Petroleum Generation Research Articles

REMOTE SENSING ANALYSIS AND NUMERICAL MODELLING OF SURFACE TEMPERATURE ANOMALIES OVER PETROLEUM ACCUMULATIONS: A CASE STUDY OF THE ALBORZ OILFIELD, CENTRAL IRAN

Petroleum accumulations may coincide with either positive or negative temperature anomalies, which are conventionally detected using in situ temperature measurements made in shallow boreholes 1‐3 m deep. Data gathered in this way, however, can be sparse and costly, and may require intensive fieldwork over a long time period. This article explores the possibility of detecting thermal anomalies associated with petroleum entrapment using satellite‐derived land surface temperature data. For this aim, a robust correction scheme based on a physically‐based land surface model was applied to night‐time kinetic temperature data derived from NASA's ASTER instrument. The numerical model, known as SKinTES, attempts to simulate diurnal effects and to remove them from the measured temperature data to yield a residual temperature anomaly map. The performance of this methodology was tested over the Alborz oilfield located on an anticline of the same name in the Qom region of Central Iran. The study area has an arid to semi‐arid climate and the surface geology is dominated by outcrops of the Lower Miocene Upper Red Formation. The modelling approach used successfully highlighted several negative temperature anomalies over the oil‐bearing parts of the Alborz structure. In comparison to the uncorrected data, the anomalies were shown to be highly enhanced in both spatial and magnitude terms. In addition, time series analysis indicated that the temperature anomalies were consistent over time. The authenticity of the anomalies was confirmed by a suite of in situ temperature measurements made at shallow boreholes. In conclusion, a unifying framework is proposed to explain the occurrence of both negative and positive temperature anomalies over petroleum accumulations. The new modelling and correction scheme is expected to broaden the application of remote sensing land surface temperature data not only in petroleum exploration but also in other types of geothermic investigations including geothermal exploration.

An experimental investigation on the CO2 storage capacity of the composite confining system

Assuring secure containment of stored CO2 is of paramount importance—for climate change mitigation, for permitting, and for reassuring the public. Regional seals, such as those sealing petroleum accumulations, have proven to be effective for securing CO2. However, the goal of permanent sequestration can also be satisfied with “composite confining systems” consisting of multiple, possibly discontinuous flow barriers that, in aggregate, create a system with very high permeability anisotropy and effectively retard the vertical migration of CO2. This study focuses on investigating the barrier characteristics necessary for effective containment of CO2, using both physical flow experiments and modified invasion percolation simulations. The simulations are calibrated to the physical experiments and are used to further extend the analysis. Results show that for a composite confining system, a) even barriers with low capillary entry pressure contrast to the underlying flow unit can divert rising CO2; b) curved or anticlinal barrier topography can enhance CO2 trapping; c) fining-upward gradations make little difference to barrier effectiveness or CO2 retention; d) longer barriers retain more CO2 regardless of barrier topography. Finally, field-scale simulations have demonstrated the importance of barrier length for increasing CO2 storage capacity. The results presented can be used to inform the development of new screening criteria for characterization and effectiveness of composite confining systems.

Petroleum accumulations in the tarim basin during various tectonic stages as revealed by U–Pb dating of multi-phase calcite veins in deeply buried carbonate reservoirs

Significant discoveries in deeply buried marine carbonate petroleum exploration have been made recently in the Tarim Basin, NW China. Constraining the evolutionary history of fluid activity and the process of oil charging in the deeply buried carbonate reservoirs is crucial for further hydrocarbon exploration and development. In this study, we conducted an integrated study combining petrography, geochemistry, fluid inclusion analysis, and in-situ U–Pb dating of multi-phase calcite veins collected from the Ordovician carbonate reservoirs, Akeyasu area, Tarim Basin. Four distinct phases of calcite veins were found within the Ordovician carbonate reservoirs. The U–Pb ages of these four phases of calcite veins are as follows: 459.8 ± 4.7 Ma, 418.8 ± 3.7 Ma, 329.7 ± 1.6 Ma to 310.0 ± 3.6 Ma, and 291.7 ± 6.1 Ma to 220.5 ± 7.3 Ma. These ages closely correspond to key tectonic events that influenced the study area, specifically, the Middle Caledonian, Late Caledonian, Middle Hercynian, and Late Hercynian orogenies, respectively. The first phase (C1) calcite veins are believed to have precipitated from meteoric water, closely associated with the first episode of oil charging. Phase Ⅱ (C2) calcite veins primarily formed from Early-Middle Ordovician formation water. Phase Ⅲ and phase Ⅳ (C3 and C4) calcite veins originated from Middle-Late Cambrian formation water and hydrothermal fluids, respectively. Significantly, the second and third episodes of oil charging occurred concurrently with the precipitation of C3 and C4 calcites. Seismic data analysis of Paleozoic strata in the Akeyasu area revealed four stages of fault activity, corresponding to the Early Caledonian, Middle Caledonian, Late Caledonian-Early Hercynian, and Middle-Late Hercynian orogenies. Our findings strongly suggest that the evolution of fluid activity and oil charging was primarily governed by regional orogeny. These large-scale tectonic shifts led to intensified fault activity, ultimately controlling fluid activity and oil charging dynamics. Furthermore, this intensified faulting eased the connection between deep fluid systems and the Ordovician carbonate reservoirs, serving as the primary conduits for fluid migration and oil charging within the deeply buried Ordovician carbonate reservoirs.

