Maximum Hydrocarbon Generation Research Articles

Indirect analysis of unconventional shale hydrocarbon resources in the Recôncavo Basin, Brazil. A case study

The Recôncavo basin is a mature basin with great potential for extracting hydrocarbons from conventional and unconventional reserves. It is inserted in an extensive taphrogenic basin, that is the Recôncavo-Tucano-Jatobá aborted rift in the Brazilian northeast region, where the beginning occurred with the rupture of the western Gondwana paleocontinent. Stratigraphically, it presents six sedimentary sequences related to the pre-rift and rift stages. The study area is located in the structural low named Camaçari Low, in the Southern compartment of the basin, what it is the deepest depocenter, with a preserved sedimentary section of 6900 m, it is in addition to being main oil and gas generation kitchen. So to evaluate the potential abundance of a rock formation, in the case of both conventional and unconventional reserves, it is of key importance to quantify the total organic content (TOC), hydrogen index (HI), vitrinite reflectance (Ro), maximum hydrocarbon generation temperature (Tmax) and level of organic maturation (LOM). These parameters can be estimated by direct methods (in the laboratory) using geochemical analysis or by indirect methods using well log data. Direct analysis provides point estimates, while indirect analysis provides a continuous depth profile of them. For this study, data from geochemical analysis and logging of well 1 CGL 1D BA from the Recôncavo basin, in the Camaçari Low, to estimate the TOC profiles by means of simple linear regression, LOM by the Passey method utilizing the ΔDT, Ro, HI and Tmax, for depths greater than 1000 m. The linear regression resulted in a moderately positive correlation of the TOC estimate. Replacing the ΔLogR method of Passey for ΔDT method of Bowman proved to be a rapid and easily determined technique. The estimates of the vitrinite reflectance and hydrogen index based on the estimated LOM values were compatible with the measured values, as was the estimate of maximum hydrocarbon generation temperature based on the vitrinite reflectance. The organic matter was characterized as type I and II kerogen.

Integrated source rock evaluation along the maturation gradient. Application to the Vaca Muerta Formation, Neuquén Basin of Argentina

AbstractThe Vaca Muerta Formation (Tithonian–early Valanginian) is the main source rock in the Neuquén Basin and the most important unconventional shale resource in South America. In the present study, organic geochemistry, electron microscopy and basin and petroleum system modelling (BPSM) were combined to evaluate source rock properties and related processes along a transect from the early oil (east) to the dry gas (west) window. The unit is characterized by high present‐day (1%–8% average) and original (2%–16% average) total organic carbon contents, which increase towards the base of the unit and basinal (west) settings. Scanning electron microscopy shows that organic pores derived from the transformation of type II kerogen. Isolated bubble pores are typical of the oil window, whereas bubble and densely distributed spongy pores occur in the gas stage, indicating that the maturity gradient exerts strong control on organic porosity. Organic geochemistry, pressure and porosity data were incorporated into a 2D basin petroleum system model that includes the sequential restoration of tectonic events and calculation of compaction trends, kerogen transformation, hydrocarbon generation and estimation of pore pressure through geologic time. The W–E regional model extends from the Agrio Fold and Thrust Belts to the basin border and allows us to evaluate the relationship between thermal maturity and timing of hydrocarbon generation from highly deformed (west) to undeformed (east) regions. Modelling results show a clear decrease in maturity and organic matter (OM) transformation towards the eastern basin margin. Maximum hydrocarbon generation occurred in the inner sectors of the belt, at ca. 120 Ma; long before the first Andean compression phase, which started during the Late Cretaceous (ca. 70 Ma). Miocene compression (15–7 Ma) promoted tectonic uplift of the inner and outer sectors of the belt associated with a reduction in thermal stress and kerogen cracking, as well as massive loss of retained fluids and a decrease in pore pressure. The OM transformation impacted (a) the magnitude of effective porosity associated with organic porosity development, and (b) the magnitude and distribution of pore pressure within the unit controlled by hydrocarbon generation and compaction disequilibrium. BPSM shows a progressive increase in effective porosity from the top to the base and towards the west region related to the original organic carbon content and maturity increasing along the same trend. Overpressure intervals with high organic carbon contents are the most prone to develop organic pores. The latter represent favourable sites for the storage of hydrocarbons in the Vaca Muerta Formation.

