate, as expected, a faster rate of epimerization at position 22 for the C 30 hopanoic acid of the 17βH,21βH configuration, than for its higher homologues. These C 30 hopanoic acids are well suited as maturation parameters; they may furthermore be good indicators for the migration of crude oils.

Chemical alteration of crude oils during simulated migration through quartz and clay minerals

It was previously reported (Bonilla and Engel, Org. Geochem. 10, 181–190, 1986) that laboratory simulated crude oil migration through clean quartz sands resulted in a redistribution of the saturate hydrocarbon fraction in favor of the lower molecular weight n-alkane components with increasing migration distance. This redistribution resulted in a depletion of carbon-13 in the saturate fraction. Similar isotope depletion effects were also observed for the NSO and asphaltene fractions of crude oils with increasing migration distance. In the present study, crude oils were passed through high performance liquid chromatographic (HPLC) columns packed with water wet sands and varying percent compositions of montmorillonite. A redistribution of the C 15+ aliphatic hydrocarbon fraction in favor of the lower molecular weight components and a depletion of the δ 13C values for the saturate and polar fractions appear to become accentuated by the presence of clay in the mineral phase. Whereas the δ 13C values of the aromatic fractions of oils remained constant during simulated migration, preliminary results indicate that changes in the distribution of methylphenanthrene isomers of the aromatic fraction may occur with increasing migration distance.

A review of biomarkers in kerogens as determined by pyrolysis-gas chromatography and pyrolysis-gas chromatography-mass spectrometry

Biomarkers are compounds, generally hydrocarbons, present in crude oils and source rocks whose carbon skeletons can be readily related to a precursor molecule occurring in the original source material. The use of biomarkers in source rock extracts and crude oils for the purpose of determining source materials, thermal maturity, extent of biodegradation and migration and for making oil/oil and oil/source rock correlation studies has been well documented. One of the major problems with this approach is the possibility of contamination either naturally, through crude oil migration, or artificially during sample collection or work-up procedures. A solution to this potential problem can be found in the use of biomarkers produced by kerogen pyrolysis. The actual isolation of the kerogen eliminates any potential contaminants and pyrolysis of the kerogen produces indigenous biomarkers. In this paper it is intended to review progress that has been made in the study of biomarkers produced by kerogen pyrolysis. The various techniques that have been used in this approach will be discussed and examples given to show, in particular, the distributions of triterpanes and steranes produced by kerogen pyrolysis. In addition, results obtained from a combination of hydrous pyrolysis to artificially mature kerogens, and anhydrous pyrolysis to characterize the artificially matured kerogens, will be discussed. Certain biomarkers such as the C 28-bisnorhopane and gammacerane are not produced during anhydrous pyrolysis and possible reasons for these observations will be discussed. Finally, the production of sulphur-containing compounds during pyrolysis reactions will be briefly discussed with reference to their role as possible indicators of maturity and depositional environments.

Geochemical Studies of Crude Oil Generation, Migration, and Destruction in Mississippi Salt Basin: ABSTRACT

ABSTRACT The main source for crude oil in the Mississippi Salt Basin is the laminated lime mudstone facies of the Lower Smackover. Crude oil generation and migration commenced at a level of thermal maturity equivalent to about 0.55% vitrinite reflectance. Short-range lateral migration of crude oil was focused to Upper Smackover and Norphlet reservoirs, but vertical migration also charged some overlying Cotton Valley, Rodessa, Lower Tuscaloosa, and Eutaw reservoirs. Following migration from the Lower Smackover, thermal maturity history of reservoir rocks controls the preservation of crude oil, gas-condensate, and methane. Slow thermal cracking of crude oil occurred in deep Upper Smackover reservoirs, resulting in formation of gas-condensate and precipitation of solid bitumen. The maximum thermal maturity for preservation of condensate is equivalent to about 1.3% vitrinite reflectance. Only methane, pyrobitumen, and nonhydrocarbon gases including hydrogen sulfide persist at higher levels of thermal maturity. Early destruction of methane in deep Upper Smackover reservoirs near the Wiggins Arch is driven by thermochemical sulfate reduction. Lesser availability of sulfate in Norphlet reservoirs in Lower Mobile Bay could account for methane preservation at higher levels of thermal maturity. One basic geochemical strategy for further exploration of the Mississippi Salt Basin is to focus exploration effort on traps with reservoirs in the thermal maturity window for hydrocarbon preservation. Another strategy is to avoid drilling traps with overmature reservoir rocks.

PART 1: ROCK‐EVALFYROLYSIS AND VITRINITE REFLECTANCE1

Detailed organic geochemistry has been performed on a large number of Lower Mississippian‐Upper Devonian Bakken shales from the North Dakota portion of the Williston Basin, and 28 oils mainly from Mississippian Madison Group rocks from different basinal areas. Here we report results of Rock‐Eval pyrolysis and vitrinite reflectance (Ro) analyses. Variable paleoheat flows in the Williston Basin caused the threshold of intense hydrocarbon generation to occur at different depths in different basinal areas. In higher paleogeothermal gradient basinal areas, this event occurred at depths of 7,650‐8,000 ft, and at 10,000 ft or deeper in lower paleogeothermal gradient areas of the Basin. Distinct organic metamorphic imprints in Williston Basin sediments were also caused by extreme, but variable, paleoheat flows in the basin, as well as secondary migration of crude oils from deep basinal source areas. The high paleoheat flows are postulated as being due to a Late Cretaceous — Paleocene aborted rift event. Only a small volume of Bakken shales in restricted areas of the Williston Basin was responsible for the oil found reservoired in Mississippian Madison Group rocks. However, this small shale volume has been responsible for a relatively large amount of crude oil.R0 profiles in the Tertiary through Middle Jurassic rocks in the Williston Basin had steep, linear Ro versus depth gradients, with strong reversals of R0 values occurring in the Lower Jurassic rocks. The lower Mesozoic through Paleozoic rocks of the Basin had strongly suppressed R0 values compared to the values in the Tertiary through Middle Jurassic rocks. This was especially true of the R0 values in the Bakken shales. This R0 suppression was due to a change in organic matter (OM) type from oxygen‐rich terrestrially derived OM in the younger rocks, to a hydrogen‐rich marine derived OM in the deeper, older rocks. The threshold of intense oil generation (TIHG) occurred in the Bakken shales of the Williston Basin at R0 values somewhere between 0.9 and 1.7% (best estimate 0.9), as would be read in oxygen‐rich OM. Much higher burial temperatures (and consequently R0 values) than usually held to be necessary were required for both the TIHG as well as mainstage hydrocarbon generation in the Bakken shales. These results are most likely applicable in general to source rocks with hydrogen‐rich OM. The data of this study have major implications to petroleum exploration as well as to petroleum resource assessment.