Hydrocarbon Generation History Research Articles

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.

Palaeofluid evolution process in Well Block Tubei 1 in the Kuqa Depression, Tarim Basin

Under the joint action of gypsum-salt rocks and faults, fluid evolution process is complicated in the northern Tuzimazha, Kuqa Depression, Tarim Basin. In the past, however, the oil and gas distribution rules in this area were less studied, so the related understanding was insufficient. In this paper, the reservoirs in Well Block Tubei 1 were analyzed by means of fluid inclusion and quantitative grain fluorescence (QGF) techniques. Based on tectonic evolution history, burial history, thermal history and hydrocarbon generation history, the paleofluid evolution process in this area was reproduced. It is shown that the well block experienced hydrocarbon charge in two periods. The first period is the early–middle stage (16–9 Ma) of Miocene Kangcun Fm (N1–2k), when it was charged with oil, with the corresponding characteristics of yellow and white–yellow fluid inclusion fluorescence and the QGF Index higher than 4, indicating that there were paleo-oil reservoirs at the early stage of the reservoirs. And at the late stage, the fluids that were accumulated at the early stage escaped because the gypsum-salt rocks were cut by faults, and bitumen remained in the reservoirs. It is also the evidence for the escaping of the early charged oil that the total scanning fluorescence (TSF) of the hydrocarbon adsorbed to the surface of the current reservoirs is generally unimodal. The second period is the late stage (about 3 Ma) of Pliocene Kuqa Fm (N2k), when the natural gas and light oil charging occurred. Correspondingly, there are two inclusions, i.e. black gaseous hydrocarbon inclusion and blue fluorescence inclusion located along the edge of the quartz grains. At this stage, the gypsum-salt caprocks deepened and their sealing capacity was recovered due to a strong plastic flow. Moreover, the trap was uplifted violently under the effect of Himalaya orogeny, and a large amount of natural gas and a little light oil were accumulated.

Geochemical characteristics and hydrocarbon generation modeling of the Kazhdumi (Early Cretaceous), Gurpi (Late Cretaceous) and Pabdeh (Paleogene) formations, Iranian sector of the Persian Gulf

The marls and argillaceous limestones of the Early Cretaceous Kazhdumi, Late Cretaceous Gurpi and Paleogene Pabdeh formations are considered as potential source rock candidates in this area. The present study characterizes hydrocarbon potential, type of organic matter and thermal maturity of these three formations in the Iranian sector of the Persian Gulf. Also, 1D basin modeling was used to analyse the burial history and timing of hydrocarbon generation in these formations. A total of 179 cutting samples from 25 wells were evaluated through Rock–Eval pyrolysis and organic petrography. Average total organic carbon (TOC) content for the samples of the Kazhdumi, Gurpi and Pabdeh formations that were analyzed for the current study is 1.2, 0.9 and 1 wt.%, respectively. All three formations show lower TOC contents in central part relative to eastern and western parts of the study area. Rock–Eval pyrolysis and organic petrography show that the organic matter in all three formations is mainly composed of Type II and mixed Type II–III kerogen. This study shows that the Kazhdumi, Gurpi and Pabdeh formations in Iranian offshore areas are not as rich as onshore areas, and specifically in the Dezful Embayment, in terms of organic matter quantity and quality. Thermal history modeling indicates that constant heat flow values in the range of 64–73 mW/m2 gives the best fit between measured and calculated vitrinite reflectance and bottom hole temperature. The Rock–Eval Tmax, vitrinite reflectance and the generated models suggested that in the eastern parts of the study area, the Kazhdumi Formation is at the last stage of oil generation and the Gurpi and Pabdeh formations are within the main oil generation window. Hydrocarbon generation began in the Early Eocene, Middle Eocene and Early Miocene in the Kazhdumi, Gurpi and Pabdeh formations, respectively. In the western parts of the Persian Gulf, the Kazhdumi Formation is within the main oil window with hydrocarbon generation took place during the Oligocene and the Gurpi and Pabdeh formations are early mature and immature, respectively. All three formations are thermally immature in the central part of the Persian Gulf. The Kazhdumi Formation shows positive correlation with the crude oils of the Cretaceous and Tertiary reservoirs taken from the northwestern Persian Gulf. The Pabdeh and Gurpi formations show no correlation with crude oils produced in the northwestern and southeastern Persian Gulf.