Hydrocarbon generation and expulsion characteristics of the Lower Cambrian Qiongzhusi shale in the Sichuan Basin, Central China: Implications for conventional and unconventional natural gas resource potential

In recent years, significant progress and breakthroughs have been made in the exploration of conventional and unconventional natural gas in the Lower Cambrian petroleum system in the Sichuan Basin in Central China, showing excellent exploration prospects. However, detailed evaluation of the Qiongzhusi shale, the main source rocks in the Lower Cambrian petroleum system, including their hydrocarbon generation and expulsion characteristics, is lacking, even though such evaluation is critical for understanding conventional and unconventional natural gas resource potential. To investigate the geological and geochemical characteristics of the Qiongzhusi shale, experiments including pyrolysis, total organic carbon (TOC), vitrinite reflectance (Ro), gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) were conducted. Based on modeling work and fluid inclusion analysis, the hydrocarbon generation and expulsion characteristics of the Qiongzhusi shale and their control on hydrocarbon accumulation was analyzed, and the conventional and unconventional natural gas resource potential of the Lower Cambrian petroleum system was systematically evaluated. The results indicate that the organic matter of the Qiongzhusi shale is mainly derived from bacteria and algae deposited in a saline, reducing marine environment. The shale is predominantly composed of type I kerogen with an average TOC value of 1.85 wt%, and is widely distributed in the basin with an average thickness of 212.7 m. The Qiongzhusi shale is primarily post-mature with an average vitrinite reflectance (Ro) of 2.53%. Modeling work suggests the Qiongzhusi shale reached the hydrocarbon expulsion threshold (HET) at Ro = 0.9%, and the main hydrocarbon expulsion stages are Triassic, Jurassic, and Cretaceous. The maximum hydrocarbon generation and expulsion intensities at present day are 32 × 10 6 t/km 2 and 18 × 10 6 t/km 2 , respectively. The conventional natural gas resource potential of the Longwangmiao Formation derived from the Qiongzhusi shale is estimated to be between 9.51 × 10 12 m 3 and 19.03 × 10 12 m 3 . The unconventional shale gas resource potential of the Qiongzhusi shale is predicted to be 1.4 × 10 12 m 3 , showing significant prospects for natural gas exploration. • Geochemistry characteristics of the Qiongzhusi Formation were systemically evaluated. • Hydrocarbon generation and expulsion characteristics of the Qiongzhusi Formation were first analyzed. • Conventional and unconventional natural gas resource potentials of ancient Lower-Cambrian petroleum system were calculated.

Hydrocarbon source potential evaluation insight into source rocks—A case study of the first member of the Paleogene Shahejie Formation, Nanpu Sag, NE China

The features of source rock hydrocarbon generation, expulsion, and retention are essential factors in petroleum resource potential evaluation. In this study, the improved hydrocarbon generation potential evaluation method was used to quantify the characteristics of the source rocks of the first member of the Paleogene Shahejie Formation (Es1) in the Nanpu Sag, Bohai Bay Basin, NE China. Based on the geological and geochemical data for the source rocks, the favorable exploration areas were predicted and the resource potential was evaluated. Our results show that Es1 is a set of high-quality source rocks with desirable geological (maximum thickness > 600 m) and geochemical (average total organic carbon content of 1.44%; dominantly type II kerogen; mature stage) characteristics. The improved hydrocarbon generation potential model shows that the hydrocarbon expulsion threshold is located at Ro=1.0%. The maximum hydrocarbon generation potential (Qg), hydrocarbon expulsion potential (Qe), hydrocarbon retention potential (Qs), and efficient hydrocarbon retention potential (Qse) are 549.31, 162.20, 387.11, and 287.11 mg HC/g TOC, respectively. The maximum hydrocarbon generation, expulsion, retention, and effective retention intensities are 250×104, 70×104, 180×104, and 150×104 t/km2, respectively. These parameters reach the highest value in the Linque and Caofeidian Sub-sag. The resource potential of the retention shale oil, the movable shale oil, and the conventional and the tight petroleum resources are 1.99×108, 4.38×108, and 1.37×108 t oil equivalent, respectively. This study offers a fresh and plain but operable workflow for resource evaluation, which can be applied in other petroliferous basins with low degree of exploration.