Unlocking the Mysteries of the Mishrif Formation: Seismic Data Reinterpretation and Structural Analysis for Reservoir Performance Optimization in the Garraf Oil Field, Southern Iraq

The seismic survey is based on the reflected wave’s inherent nature from the interface among layers, which depends on the layer's density and velocity. This is called acoustic impedance and is used to resolve the confusion associated with the stratigraphic structure of the Mishrif formations in the Garraf oil field. The seismic section of the Garraf oil field in Thi-Qar Province, south of Iraq, was analyzed and interpreted. Considering the most important petroleum accumulation reservoir in the Garraf oil field, to update the structural images of the Mishrif Formation. A seismic study of the actual amplitude reflections, temporal maps, and three-dimensional depositional models demonstrated that the Mishrif Formation generate hydrocarbon from an individual structural trap in the presence of oil. Numerous abrupt discontinuities were observed in the seismic reflectors of the reservoir units of the Mishrif Formation, suggesting either a reef or a fault. The correct probability can be shown by establishing a historical match between the reservoir model and the actual behavior of the reservoir or by running a 3D vertical seismic profile log (VSP), which is more precise than the seismic survey previously used to explore faults.

Reservoir properties of effusive rocks of the Muradkhanli field (Azerbaijan)

The presence of oil accumulations in igneous rocks has been known for quite a long time. Geologists estimate that oil reserves in eruptive and weathered metamorphic rocks reach 1 % of the world’s proven oil reserves. At the Shaimskoye field (Western Siberia), oil is found in the weathered granites of the basement. Oil has been found in eruptive rocks in Texas (USA) fields, the most famous of which is the Litton Springs field. Oil is found in metamorphosed shales in the western part of the Los Angeles basin, the porosity of which is caused by the development of cracks in the roof of crystalline shales. Petroleum is extracted from serpentinites in Cuba. Basic igneous rocks contain petroleum at the Ferbro field in Mexico.At the Khukhrinsky gas field, which islocated at the north-western end of the Dnieper-Donets depression, the crystalline basement rocks are oil and gas bearing, from which commercial hydrocarbon inflows have been obtained. In the White Tiger field (Bach Ho), located on the southern shelf of Vietnam, commercial oil accumulations are also found in crystalline basement rocks.
 At the Muradkhanli field in Azerbaijan, the industrial accumulation of petroleum belongs to the igneous rocks of the Upper Cretaceous age. The natural oil and gas reservoir of the Muradkhanli field is confined to the erosion zone of the upper part of the section of these rocks.
 This work aims to determine the reservoir properties of the rocks of the Muradkhanli deposit, which belong to igneous rocks, in different ways.
 The method of estimation of final oil recovery of complex structure reservoirs was proposed for useful capacity and oil recovery of homogeneous media; different variants of the volumetric method were used for reservoirs with complex structures of pore space filling a complex and heterogeneous natural reservoir; values of hydrocarbon reserves of increased and secondary capacity were calculated for the study interval; distributions of oil reserves with right-sided asymmetry, where Mo<Me<X, were presented; it was determined that in effusive cores oil saturation and fluid filtration are caused by tectonic fracturing and cavernousness.
 Permeability varies in a wide range: 0.73·10–15—1.31·10–15 m2; the largest specific fraction of crack density is in the range 0—0.1 cm/cm2, the average value is 0.29 cm/cm2, with crack depth they decrease from 0.9 to 0.1 cm/cm2.
 The studies have shown that the natural reservoir of oil and gas in the Muradhanli field is associated with the erosion zone of the upper part of the igneous rock section.

High-resolution digital outcrop model of the faults, fractures, and stratigraphy of the Agardhfjellet Formation cap rock shales at Konusdalen West, central Spitsbergen