Source rock characteristics and hydrocarbon expulsion potential of the Middle Eocene Wenchang formation in the Huizhou depression, Pearl River Mouth basin, south China sea

The Middle Eocene Wenchang (WC) formation in the Huizhou depression of the Pearl River Mouth basin is an important geological element for petroleum exploration in the South China Sea. In this study, the geological and geochemical characteristics of the WC source rocks, including the distribution, sedimentary environment, organic matter type, hydrocarbon generation potential and thermal maturity were investigated. Hydrocarbon generation history and hydrocarbon expulsion intensity and quantities were evaluated through one dimensional basin modelling and an improved hydrocarbon generation potential methodology. The WC source rocks are widely distributed and have an elevated thickness (mostly thicker than 200 m, with a maximum thickness greater than 1000 m); they were deposited in a lacustrine weak oxidation–weak reduction sedimentary environment with low salinity. The source rocks have low to high organic matter abundance (TOC mainly ranges from 0.27 to 3.59 wt% with an average of 1.39 wt%) dominated by II1–type and II2–type kerogen, resulting in significant hydrocarbon generating potential under moderate–high thermal evolution (Ro mainly ranges from 0.65% to 1.2% on the margins of sags and greater than 1.2% in the centre of sags). The source rocks became mature (Ro = 0.5%) in the early Miocene and began to generate hydrocarbons. They reached the hydrocarbon expulsion threshold at 0.8% Ro and the hydrocarbon expulsion rate became greatest at 1.1% Ro. The expulsion intensities in the H26 sag, H21 sag, X24 sag and X23 sag are relatively large, with their greatest expulsion intensities being 104 × 106, 71 × 106, 62 × 106 and 53 × 106 t/km2, respectively. The comprehensive hydrocarbon expulsion efficiency was approximately 75%. About 690.1 × 108 t of hydrocarbons were expulsed from the WC source rocks in the Huizhou depression.

Charging history of Paleogene deep gas in the Qibei sag, Bohai Bay Basin, China

The Qibei sag (QS), at the western region of the Bohai Bay Basin (BBB), eastern China, has made significant progress in the deep gas exploration recently, indicating that the deep gas reservoirs have good exploration prospects. The deep gas reservoirs within the second member of the Shahejie Formation of the Paleogene (E2s2) are buried at approximately 5000 m. The sources and hydrocarbon accumulation mechanisms were investigated by analyzing the regional structure, integrating geologic and geochemical parameters of source rocks and natural gas. Analyzing results show that, in the QS and adjacent areas (QSAA), three sets of source rocks (E2s1, E2s2, E2s3) were developed, which differ in organic chemical characters, but have abundant organic matters in fair-good standard. Affected by burial history, E2s3 source rocks have entered into the high mature-over mature stage and E2s1 source rocks are mainly in mature stage. The methane content of natural gas (78%∼91%), the methane carbon isotope value (−41.3‰∼−34.6‰) and the positive carbon isotope sequence (δ13C1<δ13C2<δ13C3<δ13C4) indicate that the deep gas is organic origin and mainly from thermogenic gas. The relationship between light hydrocarbon character parameters and thermal evolution degree indicates that the deep gas in the QS is mainly from E2s2 and E2s3 source rocks of the sag. Since the different hydrocarbon generation history, there exist two hydrocarbon accumulation periods in QS, and the early period is characterized by oil accumulation, which occurs at the shallows, such as the Binshen6 block; the late period is characterized by gas accumulation, which happens in the depth mostly, such as the Binshen22 block. The different hydrocarbon generation history results in the relative enrichment of gas in the depth and the phenomenon of oil–gas inversion.