The hydrocarbon generation and expulsion features of source rocks and tight oil potential of the second member of the Qiketai Formation, Shengbei area in the Turpan–Hami Basin, NW China

Significant progress in tight oil exploration has been reported in the second member of the Qiketai Formation (J2q2) in the Shengbei area of the Turpan–Hami Basin. Geochemical analyses were conducted to assess the quality of the J2q2 source rocks. The improved hydrocarbon generation potential method was utilized to quantify the hydrocarbon generation and expulsion features of the source rocks. The results showed that J2q2 source rocks were deposited in a reduced lacustrine setting with a high palaeoproductivity. The J2q2 source rocks are widely distributed (approximately 1,000 km2) and have a thickness that varies from 50 to 130 m. Moreover, they can be identified as a set of high‐quality source rocks (thermally mature rocks with Ro values >0.5%, consisting mainly of types I and II kerogen and possessing an average total organic carbon content of 2.68%). The oil–source correlation results reveal that the source of crude oil in the studied area is J2q2. The improved hydrocarbon generation potential method is established for different kerogen types to limit the influence of the kerogen type on the calculation. The hydrocarbon expulsion threshold of the type I model is located at Ro = 0.6%. The type II kerogen rocks have different characteristics, and the hydrocarbon expulsion threshold is located at Ro = 0.62%. The maximum hydrocarbon generation and expulsion intensities are 700 × 104 t/km2 and 400 × 104 t/km2, respectively. The hydrocarbon generation and expulsion amount of the J2q2 source rocks are 21.4 × 108 t and 12.3 × 108 t, respectively. The tight oil potential of the J2q2 tight oil in the Shengbei area is 4.09 × 108 t. The SB10 and SB6 well areas are favourable J2q2 tight oil exploration areas in the Shengbei area. The SB10 well area has the highest hydrocarbon generation and expulsion intensities in the study area and is the best tight oil exploration target.

Organic geochemistry, hydrocarbon generation, and expulsion characteristics and their impact on tight oil: A case study of the third member of the Upper Palaeogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin, NE China

In recent years, exploration of tight oil in the Nanpu Sag has made significant progress in the third member of the Upper Palaeogene Shahejie Formation (Es3) in the Nanpu Sag, Bohai Bay Basin, Northeast China, showing excellent prospects. However, owing to insufficient understanding of the hydrocarbon generation and expulsion characteristics of Es3 source rocks and their matching relationship with the reservoir tightening time, the genetic type and resource potential of tight oil systems are not precise, which limits the further exploration of tight oil. In this study, the geological and geochemical characteristics of Es3 source rock are identified through a comprehensive geological and organic geochemistry analysis. In addition, hydrocarbon generation and expulsion patterns are established using a hydrocarbon generation potential model. On the basis of these results, combined with sandstone reservoir evolution histories, we have identified the genetic type and resource potential of the tight oil. The results show that the kerogen types of the Es3 source rocks of the Nanpu Sag, are widely distributed in an area of nearly 1,000 km2 and have a large thickness of more than 700 m, are mainly Types II and III with a high average total organic carbon (TOC) value of 1.63%. Moreover, the source rocks are primarily in the mature stage, with an average vitrinite reflectance (Ro) of 1.06%. The Es3 source rock reached the hydrocarbon expulsion threshold at Ro = 0.7%, and the hydrocarbon expulsion efficiency was approximately 70%. Two hydrocarbon generation and expulsion centres are identified, the Gaoshangpu and Laoyemiao structural belts, with maximum hydrocarbon generation and expulsion intensities of 100 × 106 t/km2 and 80 × 106 t/km2, respectively. In addition, two genetic types of tight oil are identified with accumulation before and after tightening, respectively. The resources of these types are 2.3 × 108 t and 20.4 × 108 t, respectively, with a total of 22.7 × 108 t, which indicates significant prospects for tight oil exploration.

Geological Controls on High Production of Tight Sandstone Gas in Linxing Block, Eastern Ordos Basin, China

AbstractTight sandstone gas in the Linxing Block, eastern Ordos Basin, has been successfully exploited. The high performance is mainly a result of the special geological conditions. The key geological controls for high production have been discussed on the basis of seismic data, field observation, sample features, mercury porosimetry, mechanical properties, and basin modeling. Firstly, the coal measures have good gas generation potential, not only because of the existence of coalbeds and organic‐rich shales, but also because coal laminae and microbial mats in the shales significantly increase their total organic carbon (TOC) contents. Secondly, except for the uplifted zone of the Zijinshan complex and the eastern fault zone, rare large faults develop in the Carboniferous–Permian sequence, ensuing the sealing capacity of cap rock. Small fractures generally concentrated in the sandstones rather than the mudstones. Thirdly, gas accumulation in the Linxing Block was controlled by the tectonic, burial and thermal histories. Gas accumulation in the Linxing Block started in the Late Triassic, followed by three short pauses of thermal maturation caused by relatively small uplifts; the maximum hydrocarbon generation period is the Early Cetaceous as a combined result of regional and magmatic thermal metamorphisms. Field profiles show abundant fractures in sandstone beds but rare fractures in mudstone beds. Mechanical properties, determined by lithostratigraphy, confine the fractures in the sandstones, increasing the permeability of sandstone reservoirs and retaining the sealing capacity of the mudstone cap rocks. The modern ground stress conditions favor the opening of predominant natural fractures in the NNW–SSE and N–S directions. These conclusions are useful for exploring the potential tight sandstone gas field.