Abstract. Structure-from-motion (SfM) photogrammetry has become an important tool for the digitalisation of outcrops as digital outcrop models (DOMs). DOMs facilitate the mapping of stratigraphy and discontinuous structures like folds, faults, and fractures from the centimetre to kilometre scale. With pristine, treeless exposures, the outcropping strata in Svalbard, Arctic Norway, hold exceptional potential for analogue studies and are ideally suited for the acquisition of high-resolution DOMs. Here, we present the acquisition, processing, and integration of the Konusdalen West digital model data set, comprising both DOM and derived digital terrain model (DTM) data. Drone-based image acquisition took place over 2 weeks in July and August 2020. The Konusdalen West DOM and DTM cover a 0.12 km2 area and span a 170 m elevation difference. The DOM covers the upper two-thirds of the mudstone-dominated Late Jurassic–Early Cretaceous Agardhfjellet Formation. The Agardhfjellet Formation and its time equivalents are regional cap rocks for CO2 sequestration and petroleum accumulations on the Norwegian Continental Shelf. A total of 15 differential GNSS control points were used to georeference and quality assure the digital data assets, 5 of which function as reference checkpoints. SfM processing of 5512 acquired images resulted in high-confidence, centimetre-scale resolution point clouds, textured mesh (DOM), tiled model, orthomosaics, and a DTM. The confidence-filtered dense cloud features an average inter-point distance of 1.57 cm and has an average point density of 3824.9 points per metre. The five checkpoints feature root mean square errors of 2.0 cm in X, 1.3 cm in Y, 5.2 cm in Z, and 5.7 cm in XYZ. Increased confidences and densities are present along the western flank of the Konusdalen West outcrop, where a fault fracture network in mudstone-dominated strata is best exposed and photographed most extensively. Top and side view orthomosaics feature maximum resolutions of 8 mm per pixel, enabling the mapping of faults, formation members, marker beds, fractures, and other sub-centimetre features. Additional structural measurements and observations were taken in June 2021 to place the data in the geological context. Data described in this paper can be accessed at Norstore under https://doi.org/10.11582/2022.00027 (Betlem, 2022b).

Multiple geochronological evidences revealing oil charging and redistribution processes in the Tazhong-4 Oilfield, Tazhong Uplift (Tarim Basin): Implications for quantitative reconstruction of petroleum accumulation history in superimposed basins

Re-migration within a hydrocarbon reservoir is an important yet poorly constraint process in petroleum system analysis. Here we investigated a Paleozoic petroleum reservoir in the Tarim Basin and quantitatively reconstructed the oil re-migration process using fluid inclusions and multiple isotopic dating techniques including the calcite U–Pb dating, the oil Re–Os dating, and the illite K–Ar dating. The Re–Os dating for the Carboniferous oil samples demonstrated an oil generation process during the Middle Caledonian (479 ± 110Ma). Two episodes of oil charging were revealed by each represented oil inclusion fluorescing yellowish and blue color in the Cambrian and Ordovician intervals. Calcite U–Pb ages suggest the Cambrian and Ordovician paleo-reservoirs represented oil inclusion fluorescing yellowish color were charged by mature oils during the late Caledonian orogeny (420-384Ma), and illite K–Ar ages show the oils with similar maturity charged into the Carboniferous reservoir during the late Hercynian orogeny (278.4–246.0Ma). This contradiction in absolute ages reveals an oil re-migration process with oils that originally was generated during the Middle Caledonian and charged in the Cambrian and Ordovician reservoirs and then migrated vertically to the Carboniferous reservoir ∼200 Myrs later possibly due to fault reactivation. The successful application of fluid inclusion analysis and multiple absolute dating techniques in the Tarim Basin provides a paradigm for quantitative reconstruction of petroleum (re-) accumulation history in similar tectonic superimposed basins.

Petroleum Potential and Organic-Matter–Oil Correlation in the Rocks of the Upper Riphean Iremeken Formation in the Kamo Arch of the Baikit Anteclise (Siberian Platform)

Abstract —A complex of laboratory studies of Riphean rocks and oils was carried out by the organic-geochemistry methods to construct a basin model for the Kamo arch of the Baikit anteclise of the Siberian craton. We compared the parameters of the organic matter (OM) and oils of the Upper Riphean Iremeken carbonaceous member by biomarker hydrocarbons. Analysis of the obtained chromatography–mass spectrometry data showed an unordinary group hydrocarbon composition of extracts from the OM and oils and low contents of cheilanthanes and steranes in them. Within the Kamo arch, the Upper Riphean Iremeken OM-enriched deposits with a high petroleum potential might have reached the peak of petroleum generation only in the deepest part of the Madra trough; thus, the traps could not be completely filled with oil. The distribution of tricyclic terpanes in the rock bitumens from the studied wells testifies to immature OM in the Iremeken Formation. However, in the most submerged zones of the Kamo arch and in the adjacent areas, oil was generated from the OM of the Iremeken Formation. This is evidenced by the oils of the Upper Iremeken Subformation in the Kuyumbinskoe field and the Ter’-Kamo license area.