Quantitative estimation of overpressure caused by gas generation and application to the Baiyun Depression in the Pearl River Mouth Basin, South China Sea

AbstractHydrocarbon generation can yield high fluid pressures in sedimentary basins as the conversion of solid kerogen to hydrocarbons can result in an increase in fluid volume. To quantify the relationship between gas generation and overpressure in source rocks, a set of equations for computing the pressure change due to gas generation has been derived. Those equations can be used to quantitatively estimate overpressure generated by type III kerogen in source rocks by considering gas generation and leakage, gas dissolution in formation water and residual oil, thermal cracking of oil to gas, and hydrocarbon episodic expulsion from source rocks. The equations also take consideration of other factors including source rock porosity, transformation ratio, total organic carbon (TOC), hydrogen index, and compressibility of kerogen, oil, and water. As both oil and gas are taken into account in the equations, they can also be used to estimate the evolution of overpressure caused by hydrocarbon generation of type I and type II kerogen source rocks. Sensitivity analyses on the type III kerogen source rock indicate that hydrogen index is the most influential parameter for overpressure generation, while TOC and residual gas coefficient (β: ratio of residual gas over the total gas generated) have a moderate effect. Overpressure can be generated even if the gas leakage/loss in the source rock is up to 80% of the total gas generated. This suggests that the internal pressure seal of the source rock is not a critical factor on the pressure change as long as the source rocks are capable of sealing liquid oil. The equations were applied to evaluate the overpressure in the Eocene–Oligocene Enping Formation source rocks due to hydrocarbon generation in the Baiyun Depression, the Pearl River Mouth Basin by considering the source rock properties, hydrocarbon generation history, and hydrocarbon expulsion timing. Two episodes of overpressure development due to gas generation and release were modeled to have occurred in the Enping Formation source rock since 16 Ma. The overpressure release at 10.2–5.3 Ma via hydrocarbon expulsion was apparently related to the Dongsha phase of tectonic deformation, whereas the pressure release at 2–0 Ma was due to pressure generation that was exceeded the fracture‐sealing pressure in the source rocks.

Unconventional gas prospectivity of the Cooper Basin

The Cooper Basin is an Upper Carboniferous–Middle Triassic intracratonic basin in northeast SA and southwest Queensland. The basin is Australia's premier onshore hydrocarbon-producing province and is nationally significant due to its provision of domestic gas for the east coast gas market. Exploration activity in the region has recently expanded with numerous explorers pursuing newly identified unconventional hydrocarbon plays. While conventional gas and oil prospects can usually be identified by 3D seismic, the definition and extent of the undiscovered unconventional gas resources in the basin remain poorly understood. This extended abstract reviews the hydrocarbon prospectivity of the Cooper Basin with a focus on unconventional gas resources. Regional basin architecture, characterised through source rock distribution and quality, demonstrates the abundance of viable source rocks across the basin. Petroleum system modelling, incorporating new compositional kinetics, source quality and total organic carbon (TOC) map, highlight the variability in burial, thermal and hydrocarbon generation histories between depocentres. The study documents the extent of a number of unconventional gas play types, including the extensive basin-centred and tight gas accumulations in the Gidgealpa Group, deep-dry coal gas associated with the Patchawarra and Toolachee formations, as well as the less extensive shale gas plays in the Murteree and Roseneath shales.

Analyzing geochemical characteristics and hydrocarbon generation history of the Middle and Upper Jurassic source rocks in the North Yellow Sea Basin

The North Yellow Sea Basin is still in the early stages of exploration. Oil has been recovered from Mesozoic sandstone intervals, but the characteristics of source rocks are not fully understood in this basin. In this study, the geochemical characteristics and the hydrocarbon generation history of the Jurassic source rocks in the North Yellow Sea Basin have been evaluated. The major findings of the study are as follows: (1) The Middle and Upper Jurassic dark gray and gray black mudstones are the main source rocks in the North Yellow Sea Basin. (2) The organic matter of the Middle Jurassic source rocks is derived from terrigenous higher plants and the type of organic matter is predominantly Type III kerogen. The content of organic carbon is moderate for this type of kerogen, and the hydrogen index (HI) is below 100 mg HC/g TOC mostly; therefore, the Middle Jurassic source rocks will produce gas mainly. The organic matter in the Upper Jurassic source rocks was derived from a mixture of terrigenous higher plants and aquatic lower organisms, and is characterized by the coexistence of Types I, II and III kerogen, there are some excellent local source rock intervals with high organic carbon and higher HI values, which constitute the main oil source rocks. (3) The Middle Jurassic source rocks have fair-poor hydrocarbon-generative potential and the Upper Jurassic source rocks have fair-good hydrocarbon-generative potential. (4) Hydrocarbon generation history models indicate that the Middle Jurassic source rocks reached late mature stages and the Upper Jurassic source rocks reached the oil window at the present-day. These two sets of source rocks all didn’t reach the peak of oil and gas generation in NYS2 well.