An improved hydrocarbon generation potential method for quantifying hydrocarbon generation and expulsion characteristics with application example of Paleogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin

Abstract To evaluate petroleum resources, it is important to quantify the hydrocarbon generation and expulsion characteristics of source rock. The hydrocarbon generation potential method is an efficient model for calculating the characteristics of source rocks and evaluating the resource potential. The previous hydrocarbon generation potential model was mainly established by measured Rock-Eval pyrolysis data, and due to inappropriate preservation measures, an important component (volatile hydrocarbon content) of source rock may be significantly reduced. Prior methods may, therefore, not objectively reflect the properties of a source rock and cause unacceptable errors in the resource assessment. This study proposes an improved hydrocarbon generation potential method. The new method considers the initial hydrogen index (HI0) and transformation ratio (Tr) during the evolution of source rocks, which can more realistically reflect the hydrocarbon generation and expulsion history of source rocks. Therefore, the hydrocarbon evaporative loss (Qloss) is calibrated and the hydrocarbon generation and expulsion features of source rocks are more accurately evaluated. The proposed method is used to examine the effectiveness of the third member of the Upper Paleogene Shahejie Formation (Es3) in Nanpu Sag. By utilizing the improved hydrocarbon generation potential model, the hydrocarbon expulsion threshold of the Es3 source rock is positioned at Ro = 0.875%. The maximum hydrocarbon generation and expulsion potential (Qg and Qe) are 593.78 and 323.78 mg HC/g TOC, respectively, and the maximum hydrocarbon expulsion efficiency is 54%. The maximum hydrocarbon generation and expulsion intensities are 500 × 104 t/km2 and 250 × 104 t/km2, respectively, which locate source rock at the Laoyemiao and Gaoshangpu Structural Belts. The amounts of generated and expelled hydrocarbon are 13.7 × 108 t and 6.9 × 108 t, respectively, and the resource potential of the tight oil of the Es3 in the Nanpu Sag is 0.69 × 104 t. Compared with the previous method, the improved hydrocarbon generation potential method limits the maximum Qg and calibrates the Qloss; therefore, the new method more objectively reflects the hydrocarbon generation and expulsion characteristics and resource prospect of the source rock.

Organic geochemistry of Upper Paleozoic source rocks in the eastern margin of the Ordos Basin, China: Input and hydrocarbon generation potential

In the present research, the hydrocarbon source rock potential, thermal maturity (Tmax), and paleoenvironment of Upper Paleozoic coaly source rocks of the eastern margin of the Ordos Basin, China, were assessed by using Rock-Eval pyrolysis, gas chromatography (GC), and gas chromatography–mass spectrometry (GC–MS). The tested samples were found to be composed mostly of Type III kerogen organic matter with relatively low hydrogen and low oxygen index values. Graphs of the total organic carbon (TOC) content against free hydrocarbon (S1) and source potential (S2) values indicated that most of the samples have good source rock qualities. On the basis of maximum hydrocarbon generation temperature (Tmax) and vitrinite reflectance (Ro), the investigated samples were found to be in mature and high-mature stages for hydrocarbon generation. The detected chromatograms were dominated by short (nC15–nC20)- to middle (nC20–nC25)-chain normal alkanes and were marked by a single peak with weak to no odd–even predominance. The C29ααα20R/C27ααα20R ratio varied between 1.14 and 1.35, and the gammacerane/hopane ratio ranged from 0.12 to 0.14, thus indicating a low-salinity reducing environment. Both the Late Carboniferous Taiyuan and the Early Permian Shanxi formations manifested a dominant source of higher plant as evidenced by the maceral compositions and biomarkers, while the Taiyuan Formation samples show a mixed source aquatic matter influenced by the transgression happened several times during the strata deposition. Moreover, the C29ααα20R/C27ααα20R ratio, ΣC21−/ΣC22+ ratios, and the distributions of C27-, C28-, and C29- steranes revealed that the Taiyuan Formation source rocks were composed of certain contents of aquatic organisms and algae under a more reducing environment.