Origin of calcite cements in the Permian Lucaogou Formation tight reservoirs, Jimsar sag, Junggar basin, NW China: Constraints from geochemistry

Understanding the diagenetic evolution of carbonate cementation in hydrocarbon reservoirs is critical to better reconstruct the history of fluid flow during petroleum accumulation. The extensive occurrence of carbonate cements within the lower Permian Lucaogou Formation tight reservoirs is regarded as a major diagenetic factor that causes strong hydrocarbon reservoir heterogeneities. Petrographic and geochemical analyses, including optical microscopy fitted with cathodoluminescence, scanning electron microscopy, carbon and oxygen stable isotopes, in situ rare earth element, as well as fluid inclusion microthermometry, were carried out to decipher the origin of calcite cementation and understand its control on reservoirs quality. Petrography shows that the precipitating cements mostly consist of pore-filling blocky/mosaic calcite, with a dull orange luminescence color. Chondrite-normalized rare earth element (REE) patterns and C–O isotopic compositions of these calcite cements exhibit strongly negative Eu and Tb anomalies, enrichment in light REE, positive carbon (δ13CPDB = 0.58‰–7.45‰) and negative oxygen (δ18OPDB = −11.38‰ to −8.61‰) isotopic values, similar to the dolostone and micritized peloidal grains, suggesting that the calcite-precipitating fluids were derived from dissolution of lacustrine depositional carbonates. The relative timing of calcite precipitation in reservoirs was constrained based on the thermal-burial history of the study region and precipitation temperatures obtained from fluid inclusions. The results show that this cementation episode mainly occurred during the Late Triassic to Early Jurassic, which was synchronous with the tectonic uplift event. Moreover, homogenization temperatures of fluid inclusions and geochemical signatures of the calcite cement are similar to those of the fracture-fillings, suggesting that these two calcite phases may be genetically related and form coevally within one fluid flow system. It can be interpreted as a response to the compressional tectonic deformation given by the collision of the Qiangtang Block with the Eurasia Plate. This tectonic deformation event is regarded as the driver for calcite precipitation during the early burial stage, resulting in a considerable reduction of reservoir quality. Calcite cementation is pervasive and may play a main role in halting hydrocarbon migration through some of the permeable pathways in reservoirs.

A tectono-thermal perspective on the petroleum generation, accumulation and preservation in the southern Ordos Basin, North China

The southern Ordos Basin has excellent petroleum exploration prospects. However, the tectono-thermal history and the controls on petroleum generation, accumulation and preservation conditions in southern basin are unclear. In this study, we analyzed the present geothermal field, paleo-geothermal gradient, maturity of the hydrocarbon source rocks, uplift and cooling process and tectono-thermal evolution history. In the study area, for the Ordovician, Permain and the Triassic strata, the present temperature is low (30−70 °C) in the southeastern area but high (80−140 °C) in the northwestern area. The paleo-geothermal gradient varied from 24 °C/km to 30 °C/km with a heat flow of 58–69 mW/m2 (i.e., a medium-temperature basin). The paleo-temperatures are higher than the present temperatures and the maximum paleo-temperatures controlled the thermal maturity of the source rocks. The vitrinite reflectance (Ro) values of the Triassic strata are >0.7% and the thermal maturity reached the middle-mature oil generation stage. The Ro values of the Permian-Ordovician strata are >1.8% and the thermal maturity reached the over-mature gas generation stage. The southern Ordos Basin has experienced the multiple tectonic events at the Late Ordovician Caledonian (452 Ma), Late Triassic (215 Ma), Late Jurassic (165−160 Ma), End-Early Cretaceous (110−100 Ma) and Cenozoic (since 40 Ma). A large-scale tectono-thermal event occurred at the End-Early Cretaceous (110−100 Ma), which was controlled by lithospheric extension, destruction and thinning. This event led to the highest paleo-temperatures and thermal maturities and coeval with the peak period of petroleum generation and accumulation. The southern Ordos Basin has undergone rapid and large-scale uplift since the Late Cretaceous due to expansion of the northeastern margin of the Tibetan Plateau, uplift of the Qinling orogenic belt and thrust faulting in the Liupanshan tectonic belt. The southern Ordos Basin experienced tectonic overprinting that was strong in the south and weak in the north. The strongest overprinting occurred in the southwestern part of the basin. The large-scale uplift, denudation and faulting led to oil and gas loss from reservoirs. The petroleum generation, accumulation and preservation in the southern Ordos Basin were affected by deep lithospheric structures and the tectono-thermal evolution. This work provides a novel tectono-thermal perspective on the petroleum generation, accumulation and preservation condition of the southern Ordos Basin.

Oil-source correlations and petroleum accumulation in oil sands in the Carboniferous Yanghugou Formation in the Shajingzi area, Ordos Basin, China

