Formation Of Hydrocarbon Reservoirs Research Articles

The Volcanic Rocks and Hydrocarbon Accumulation in the Offshore Indus Basin, Pakistan

To analyze the impact of volcanic rocks in the Offshore Indus Basin on hydrocarbon reservoir formation, seismic data interpretation, seismic data inversion, and sea–land correlation analysis were carried out. The results show that, longitudinally, volcanic rocks are mainly distributed at the top of the Cretaceous system or at the bottom of the Paleocene, and carbonate rock platforms or reefs of the Paleocene–Eocene are usually developed on them. On the plane, volcanic rocks are mainly distributed on the Saurashtra High in the southeastern part of the basin. In terms of thickness, the volcanic rocks revealed by drilling in Karachi nearshore are about 70 m thick. We conducted sparse spike inversion for acoustic impedance in the volcanic rock area. The results show that the thickness of the Deccan volcanic rocks in the study area is between 250 and 750 m which is thinning from southeast to northwest. Based on sea–land comparison and comprehensive research, the distribution of volcanic rocks in the Indian Fan Offshore Basin played a constructive role in the Mesozoic oil and gas accumulation in the Indus offshore. Therefore, in the Indian Fan Offshore Basin, attention should be paid to finding Mesozoic self-generated and self-stored hydrocarbon reservoirs and Cenozoic lower-generated and upper-stored hydrocarbon reservoirs.

Turbidite Dynamics and Hydrocarbon Reservoir Formation in the Tano Basin: A Coastal West African Perspective

Turbidite Dynamics and Hydrocarbon Reservoir Formation in the Tano Basin: A Coastal West African Perspective

The Effects of Different Water Types on the Dissolution, Physical Appearance, and Compressive Strength of Gypsum Rock

Dissolution of gypsum rock in water is significant, which may result in hydrocarbon reservoir formation and evaporate deposits. However, the complexity of the gypsum dissolution process is still of interest because of its uncleanness that requires more critical analysis. The objectives of this experimental study are emphasis on the dissolution characteristics of gypsum rock under room temperature and by various types of water; namely: deionized, tap, fresh, acidic, well, and normal rainwatre. In addition, the influences of dissolution on gypsum rock's mechanical and physical characteristics. Gypsum rock was obtained from Agjalar area, in the southwest of Sulaymaniyah city, Northern Iraq. Experimental results show that well water is the most effective type to dissolve gypsum and cause significant reductions in the mechanical characteristics of gypsum rock.

Organoclastic sulfate reduction in deep-buried sediments: Evidence from authigenic carbonates of the Gulf of Mexico

The fate of organic matter in deep-buried marine sediments determines the formation of hydrocarbon reservoirs, shapes the deep biosphere, and affects the global carbon cycle. Several geochemical processes such as silicate weathering, iron and manganese (hydr)oxide reduction, and sulfate reduction influence the remineralization of organic matter in buried sediments. However, little information on deep-seated organoclastic sulfate reduction is available and the involved geochemical processes are largely unknown. Here, authigenic carbonates recovered from Ship Shoal Block 296 (SS296) of the Gulf of Mexico, all dominated by low-magnesium calcite, were investigated to constrain organoclastic sulfate reduction in deep-buried sediments. The SS296 carbonates had been previously suggested to be of a deep origin and transported upward by salt diapirism. The presence of cone-in-cone textures in samples 3110R1 and 3110R2 as well as vitrinite reflectance values of 0.48% to 0.58% indicate carbonate formation at a relatively deep burial. Likewise, clumped isotope thermometry yielded formation temperatures from 45 °C to 53 °C for sample 3110R1, 60 °C for sample 3110R2, and 11 °C to 37 °C for sample 3110R3. In spite of formation at greater depth, the temperatures of samples 3110R1 and 3110R2 are still within the temperature range of microbial sulfate reduction, reflecting formation depths between 1 km and 2.7 km. The presence of framboidal pyrite and its relatively low δ34S values (−27.8‰ to +11.5‰) agree with the occurrence of microbial sulfate reduction during carbonate precipitation. The carbon isotopic composition of the carbonates (δ13C: −16.6‰ to −8.9‰) and enclosed organic matter (δ13Corg: −26.8‰ to −20.5‰) suggests that organic matter is the dominant carbon source of carbonate minerals. This study confirms that microbial sulfate reduction occurs in deep-buried sediments, driving the degradation of organic matter. Our findings suggest that organoclastic sulfate reduction might be common in deep-seated sedimentary environments, controlling the fate of organic matter in deep subsurface environments and affecting the global carbon cycle.