Hydrocarbon generation and expulsion characteristics of the source rocks in the third member of the Upper Triassic Xujiahe Formation and its effect on conventional and unconventional hydrocarbon resource potential in the Sichuan Basin

Abstract The third member of the Upper Triassic Xujiahe Formation (T3x3) is a typical source-reservoir-cap unit for natural gas exploration in the Sichuan Basin. However, most previous studies mainly focused on the T3x3 as a source rock, ignoring its role as a reservoir. As a result, the evaluation of hydrocarbon resource potential was not accurate. This study established a hydrocarbon generation and expulsion model through analyzing the geological and geochemical characteristics of the T3x3 source rocks, and calculated the resource potential of conventional gas, tight gas and shale gas systematically with combining the lower boundary of buoyancy-dominated accumulation (LBBA). The results indicated that the thickness of the source rocks dominated by mudstone was distributed widely, with an average value of more than 45 m. The sedimentary environment was salty lacustrine deposits. They have a high content of total organic carbon (TOC) with an average value of 4.80 wt%, the kerogen is mainly type III with minor type II, and the thermal evolution has entered the high to over mature stage. The hydrocarbon generation threshold was determined to be 0.5%Ro, while the hydrocarbon expulsion threshold and the LBBA were determined to be 0.83%Ro and 1.12%Ro, respectively. The efficiency of hydrocarbon expulsion was relatively high, with an average of about 56%. Also, the maximum hydrocarbon generation and expulsion intensity reached to 110 × 108 m3/km2 and 53 × 108 m3/km2. The amounts of hydrocarbon generation, expulsion and residual associated with the T3x3 source rocks were 125.68 × 1012m3, 70.38 × 1012m3, and 55.30 × 1012m3, respectively. Under the criterion condition of the LBBA, the conventional gas resource was 7.21 × 1010m3, the tight gas resource was 294.34 × 1010m3, and the shale gas resource was 2488.50 × 1010m3. It indicated good prospects for exploration.

Organic geochemistry of the Upper Triassic T3x5 source rocks and the hydrocarbon generation and expulsion characteristics in Sichuan Basin, central China

The Upper Triassic Xujiahe Formation is a key target layer for development of tight sandstone gas reservoirs in the Sichuan Basin. Most of the previous work focused on the main reservoirs such as T3x2 and T3x4 with lack of research attention on T3x5, an equally important source-reservoir unit. Here we examine the organic matter and source rock distribution in the T3x5 using rock pyrolysis, asphalt extraction, and gas chromatography. The thickness of T3x5 source rocks reduces from west and northwest Sichuan Basin to east and southeast Sichuan Basin. The main sedimentary facies are salt lakes and deltas, of which the organic matter originated from aquatic organisms and a small amount of terrestrial matter. The abundance of total organic carbon (TOC) in T3x5 is relatively high, at values of 0.07%–7.2%. According to the vitrinite reflectance (Ro), pyrolysis, and gas chromatography measurement results, the T3x5 source rocks are at the stage of mature to over-mature, and their hydrocarbon expulsion threshold and hydrocarbon expulsion peak correspond to Ro of 1.05% and 1.23%, respectively. Furthermore, a hydrocarbon generation center and a hydrocarbon expulsion center are formed horizontally, with the maximum hydrocarbon generation intensity of 50 × 108 m3/km2 and the maximum hydrocarbon expulsion intensity of 48 × 108 m3/km2. The natural gas resource is 3.19–5.36 × 1012 m3, indicating great exploration potential.

Data for: Organic geochemistry of the Upper Triassic T3x5 source rocks and the hydrocarbon generation and expulsion characteristics in Sichuan Basin, Central China

Abstract The Upper Triassic Xujiahe Formation is a key target layer for development of tight sandstone gas reservoirs in the Sichuan Basin. Most of the previous work focused on the main reservoirs such as T3x2 and T3x4 with lack of research attention on T3x5, an equally important source-reservoir unit. Here we examine the organic matter and source rock distribution in the T3x5 using rock pyrolysis, asphalt extraction, and gas chromatography. The thickness of T3x5 source rocks reduces from west and northwest Sichuan Basin to east and southeast Sichuan Basin. The main sedimentary facies are salt lakes and deltas, of which the organic matter originated from aquatic organisms and a small amount of terrestrial matter. The abundance of total organic carbon (TOC) in T3x5 is relatively high, at values of 0.07%–7.2%. According to the vitrinite reflectance (Ro), pyrolysis, and gas chromatography measurement results, the T3x5 source rocks are at the stage of mature to over-mature, and their hydrocarbon expulsion threshold and hydrocarbon expulsion peak correspond to Ro of 1.05% and 1.23%, respectively. Furthermore, a hydrocarbon generation center and a hydrocarbon expulsion center are formed horizontally, with the maximum hydrocarbon generation intensity of 50 × 108 m3/km2 and the maximum hydrocarbon expulsion intensity of 48 × 108 m3/km2. The natural gas resource is 3.19–5.36 × 1012 m3, indicating great exploration potential.