Thermal effect of intrusive rock on hydrocarbon generation from organic matter

Igneous intrusions may contain sufficient heat that can have an effect on the generation of hydrocarbons from the source rock. This model is tested in the Yingtai Fault Depression of the southern Songliao Basin, where intrusive rocks are abundant. A heat conduction model and kinetic models of hydrocarbon generation are calibrated by using the hydrocarbon yield data from pyrolysis experiment and vitrinite reflectance values of source rocks adjacent to intrusive rocks. Our analysis shows that the intrusive rock contributes to the hydrocarbon generated from organic matter in the neighboring rock nearby the intrusive rock. For instance, as the distance to the contact surface is decreased, the maturity of the organic matter of neighboring rock increases gradually, H/C and TOC decreases gradually. The results have revealed that the extents affected by intrusive rocks with different thicknesses at various initial temperatures are basically not more than twice of the thickness of the intrusive rock. For multiple intrusive rocks, the extent and the degree of the thermal effect during a contemporaneous emplacement and emplacement at different stages are obviously different. The extent and degree of the thermal effect during contemporaneous emplacement are normally large. The degrees of thermal effect are different for neighboring rocks with different initial maturity, which is affected by the intrusive rock with the same parameters (such as thickness or initial temperature). Setting 0.9 % as the maturity (Ro) limit, at maturity less than 0.9 %, the Ro thermal effect (increment amount of Ro) increases as the initial maturity of the neighboring rock rises. At maturity of more than 0.9 %, it decreases as the initial maturity of neighboring rock rises. The results of the geological application have shown that the hydrocarbon generation history of source rock in an area with intrusive rocks can be solved effectively by an integrated use of the heat conduction model and the kinetic model of hydrocarbon generation.

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

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

The Maximum Burial Depth in Hydrocarbon Source Rocks on Kongquehe Slope in the Tarim Basin

The strata of the Kongquehe slope in the Tarim basin have suffered from long-term denudation, causing the determination of maximum ancient buried depth in mainly hydrocarbon source rocks to be very difficult. The denudation restricts the conduct of research into the hydrocarbon generation history of the source rocks. Through the use of drilling, seismic, logging, and geochemical data, calculation of the amount of denudation of the main unconformable surface, consideration of the present residual thicknesses of major hydrocarbon source rocks and other data, the authors determine maximum ancient buried depth in four major hydrocarbon source rocks and determines the time required to reach the maximum ancient buried depth. The authors have ascertained four main results through comprehensive analysis. (a) A majority of the Jurassic hydrocarbon source rock passed the hydrocarbon-generating threshold during the Neogene period and are now in the early-mature to mature stage. (b) Carboniferous hydrocarbon source rock is only distributed in the Caohu depression, having crossed the hydrocarbon-generating threshold in the Cretaceous period, and is now in the mature to late-mature stage. (c) Most of the middle-upper Ordovician hydrocarbon source rock crossed the hydrocarbon-generating threshold in the late Ordovician period and is now in the late-mature to over-mature stage. There are two blocks in the east research area that appear to contain the maximum ancient buried depth which may have experienced secondary hydrocarbon generation in the late Silurian. (d) Cambrian-Lower Ordovician hydrocarbon source rock is in the late-mature to over-mature stage and may have experienced secondary hydrocarbon generation in the Cenozoic period in most of Kongquehe area.