The south-central part of the western Ordos Basin is an important structural belt. Recent drilling of Well YT2 in the Shajingzi area of this belt has led to the discovery of oil sands in the Carboniferous Yanghugou Formation. In this study, Paleozoic source rocks and oil sands were sampled from the Well YT2 and analyzed for oil-source correlations. Geochemical data including saturate and aromatic biomarker compositions were used to investigate the genetic origins of oil sands. Saturated hydrocarbon biomarkers, such as n-alkanes, isoprenoids, tricyclic terpanes and C27-C28-C29 regular steranes, indicate that the oil and source rocks in the Ordovician Wulalike Formation are similar in terms of maturity, provenance and sedimentary environment. Aromatic parameters, such as dibenzothiophene/phenanthrene and alkyldibenzothiophene/alkyldibenzofuran ratios in the oil are similar to those in source rocks in the Carboniferous Yanghugou Formation and the Permian Taiyuan Formation. Moreover, retene is direct evidence that the oil has originated in part from the Yanghugou and/or Taiyuan formations. In addition, the modelled accumulation ages indicate that that the maturity of the two types of oil inclusions is consistent with the source rocks of the Wulalike, Yanghugou and Taiyuan formations during the charging times. The thrust faults runs through the Wulalike, Yanghugou and Taiyuan formations can provide pathways for oil migration. Therefore, the oil from the Yanghugou Formation has a mixed source from the Wulalike, Yanghugou and/or Taiyuan formations. This is the first documented discovery of Ordovician marine oil in the Ordos Basin.

Petroleum generation and migration through the Faroe–Shetland Basin – the role of igneous intrusions

Previous basin modelling of the Faroe–Shetland Basin (FSB, offshore UK) has suggested mid-Cretaceous petroleum generation, which predates the deposition of the working Paleogene reservoirs and traps. To justify the time discrepancy between generation, reservoir, and trap formation, factors such as intermediary accumulations and overpressure have been invoked. However, across much of the FSB, the Cretaceous sequences that overly the Kimmeridgian source rock are heavily intruded by Paleogene-aged intrusions. Recent modelling has shown that the emplacement of the intrusions, coupled with lower radiogenic heat production from underlying basement, leads to estimates of petroleum generation occurring up to 40 myr more recently than suggested by previous models. In this work, we seek to better understand the role that igneous intrusions have exerted on petroleum generation and migration in the FSB. Models with varying thicknesses of Paleogene intrusions are compared with those that consider the Cretaceous sequence as purely sedimentary (i.e. similar to assumptions in previous modelling). The estimated times of petroleum generation are compared with geochronological constraints on the ages of oils (i.e. c . 90–68 Ma) along with the deposition and formation of other petroleum system elements. By considering only the effect of igneous intrusions, the expulsion onset from the source rock is retarded by up to 12 myr. In addition, our models show the impact of the intrusions on petroleum saturation and migration, suggesting that intrusions have potentially compartmentalized the basin, trapping petroleum beneath or within the sill complex. Finally, our findings suggest that basin models in regions impacted by significant magmatism need to consider the impact of intrusions to more accurately constrain both petroleum generation and migration. Thematic collection: This article is part of the New learning from exploration and development in the UKCS Atlantic Margin collection available at: https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin

Diagenetic history of calcite fractures in Vaca Muerta shales (Argentina) inferred from paired Δ47 and fluid inclusion geothermometry

Many low-permeability, hydrocarbon-bearing rocks are productive for petroleum because natural fractures enhance hydrocarbon delivery to wellbores. Exploration and development decisions often must be made in the face of uncertainty about the presence and properties of natural fractures at scales of beds, field and plays, and how they contribute to production. Fractures patterns in subsurface rocks are challenging to predict or characterize owing to the difficulty in obtaining representative samples of fractures and the sparse set of tools for reconstructing how and when fractures grow during sedimentary basin evolution. In this study, we investigate bed-parallel fracture diagenesis in the Vaca Muerta shales (Argentina) based on a set of calcite vein collected from core across a thermal maturity sequence that ranges from the oil to dry gas window. We characterize these samples using secondary ions mass spectrometry (SIMS) measurements of stable isotope ratios, carbonate clumped isotope geothermometry and fluid inclusion analysis. These measurements precisely reconstruct the evolution of fluid geochemistry, temperature and pore fluid pressure during fracture opening. Here we show that within each studied site, all bedding parallel fibrous veins calcite formed at similar ranges of temperature. The fracture mineralization temperature increases substantially at the basin scale, from 90 °C to 120 °C, correlated with host-rock thermal maturity. We compare our constraints on carbonate and fluid temperature with apatite fission track thermal models and find that most of the fractures of the Vaca Muerta shales have formed in a relatively early stage of subsidence of the basin (c.a. 90 to 70 Ma). These ages estimations are consistent with recently published U–Pb ages on calcite veins from the outcropping area (117–61 Ma). The presence of petroleum inclusions (oil, condensate, and gas) in most of the vein's calcite fibers from cores also provides clear evidence that fracture formation was contemporaneous or posterior with petroleum generation, constraining the timing of catagenesis in the Vaca Muerta. Reconstructed paleo pressures conditions of veins formation from fluid inclusion analysis highlight significant fluid overpressure in the shale interval, which likely contributed to fracture initiation and growth. Preserved apparent Δ47 temperatures in fibrous veins carbonates mineralization evolves gradually from 130 °C to 175 °C with increasing host rock thermal maturity. These clumped-isotope-based temperatures are systematically higher than trapping temperatures of associated fluid inclusions; one interpretation of this observation is that carbonate clumped isotope compositions re-equilibrated to near maximum burial conditions by solid-state isotopic re-ordering, yielding a record of the maximum burial temperature the shale unit experienced. The combination of paleothermometry techniques used in this study illustrates the importance of simultaneously exploring several independent geothermometers, particularly the informative combination of fluid inclusion and clumped isotope constraints, which provides a means of understanding the complex diagenesis of old sedimentary rocks that have experienced burial temperatures in the oil and gas thermal windows.