Basin modelling and source rock characteristics of the Late Palaeoproterozoic Cuizhuang Formation in the Yuncheng sub‐basin, North China: Implications for hydrocarbon generation and expulsion history

The present investigation is the first to provide information on the formation, process and influence factors for hydrocarbon generation and expulsion potential of the Cuizhuang Formation source rock in the Yuncheng sub‐basin to decipher the reason why no commercial petroleum resources have been found so far. In this study, data from the Jitan‐1 well in the Yuncheng sub‐basin were applied for the Cuizhuang Formation source rock basin modelling and organic geochemical analyses to reconstruct the burial and thermal evolution history and reveal the timing and process of hydrocarbon generation and expulsion. The modelling results indicate that the peak palaeotemperature of the Cuizhuang Formation source rock reached ~205°C in the Middle Carboniferous (~327 Ma) at a maximum burial depth of ~4000 m, when rapid burial subsidence and thermal events played a significant role in increasing thermal maturity. The Cuizhuang Formation generated and expelled small amounts of hydrocarbons from the Early Ordovician until the Middle Carboniferous, starting with the primary kerogen cracking and conversion to oil from the Early to Middle Ordovician (~476–461 Ma), corresponding to the thermal maturity values of 0.55–0.70 %VRo and transformation ratio (TR) <10%. The expulsion of most generated oil (0.70–1.30 %VRo, TR of 10%–90%) started from the Middle Ordovician to the Early Carboniferous (~461–351 Ma), before reaching the secondary cracking of the retained oil into gas (>1.30 %VRo and TR of 90%–100%) from the Early to Middle Carboniferous (~351–327 Ma). Destruction of the initial formation of hydrocarbon reservoirs in the Yuncheng sub‐basin was primarily controlled by the Middle Carboniferous tectonic event with its major uplift‐erosion, resulting in the absence of potential hydrocarbon reservoirs in recent exploration activities in some parts of the Yuncheng sub‐basin.

Dolomitization evolution and its effects on hydrocarbon reservoir formation from penecontemporaneous to deep burial environment

Aiming at the scientific problem that only part of dolomite acts as dolomite reservoir, this paper takes the multiple dolomite-bearing formations in the Tarim and Ordos basins, NW China and Sichuan Basin, SW China as the study object, by means of mineral petrological analysis and geochemical methods including carbonate clumped isotope, U-Pb isotopic dating, etc., to rebuild the dolomitization pathway and evaluate its effects on reservoir formation. On the basis of detailed rock thin section observation, five dolomitic structural components are identified, including original fabric-retained dolomite (microbial and/or micrite structure), buried metasomatic dolomite I (subhedral–euhedral fine, medium and coarse crystalline structure), buried metasomatic dolomite II (allotriomorphic–subhedral fine, medium and coarse crystalline structure), buried precipitation dolomite and coarse crystalline saddle dolomite. Among them, the first three exist in the form of rocks, the latter two occur as dolomite minerals filling in pores and fractures. The corresponding petrological and geochemical identification templates for them are established. Based on the identification of the five dolomitic structural components, six dolomitization pathways for three types of reservoirs (preserved dolomite, reworked dolomite and limestone buried dolomitization) are distinguished. The initial porosity of the original rock before dolomitization and the dolomitization pathway are the main factors controlling the development of dolomite reservoirs. The preserved dolomite and reworked dolomite types have the most favorable dolomitization pathway for reservoir formation, and are large scale and controlled by sedimentary facies in development and distribution, making them the first choices for oil and gas exploration in deep carbonate formations.