Evaluation of effective carrier system and function on hydrocarbon accumulation in Gaoyou Sag, Subei Basin, China

Effective carrier system comprises carrier beds which transport hydrocarbons. The spatial and temporal effectiveness of carrier system is identified according to the relevance of hydrocarbon show, hydrocarbon inclusion and sealing ability of fault to hydrocarbons distribution, together with matching relation of activity history of fault and hydrocarbon generation history of source rock. On the basis of the above considerations, transporting ability of effective carrier system can be evaluated using parameters such as fluid potential, porosity and permeability, spatial coefficient of effective pathway as well as activity rate of fault. Additionally, a new concept of “transporting threshold porosity” was proposed. Five styles of effective carrier systems were established in Gaoyou Sag, displaying either layered or zonal distribution characteristics, and transporting time ranges from the sedimentary time of E2d2 to early stage of sanduo uplift. Effective carrier systems can be described to be lowly-efficient and highly-efficient. Major faults (convex or steep fault plane) with activity rate greater than 20 m/Ma and structure ridges of sand layers with spatial coefficient of effective pathway greater than 25% are defined to be highly-efficient carrier beds. Hydrocarbons are concentrated around high-efficient carrier beds and E1f traps of northern shanian area are predicted to have great potential.

Geothermal History of Hydrocarbon Generation of Wells in the North Western Desert, Egypt

Forty-two rock samples representing seven formations (Ras Qattara, Khatatba, Masajid, Alam El Bueib, Kharita, Baharyia, and Abu Roash) and six thermal burial history modeling of wells (Tut-1x, Kahraman-1, Yasser-1, Salam-3x, Meleiha-4x, and El-Kharita-1x) were used to characterize potential source rocks for generating capability of oil preservation in terms of hydrocarbon generation and expulsion. The results showed that Ras Qattara Formation started to generate hydrocarbons during Paleocene, Khatatba Formation during Late Cretaceous-Eocene, Masajid Formation during Late Cretaceous-Late Miocene, Alam El Bueib Formation during Late Cretaceous-Oligocene, and Kharita Formation during Miocene times. Bahariya and Abu Roash formations are still immature and do not reach the onset of hydrocarbon generation.

A method of calculating hydrocarbon generation history - hydrogen index method (TTPCI-IH method)

The traditional TTI-Ro method uses virtinite reflectance as the indicator of the organic matter maturity, and then makes it a dominant parameter during the simulation of organic matter hydrocarbon generation history. However, this method only takes virtinite reflectance as a function of time and temperature, but ignores not only the influence of pressure and catalyst, but also the follow-up generation contradiction. Actually, this method is difficult to correctly describe the organic matter hydrocarbon generation history. By a variety of analysis and comparison, hydrogen index (IH) is found to be the parameter with the above characteristics. IH is also the synthetical effect result of time, temperature, pressure and catalyst and their dynamic change. So it is appropriate to use IH, instead of Ro, as the dominant parameter during the hydrocarbon generation history of organic matter. Then it is possible to establish a method on the basis of the hydrogen index to calculate the hydrocarbon generation history – the comprehensive simulation method of time, temperature, pressure, catalyst and index, called TTPCI-IH method. And it is successfully applied in hydrocarbon generation history simulation. The actual simulation results in Shengli oilfield show that TTPCI-IH method is obviously better than TTI-Ro method.

Reconstruction of burial history, temperature, source rock maturity and hydrocarbon generation in the northwestern Dutch offshore

Abstract3D basin modelling is used to investigate the history of maturation and hydrocarbon generation on the main platforms in the northwestern part of the offshore area of the Netherlands. The study area covers the Cleaverbank and Elbow Spit Platforms. Recently compiled maps and data are used to build the input geological model. An updated and refined palaeo water depth curve and newly refined sediment water interface temperatures (SWIT) are used in the simulation. Basal heat flow is calculated using tectonic models. Two main source rock intervals are defined in the model, Westphalian coal seams and pre-Westphalian shales, which include Namurian and Dinantian successions. The modelling shows that the pre-Westphalian source rocks entered the hydrocarbon generation window in the Late Carboniferous. In the southern and central parts of the study area, the Namurian started producing gas in the Permian. In the north, the Dinantian source rocks appear to be immature. Lower Westphalian sediments started generating gas during the Upper Triassic. Gas generation from Westphalian coal seams increased during the Paleogene and continues in present-day. This late generation of gas from Westphalian coal seams is a likely source for gas accumulations in the area.Westphalian coals might have produced early nitrogen prior to or during the main gas generation occurrence in the Paleogene. Namurian shales may be a source of late nitrogen after reaching maximum gas generating phase in the Triassic. Temperatures reached during the Mid Jurassic were sufficiently high to allow the release of non-organic nitrogen from Namurian shales.