Organic richness and source rock potential of the La Peña Formation in the Sabinas and Piedras Negras basins, NE of Mexico

This paper investigates the petroleum generation potential of the Lower Cretaceous organic-rich rocks of the La Peña Formation in the Sabinas and Piedras Negras Basin (SB-PNB) of northeastern Mexico. In order to provide insights into the source rock potential of this unit, a total of 25 cutting samples collected from 15 wells at different stratigraphic intervals along the study area were analysed using Rock-Eval Pyrolysis technique. The analytical results revealed that all the analysed samples can be described as hydrogen-poor organic matter with HI <200 mg HC/g TOC. The organic richness indicates a poor to excellent Total Organic Carbon content suggesting that existed different conditions during the deposition and burial of this unit, causing variable organic matter production and preservation. Also, the results revealed a variation in the kerogen types that may be attributed to the relative stratigraphic positions of the selected samples in the wells.
 With respect to the organic matter thermal maturity, given by the geographical distribution of the Tmax values, the mature and overmature zone (435–508 °C) correspond to the Sabinas basin (SB).
 Overall, these results show a variability in the organic richness, thermal maturity and petroleum potential of the La Peña Formation, differentiating the values of the TOC content, petroleum potential and HI content for the samples from the Sabinas Basin and Piedras Negras Basin, respectively.

The “Golden Zone” temperature distribution of oil and gas occurrence examined using a global empirical database

We present here a straightforward empirical correlation between petroleum occurrence in sedimentary basins and reservoir temperature that can be integrated with other methods of analysis to reduce exploration risk. Global amounts of recoverable oil, gas, and gas-condensate in 1175 well characterized reservoirs from 954 of the world's largest fields, constituting 54% of the world's documented recoverable conventional oil and 50% of gas, are examined in terms of present-day reservoir temperature. Most volumes (74%) occur within the range of 60–120 ± 2 °C (140–248 ±4 °F), corresponding with the isotherm-bounded depth interval in petroliferous basins previously defined as the “Golden Zone” for exploration. Only 6% of the global total occurs at higher temperatures and 20% at lower temperatures. The decrease <58 °C is gradual in most regions, whereas the drop-off of discovered volumes >122 °C is precipitous. The low-temperature limit is suggested to reflect both poor sealing capacity of diagenetically immature shales and biodegragation, but many low-temperature accumulations survive because of uplift from previous maximum burial. The high-temperature limit is interpreted as resulting mainly from diagenetically induced overpressure that causes seal failure and remigration. Similarity between the distributions of both oil and gas with temperature indicates that the controlling processes are unrelated to petroleum generation. The distributions are also similar for sandstone and carbonate reservoirs and for reservoirs with shale, evaporite, and carbonate seals, indicating little lithologic influence. Although the ultimate controls can be debated and are certainly in need of continuing study, the observed temperature dependence of petroleum volumes is entirely empirical and can be used as an independent exploration risk factor. Nevertheless, the proportions of total estimated ultimate recovery above and below the Golden Zone temperature limits vary significantly between major petroleum-producing regions, so local calibration is essential.

Hydrocarbon charging process of Ordovician strike‐slip fault zones in the Shunbei area, Tarim Basin, NW China

Ultra‐deep marine carbonate reservoirs is an important field for oil and gas exploration, and it is also a hot research topic in recent years. However, their hydrocarbon episodic charging model is still under debate up to now. A great breakthrough has been made in the newly discovered ultra‐deep fault‐karst oil reservoir in the Shunbei area of Tarim Basin. Based on quantitative gas chromatogram‐mass spectrometry, stable carbon isotopes of reservoir oils, microthermometry and confocal laser scanning analyses of fluid inclusions, the reservoir oil origin and hydrocarbon charging history in Shunbei No. 1, No. 5 and No. 7 strike‐slip fault zones are expounded. The results showed that the Ordovician reservoir oil derives from the source rocks within the Cambrian Yuertusi Formation deposited in a highly anoxic bottom water environment. There were four stages of hydrocarbon charging in the study area, in the late Caledonian, late Hercynian–Indosinian, middle Yanshanian and late Himalayan. During this period, the force‐field strength of the charged oil gradually decreased, and the early‐stage charged crude oil with low maturity and high force‐field strength preferentially accumulated in the Yijianfang Formation, while the late‐stage charged crude oil with high maturity and low force‐field strength preferentially accumulated in the Yingshan Formation. This study reveals the history and differences of petroleum accumulation in the Shunbei fault zones, which is significance for understanding the hydrocarbon distribution in ultra‐deep marine carbonate reservoirs.