Assessment of hydrocarbon generation potential and thermal maturity of the offshore Mannar Basin, Sri Lanka

The Mannar Basin is an under-explored offshore sedimentary basin in terms of petroleum geology. The Cretaceous to Paleogene cutting samples were collected in three offshore exploration wells (i.e. the Dorado North, Dorado and Barracuda) in the Mannar Basin. In this study, kerogen type, quantity and thermal maturity of sedimentary organic matter were ascertained using Rock–Eval pyrolysis and vitrinite reflectance analyses. In addition, 1-D basin modelling was used to analyse the timing of hydrocarbon generation in the Mannar Basin. Total organic carbon (TOC) contents and total hydrocarbon potential are higher in the Cretaceous calcareous mudstones than in the Paleogene calcareous silty/sandy mudstones. TOC contents show a negative correlation with oxygen index. Hydrogen index and oxygen index values range from 77 to 785 mg HC/g TOC and from 25 to 165 mg HC/g TOC, respectively. Organic matters were identified as mixed Type II–III and Type III kerogen. Maturity expressed in term of Tmax and vitrinite reflectance range from 332 to 456 °C and from 0.26 to 1.49%, respectively. It indicates both immature and mature sediments. In general, maturity values are relatively high in the Late Cretaceous sediments (Tmax, from 332 to 456 °C, average = 423 °C ± 25) compared to the Paleogene sediments (Tmax, from 388 to 431 °C, average 419 °C ± 10). Geochemical proxies show that oil and gas prone (Type II–III) and gas prone (Type III) kerogen-rich Late Cretaceous sediments of the Dorado and Barracuda wells have principally achieved maturity levels for oil window. Therefore, it suggests incomplete thermal conversion for the wet gas generation in the northeast part of the Mannar Basin. In the 1-D basin modelling, the maximum hydrocarbon generation was observed during the Neogene Period in the Late Cretaceous sediments of the deeper Barracuda well.

Shale Oil Assessment for the Songliao Basin, Northeastern China, Using Oil Generation–Sorption Method

This study was performed in order to evaluate shale oil in the first member of the Qingshankou formation (K2qn1) in the Songliao basin in northeastern China. The evaluation was carried out using immature type I kerogen kinetics in a closed system, two wells drilled into oil prone source rocks, in order to apply Rock-Eval, mineral composition and residual hydrocarbon analysis, and the hydrocarbon sorption method. The “oil windows” for K2qn1 in mudstone and shale wells range from 0.6% to 1.05%, with maximum hydrocarbon generation at around 420 mg of hydrocarbon per gram of total organic carbon. In addition, the brittle mineral contents of K2qn1 conform to the requirements for industrial oilfield development and exploitation. Our results demonstrate that there is clear potential for shale oil exploration in the K2qn1; a highly potential zone is defined as low risk at burial depths of greater than 2065 m for well H14, while well X83 exhibits relatively discrete depth based on oil saturation and production ind...

Clay-organic association as a control on hydrocarbon generation in shale

Programmed pyrolysis experiments investigating the influence of the mineral matrix on hydrocarbon generation from organic compounds have shown inconclusive results in past studies. This study tests the hypothesis that the inhibitory vs catalytic influence of clay minerals is dependent on the physical association of the mineral matrix with organic compounds by comparing natural samples from two shale formations with different mineral-organic associations. Samples from the Miocene Monterey Formation have a greater area of surface contact between organic matter and mineral surfaces when compared to the more particulate texture and discrete nature of the organic matter in the samples from the Permian Stuart Range Formation. Comparison of kerogen extracts to the whole rock (containing mineral and organic matter) samples during programmed pyrolysis shows higher hydrocarbon generation from isolated kerogen compared to the whole rock sample it was extracted from in both the Monterey and the Stuart Range Formation samples. The difference between extracted kerogen and whole rock samples is greater and more variable (56–210mgHC/gTOC) in the Stuart Range than the Monterey Formation (85–142mgHC/gTOC) implying greater hydrocarbon retention by the free mineral surfaces. The temperature of maximum hydrocarbon generation (Rock-Eval Tmax) is greater in whole rock than kerogen isolates (20°C mean) in the Monterey Formation samples, but shows negligible difference (2°C mean) in the samples from the Stuart Range Formation. Standard kerogen typing using Rock-Eval pyrolysis data places the same kerogen as Type II to Type III on a modified Van Krevelen diagram depending whether it is isolated or pyrolysed with its mineral host. This study identifies that not only the bulk mineralogy and kerogen type but also the degree of surface contact of the phases influence hydrocarbon generation.