Analysis on Migration Patterns and the Distribution of Oil-Gas Controlling Factors of Yushulin Area

In order to ascertain the oil and gas migration pattern and its effect on gas/oil distribution of Yushulin area of Sanzhao depression in Northern Songliao Basin, this paper makes a comprehensive analysis of the oil source condition, the source-reservoir-seal assemblage relationship, the oil and gas migration pathway and patterns in Putaohua and Fuyang oil reservoir, summarizes the oil and gas migration patterns of Yushulin area, and analyses different oil and gas migration pattern influence on oil/gas distribution in Yushulin area combined with structural history, hydrocarbon generation and expulsion history, sedimentary microfacies research. The results show that there are mainly four types of oil and gas migration patterns in Yushulin area: indigenous – downward type - vertical migration pattern, indigenous - normal type - vertical migration pattern, proximal - lateral migration pattern and proximal – “U” type - complex migration pattern.

Phase States of Hydrocarbons in Chinese Marine Carbonate Strata and Controlling Factors for Their Formation

Chinese marine strata were mainly deposited before the Mesozoic. In the Tarim, Sichuan and Ordos Basins, the marine source rocks are made of sapropelic dark shale, and calcareous shale, and they contain type II kerogen. Because of different burial and geothermal histories, the three basins exhibit different hydrocarbon generation histories and preservation status. In the Tarim Basin, both oil and gas exist, but the Sichuan and Ordos Basins host mainly gas. The Tarim Basin experienced a high heat flow history in the Early Paleozoic. For instance, heat flow in the Late Cambrian varied between 65–75 mW/m2, but it declined thereafter and averages 43.5mW/m2 in the current time. Thus, the basin is a “warm to cold basin”. The Sichuan Basin experienced an increasing heat flow through the Early Paleozoic to Early Permian, and peaked in the latest Early Permian with heat flows of 71–77 mW/m2. Then, the heat flow declined stepwise to the current value of 53.2 mW/m2. Thus, it is a generally a high heat flow “warm basin”. The Ordos Basin has a low heat flow for most of its history (45–55 mW/m2), but experienced a heating event in the Cretaceous, with the heat flow rising to 70–80 mW/m2. Thus, this basin is a “cold to warm basin”. The Tarim Basin experienced three events of hydrocarbon accumulations. Oil accumulation formed in the late stage of Caledonian Orogeny. The generation and accumulation of oil continued in the Northern and Central Tarim (Tabei and Tazhong) till the late Hercynian Orogeny, during which, the accumulated oil cracked into gas in the Hetianhe area and Eastern Tarim (Tadong). In the Himalaya Orogeny, oil cracking occurred in the entire basin, part of the oil in the Tabei and Tazhong areas and most of the oil in the Hetianhe and Tadong areas are converted into gas. In the Sichuan Basin, another triple-episode generation and accumulation history is exhibited. In the Indosinian Orogeny, oil accumulation formed, but in the Yanshanian Orogeny, part of the oil in the eastern Sichuan Basin and most of the oil in the northeastern part was cracked into gas. In the Himalayan Orogeny, oil in the entire basin was converted into gas. The Ordos Basin experienced a double-episode generation and accumulation history, oil accumulation happened in the early Yanshanian stage, and cracked in the late stage. In general, multiple phases of heat flow history and tectonic reworking caused multiple episodes of hydrocarbon generation, oil to gas cracking, and accumulation and reworking. The phases and compositions of oil and gas are mainly controlled by thermal and burial histories, and hardly influenced by kerogen types and source rock types.