Generation and distribution of overpressure in ultra-deep carbonate reservoirs controlled by intra-cratonic strike-slip faults: The Ordovician of Shuntuoguole area in the Tarim Basin

The strike-slip fault-controlled ultra-deep fractured-vuggy carbonate reservoir is an increasingly important exploration target. However, the high heterogeneity of fault-controlled reservoirs and the ineffective methods available for pressure prediction make it difficult to assess the risk of potential overpressure in ultra-deep carbonate reservoirs. Abnormal overpressure is common in the ultra-deep strike-slip fault-controlled carbonate reservoirs in the Shunbei Oilfield of the Tarim Basin. According to measured pressures, petroleum accumulation history, and fault framework, this study investigates the generation mechanisms of overpressure in fault-controlled carbonates and reconstructs the pressure evolution of reservoirs. Finally, the effect of strike-slip faults on current overpressure distribution is discussed. Measured pore pressure data from 90 wells showed that all reservoirs present in the major fault zones are normally pressured, and the reservoirs present far away from the major faults commonly develop overpressures. The distribution patterns of overpressure in the Middle-Lower Ordovician reservoirs coincide with areas with fault reactivation during the Himalayan Period. The results of the comprehensive analysis of petroleum accumulation history, fault activity, and well production suggested that dry gas generation is a primary cause of overpressure in the Middle-Lower Ordovician reservoirs. The relatively low temperature in the reservoir, in addition to the highly compartmentalized nature of overpressure, indicated that these overpressured gas migrate vertically into the Ordovician formation from deep strata along strike-slip faults. The pressure evolution restored by basin modelling and fluid inclusion showed that distinct differences in overpressure magnitude in the different reservoirs were formed at the stage of gas charging but not at the early stages of oil accumulation. The difference in physical properties of the two types of fault-controlled reservoirs resulted in different pressure distributions and oil-bearing levels in the ultra-deep carbonate reservoirs at present. The strike-slip fault zones are the primary pathways by which overpressured fluids migrate from the deeper Cambrian formation into the Ordovician reservoirs and act as barriers to separate the pressure systems in the ultra-deep carbonate reservoirs. These findings are expected to help mitigate the drilling risks with overpressure in deep strike-slip fault-controlled carbonate reservoirs.

Phase behavior and GOR evolution using a natural maturity series of lacustrine oil-prone shale: Implications from compositional modelling

For the exploration of shale oil, there is still an urgent need to relate hydrocarbon generation reactions and changing phase behavior to exact levels of thermal maturity. Six organic-rich shale samples from the Cretaceous Qingshankou Formation, Songliao Basin spanning the maturity range with vitrinite reflectance (Ro) 0.58%–1.16% were studied for petroleum generation characteristics using the PhaseKinetics, PhaseSnapshot, and GORFit approaches. All samples show very good petroleum potential and contain Type I kerogen with total organic carbon contents ranging between 1.5% and 5%. A full spectrum of light to heavy hydrocarbons, consistent with live oils, occurs in thermal extracts of all samples. Gas chromatography fingerprints of samples with Ro > 0.7% closely resemble waxy oils derived from lacustrine organic matter (OM); fingerprints of lower maturity samples are not yet as wax rich. The inferred petroleum type organofacies of all samples is paraffinic high wax with low organic sulfur levels. Hydrocarbon generation from the least mature sample is characterized by one dominant activation energy at 55 kcal/mol, accounting for 87% of the total bulk reaction. Assuming a simplified geological scenario, i.e., a 3 K/My linear heating rate, primary petroleum is generated (transformation ratio, i.e., TR: 10%–90%) over a narrow temperature interval of only 23 °C. Onset (10% TR), maximum (Tpeak), and completion (90% TR) temperatures and Ro values are 141 °C at Ro 0.85%, 155 °C at Ro 1.08%, and 164 °C at Ro 1.2%, respectively. Primary gas generation (148–172 °C) occurs 10 °C later (300 m deeper) than the generation of C6+ compounds (138–161 °C). Secondary gas formation from oil cracking begins at 182 °C, maximizes at 197 °C, and is completed well before 225 °C (beginning of late gas generation from the secondary cracking of thermally matured, macromolecular organic matter) at 206 °C. Thus, primary and secondary oil cracking processes do not overlap under geological conditions. In line with a paraffinic high-wax oil petroleum type organofacies, cumulative fluids generated from the least mature sample fall within the black oil class over most of the primary kerogen conversion range up to 90% TR as indicated by low saturation pressures (Psat) and gas-oil-ratios generally below 160 Sm3/Sm3. Maturation results in relatively heavy fluids with Psat values in the range 40–70 bar when the free hydrocarbons, i.e., already present prior to pyrolysis, are included, and in lighter fluids with Psat values in the range 70–90 bar, when the free, mostly waxy hydrocarbons, are excluded. Systematics of physical properties and fluid compositions evolution reproduce the general behavior of naturally occurring petroleum sourced from lacustrine OM very well and fit physical properties and compositions of produced shale oils in the Songliao Basin at comparable maturity levels.