Stratigraphy and structure of the Drake Point Anticline, Sabine Peninsula, Canadian Arctic Islands

Modern processing methods were applied to 3400 line-kilometres of legacy seismic data from Sabine Peninsula of Melville Island in the Canadian Arctic Islands. Post-stack reprocessing improved the imaging, allowing new insight into the following issues: the northern extent of lower Paleozoic source rocks, extensional structures and rock types in the upper Paleozoic succession, the timing of the gentle Drake Point Anticline; and the age and extent of igneous sills. The central part of Sabine Peninsula is underlain by a half-graben containing upper Paleozoic strata. The half-graben fill is intersected by just one well, but it likely contains Upper Carboniferous to Lower Permian strata. The two largest conventional gas fields in Canada (Drake Point and Hecla) are hosted in Mesozoic strata within a gentle anticline that partially overlies the half-graben. Previously, the Drake Point Anticline was interpreted to have been formed during Eocene time. We propose that 280 m of the 430 m of structural relief on the Drake Anticline formed in response to uplift at the axis of the anticline in the Early Cretaceous, as shown by thinning of the Lower Cretaceous Christopher Formation over the Drake Anticline. The remaining 150 m of structural relief formed by differential movement between the Marryatt Point Syncline and Drake Point Anticline after the Early Cretaceous. Early Cretaceous relief on the Drake Point Anticline means it was at least partially present at the time of maximum hydrocarbon generation in the Late Cretaceous.

Pyrolysis and Hydrocarbon Source Bed Potential of the Upper Devonian Woodford Shale, Hovey Channel, Southern Permian Basin, West Texas

The Upper Devonian Woodford Shale in the Hovey Channel area, southern Permian basin, is 50 m thick and composed largely of brown to black, pyritic, spore-bearing, organic-rich, fissile shale an chert. Total organic carbon, distillable hydrocarbons, genetic potential, organic carbon index, hydrogen index, temperature of maximum hydrocarbon generation, and kerogen transformation index of the Woodford Shale suggest a matured to overmatured, gas-generating source bed. The total organic carbon content of the formation ranged from a low of 0.77% in the cherty samples to a high of 4.59% in a shaley sample, averaging 2.18%. Distillable hydrocarbon content of the samples is fairly high (averaging 1.72 mg HC/gm{degree} rock), varying from 0.90 mg HC/gm{degree} rock to 3.22 mg HC/gm{degree} rock. Genetic potential evaluated in terms of both residual and total generative potential showed above average potential, averaging 3.25 mg HC/gm{degree} rock for the residual and 4.90 mg HC/gm{degree} rock for the total, respectively. Live organic carbon index values ranged from 11-28%, characterizing the formation as a moderate to good source bed. Hydrogen index values ranged from 73 mg HC/gm{degree} C org to 155 mg HC/gm{degree} C org, suggesting overmaturity and gas-generation potential of the source bed. Temperature of maximum hydrocarbon generation valuesmore » and kerogen transformation ratio values (averaging 0.34) also indicate overmatured nature of the Woodford Shale.« less

Quantitative Evaluation of Lower Cretaceous Mannville Group as Source Rock for Alberta's Oil Sands