Predicting the distribution of the tight sandstone gas in the Hechuan play, Sichuan Basin, China

Abstract The Hechuan gas play of the second member of the Xujiahe Formation (Xu-2) in Sichuan Basin of China has low porosity and permeability and is a typical tight sandstone gas resource play. During 2008, 64 wells were drilled in the Hechuan gas play in our study area, of which 34 wells tested gas with commercial flow. The proven reserves in the Hechuan block (HC1) are 4.1 TCF over an area of 505.2 km2. The probable reserves in the Tongnan block (TN2) are 4.2 TCF in an area of 437.3 km2. To forecast the resource potential and geographic distribution of the tight gas in the Hechuan play, we used a numerical method to characterize the continuous tight gas accumulations. Unlike the existing models for conventional resource estimation, the genetic method proposed here is based on the principles of a unique trapping mechanism and pooling dynamics of the tight gas accumulations. We assume that the over-pressure associated with hydrocarbon (gas) generation in the source rocks is the primary driving force for gas migration and accumulation in tight reservoirs. This approach takes into account the interrelationships among the free-gas pressure in the source rocks, the reservoir formation water pressure, the capillary pressure, the compaction history, and diagenetic and hydrocarbon generation history and processes. A numerical model is established to represent the equilibrant processes of the various pressure components and the charging height of the free-gas column. The simulation results on both the resource potential and geographic location are consistent with what has been discovered in the target blocks (HC1 and TN2) and the model also predicted that about half of the total tight gas resource remains undiscovered. Geographically, the remaining resources are distributed in the northeastern areas of the HC1 block, and in the north and southeast of the TN2 block.

Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)

Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)Burial history, thermal maturity, and timing of hydrocarbon generation were modelled for the Jurassic source rocks in the basement of the Carpathian Foredeep and marginal part of the Outer Carpathians. The area of investigation was bounded to the west by Kraków, to the east by Rzeszów. The modelling was carried out in profiles of wells: Będzienica 2, Dębica 10K, Góra Ropczycka 1K, Goleszów 5, Nawsie 1, Pławowice E1 and Pilzno 40. The organic matter, containing gas-prone Type III kerogen with an admixture of Type II kerogen, is immature or at most, early mature to 0.7 % in the vitrinite reflectance scale. The highest thermal maturity is recorded in the south-eastern part of the study area, where the Jurassic strata are buried deeper. The thermal modelling showed that the obtained organic matter maturity in the initial phase of the "oil window" is connected with the stage of the Carpathian overthrusting. The numerical modelling indicated that the onset of hydrocarbon generation from the Middle Jurassic source rocks was also connected with the Carpathian thrust belt. The peak of hydrocarbon generation took place in the orogenic stage of the overthrusting. The amount of generated hydrocarbons is generally small, which is a consequence of the low maturity and low transformation degree of kerogen. The generated hydrocarbons were not expelled from their source rock. An analysis of maturity distribution and transformation degree of the Jurassic organic matter shows that the best conditions for hydrocarbon generation occurred most probably in areas deeply buried under the Outer Carpathians. It is most probable that the "generation kitchen" should be searched for there.

Reservoir-forming conditions of Ordovician weathering crust in the Maigaiti slope, Tarim Basin, NW China

Abstract Based on comprehensive geophysics and geology data, the characteristics and reservoir controlling factors, as well as oil and gas distribution law and exploration direction, are analyzed for the Ordovician weathered crust in the Maigaiti slope and its periphery with paleo-uplift background in the Tarim Basin. Structural mapping and analysis reveal that the largest carbonate weathering crust is developed around the Maigaiti slope which forms a favorable reservoir-seal assemblage in combination with the overlying Silurian/Carboniferous mudstone. The Ordovician carbonates experienced multi-stages of karstification and are dominated by small-size fracture-vug reservoirs which are controlled by the karst paleogeomorphology, tectonism and lithology. Drilled wells are located mainly in the northern karst depression which has weak karstification and heavy filling. Paleogeomorphology reconstruction and seismic reservoir prediction suggest that reservoirs are well developed in the southern karst slope. The comprehensive analysis of structural revolution and hydrocarbon generation history demonstrates that the hydrocarbon migration and accumulation are controlled by the evolution and migration of the paleo-uplift. There are two charging stages: large scale oil accumulation in the late Hercynian period and adjustment and re-accumulation of oil cracked gas in the late Himalayan period. The Manan and Maixi slopes in the eastern and western sides of the paleo-uplift are the favorable areas for hydrocarbon accumulation and adjustment over a long period of time, have the conditions of forming large-scale carbonate fracture-vug type pools, and are important strategic relay exploration areas in the Tarim Basin.