Maceral evolution of lacustrine shale and its effects on the development of organic pores during low mature to high mature stage: A case study from the Qingshankou Formation in northern Songliao Basin, northeast China

Organic matter (OM) hosted pores are crucial for the storage and migration of petroleum in shale reservoirs. Thermal maturity and macerals type are important factors controlling the development of pores therein. In this study, six lacustrine shale samples with different thermal maturities from the first member of the Qingshankou Formation in the Songliao Basin, of which vitrinite reflectance (Ro) ranging from 0.58% to 1.43%, were selected for a comparative analysis. Scanning electron microscopy (SEM) and reflected light microscopy were combined to investigate the development of organic pores in different macerals during thermal maturation. The results show that alginite and liptodetrinite are the dominant primary macerals, followed by bituminite. Only a few primary organic pores developed in the alginite at the lowest maturity (Ro = 0.58%). As a result of petroleum generation, oil-prone macerals began to transform to initial-oil solid bitumen at the early oil window (Ro = 0.73%) and shrinkage cracks were observed. Initial-oil solid bitumen cracked to oil, gas and post-oil bitumen by primary cracking (Ro = 0.98%). Moreover, solid bitumen (SB) was found to be the dominant OM when Ro > 0.98%, which indicates that SB is the product of oil-prone macerals transformation. Many secondary bubble pores were observed on SB, which formed by gas release, while devolatilization cracks developed on migrated SB. Additionally, at the late oil window (Ro = 1.16%), migrated SB filled the interparticle pore spaces. With further increase in temperature, the liquid oil underwent secondary cracking into pyrobitumen and gas, and spongy pores developed on the pyrobitumen at higher levels of maturity (Ro = 1.43%), which formed when pyrobitumen cracked into gas. Vitrinite and inertinite are stable without any visible pores over the range of maturities, verifying their low petroleum generation potential. In addition, it was concluded that clay minerals could have a catalytic effect on the petroleum generation, which may explain why organic-clay mixtures had more abundant pores than single OM particles. However, after Ro > 0.98%, authigenic minerals occupied the organic pore spaces on the organic-clay mixtures, resulting in fewer pores compared to those observed in samples at the early to peak oil window.

Methane pore accessibility, densification, and accommodation by organic matter in the Niobrara Formation at wet-gas thermal maturity conditions

Petroleum within unconventional source-rock reservoirs is hosted in organic matter and mineral pore space as well as in voids and microfractures. Recent work has shown that for source-rock reservoirs in the dry gas window, significant portions of methane (CH4), the main component of petroleum at elevated maturities, can be stored within fine (<5 nm) organic matter porosity. However, within reservoirs at lower thermal maturities (e.g., peak oil or wet-gas conditions), the distribution and behavior of CH4 and the higher alkanes that comprise gas condensates across pore sizes is unclear, especially for pores with diameters <50 nm. Understanding CH4 distribution within these settings provides insight for petroleum generation, movement, and recoverability, enabling increased accuracy of estimated ultimate recovery. Here wide Q-range total neutron scattering was used to evaluate perdeuterated methane (CD4) behavior at reservoir pressures (200–750 bar) and temperature (60 °C) in a sample at the late oil/wet gas thermal maturity stage from the Late Cretaceous Niobrara Formation, an active petroleum producing formation within the Denver-Julesburg Basin, U.S.Neutron scattering data show that mesopores within the Niobrara Formation sample exhibit mass fractal scattering, similar to previously measured U.S. marine shale samples. In the presence of CD4, scattering intensities between Q = 0.02–0.1 Å−1 (corresponding to nominal pore diameters from 25 to 5 nm, respectively) decrease with increased pressure up to 750 bar where at least 80% of all pores with ∼25 nm diameters are CD4 accessible. In contrast, between Q = 0.1–1 Å−1 (corresponding to nominal pore diameters from 5 to 0.5 nm, respectively), scattering intensity initially increased at the lowest CD4 pressure tested (200 bar) before decreasing with increasing pressure. These signal fluctuations with CD4 pressure are interpreted to arise from the creation of pores with diameters <5 nm, likely through deformation of solid bitumen by supercritical CD4, and/or the incorporation of CD4 within sample organic matter. This new porosity represents an increase of at least 8% in available pore volume within the sample, although the majority of these pores do not persist following removal of CD4. Additionally, there is strong evidence for densification of CD4 within the sample indicated by a shift in the CD4 intermolecular scattering peak to higher Q-values compared to bulk CD4. These results provide insight into fluid properties within source-rock reservoirs at late oil/wet gas thermal maturities, especially as they relate to organic porosity interconnectivity, and are discussed with perspective toward pressure management of gas condensate wells.