The Western Canada sedimentary basin hosts about 12 billion bbl of conventional oil in Devonian to Cretaceous reservoirs. Lower Cretaceous oil sands contain an additional 1.3 trillion bbl in place. The oil sands represent the biodegraded remnants of supergiant conventional oil deposits, the source for which has been thought to be mature rocks of the equivalent-age Mannville Group. This work shows, however, that the known Mannville rocks alone are incapable of generating the required volume of hydrocarbons. The volume of hydrocarbons generated in the Mannville beneath central Alberta was calculated by combining measured geochemical and geologic data with Lopatin's method for thermal maturation. Original hydrocarbon-generative capacity of the Mannville rocks was calculated from geochemical analyses of immature samples. Using average values for total organic carbon (TOC) (1.3%) and Rock-Eval hydrogen index (100 mg HC/g TOC), maximum hydrocarbon generation per unit volume of source rock was calculated. The maturation model was then employed to estimate the extent to which maximum yield has actually been achieved. Total volume of source rock in the basin was obtained from isopach maps of Mannville shale. Multiplication of actual oil generation per unit volume by source rock volume gave a generated volume of 450 billion bbl. These calculated values are exceedingly optimistic, however, because they ignore inefficiencies in expulsion and migration. Inclusion of oil generated in Mannville-equivalent source rock in the Foothills belt would less than double this quantity, assuming that source potential there is similar to that of the central Alberta rocks. It is clear that the Mannville Group of the Western Canada sedimentary basin cannot be the major source of Alberta's oil-sand hydrocarbons. Either the hydrocarbons were generated in as yet undocumented, very organic-rich Mannville-equivalent rocks in the Foothills, or they are derived from multiple sources throughout the basin.

Was the Mannville Group the Source for Alberta's Heavy Oils?: ABSTRACT

The Western Canadian basin hosts about 12 billion bbl of conventional oil in Devonian to Cretaceous reservoirs. Lower Cretaceous heavy-oil sands contain 1,300 to 2,600 billion bbl in place. They represent the biodegraded remnants of supergiant conventional deposits, the source for which has been thought to be mature rocks of the equivalent-age Mannville Group. This work shows, however, that the Mannville rocks alone are incapable of generating the required volume of hydrocarbons. Volume of hydrocarbons generated in the Mannville under central Alberta was calculated by combining measured geochemical and geologic data with a model (modified from Lopatin's method) for thermal maturation. Original hydrocarbon generative capacity of the Mannville rocks was calculated from geochemical analyses of immature samples. Using average values for TOC (1.3%) and Rock-Eval Hydrogen Index (100 mg HC/g TOC), maximum hydrocarbon generation per unit volume of source rock was calculated. The maturation model was then employed to estimate the extent to which maximum yield has been achieved. Total volume of source rock in the basin was obtained from isopachs of Mannville shale. Multiplication of actual oil generation per unit volume by source rock volume gave a generated volume of 450 billion bbl. Inclusion of oil generated in the Foothills belt would less than double this number. These calculated values are exceedingly optimistic, however, because they ignore inefficiencies in expulsion and migration. It is therefore clear that the Mannville Group cannot be the major source of the heavy oils. Dominant contributions probably come from Paleozoic and other Mesozoic rocks. End_of_Article - Last_Page 610------------

Stratigraphic Distribution of Hydrocarbons with Differing API Gravities in East Texas Basin: ABSTRACT

In studying the stratigraphic and geographic distributions of oils initially produced from seven East Texas Cretaceous formations, the effects of depth, temperature, and rate of burial on increasing hydrocarbon maturation, expressed as increasing API gravity, can be determined statistically. Analysis of both linear-regression and data-density trends indicates that API gravity increases as the oil matures during burial. Linear-regression analyses yield positive API-gravity gradients and low correlation coefficients for the data populations. Data-density trends show well-delineated and differing API-gravity gradients with ordinal and abscissal limits. From younger to older formations, there are two main trends of increasing API gravity. The oil from sub-Clarksville reservoirs, showing the best-delineated high API-gravity gradient, represents one main trend. The oils from Woodbine and Paluxy reservoirs show both main trends; API gravity increases rapidly, then slowly, as burial continues. The oils from Glen Rose, Rodessa, Pettet, and Travis Peak reservoirs show the second main trend, that is, a low API-gravity gradient. A composite plot for the seven formations, showing one curvilinear trend, with both high and low API-gravity gradients, implies different radiocarbon maturation rates tor the East Texas oils. Almost all maturation trends are within a temperature range of 110 to 250°F (43 to 121°C), which falls below the the retical temperature window of 250 to 350°F (121 to 177°C) for maximum hydrocarbon generation. For each formation, the geographic distributions of API gravity, depth of burial, and formation temperature establish a stratigraphic, geographic, and tectonic framework for studying the statistical distributions. Generally, high API gravity oils have been produced from the deep southern and shallow eastern parts of the basin. Lower API gravity oils are produced from the northern and western shallow parts of the basin. End_of_Article - Last_Page 1428------------