ГЕОДИНАМІКА

The purpose of the research is to analyze the impact of the region's geodynamics on the formation of hydrocarbon reservoirs in the carbonate Lower Visean-Tournaisian stratum. The paper is focused on the substantiation of hydrocarbon traps within the Machukhy-Tyshchenky area of the southern zone of the Dnieper-Donets basin, as well as oil and gas exploratory drilling and new effective methods of stimulating gas inflows to boreholes. Methodology. The study applies the stratigraphic, lithological, tectonic, paleotectonic methods of studying geology and oil potential, as well as the method of geological analogies. Results. Gas-bearing carbonate rocks of the Early Visean-Tournaisian age in the Machuhy-Tyshchenky area have been studied. A comparison with other oil and gas regions has shown that they are the domes of carbonate platforms (Wаulsoгtiаn facies). Three echelons of bioherm limestones have been identified within the the area. The research helped to describe the stages of their formation and determine the dependence of reservoir properties of limestones on their biofacial types. The role of tectonic fracture in the formation of reservoir rocks is shown. As a rule, tectonic fractures are cemented by calcite under the action of formation waters. An assumption is made about the formation of microfractures in dense limestones due to the action of plumectonic. It consists in the intrusion of high-energy fluids from the depths of the earth, the natural fluid fracturing of rocks and the formation of non-anticlinal hydrocarbon accumulations in them. Probable places of fluid breakthrough may be zones of deep faults: the Ingulets-Kryvorizhzhya-Krupetsk fault zone crosses Machuhy-Tyshchenky area. Filling microfractures with hydrocarbons prevents their cementation. The paper gives examples of microfracturing in the cores of boreholes and establishes reduced core from microfracture intervals. To identify microfracturing intervals in carbonate rocks, it is proposed to use information on the reduction of core, as well as the speed drilling of rocks. The study suggests using multistage hydrofracturing and acid hydrofracturing in order to stabilize and increase gas influxes from carbonate reservoirs to the boreholes. Such technology should provide the connection between the borehole and oil-saturated reservoirs. Probable factors of negative impact on the environment during hydrofracturing have been identified. Originality. Adiabatic microfracturing of dense lithotypes of rocks is possible at considerable depths, in addition to tectonic fracturing. It is due to natural fluid fracturing of sedimentary strata by hydrocarbon gases. This gives hope for the discovery of new types of hydrocarbon deposits that are not associated with anticline traps. Practical significance. Geophysical surveys and the location of six boreholes are recommended in order to search for hydrocarbon deposits in the Machuhy-Tyshchenky area. The study suggests effective methods for increasing gas influxes to boreholes from low-permeability carbonate rocks.

ГЕНЕЗИС УГЛЕВОДОРОДОВ ЮРСКОГО И ДОЮРСКОГО КОМПЛЕКСОВ ЧИСТИННОГО МЕСТОРОЖДЕНИЯ (ЗОНА КОЛТОГОРСКО-УРЕНГОЙСКОГО ПАЛЕОРИФТА)

Определяется генезис углеводородов в юрском и доюрском комплексах Чистинной группы месторождений, расположенных в пределах развития Колтогорско-Уренгойского палеорифта. Исследование актуально для обоснования стратегии поисков нефтегазовых залежей с учетом тектоники фундамента Западно-Сибирской плиты. Цель: установление «главного источника» углеводородов залежей юрского и доюрского горизонтов на рифтогенных участках фундамента. Объекты и методы исследования. Исследован керновый материал юрского и доюрского комплексов продуктивных и непродуктивной скважин Чистинной группы месторождений Вартовского нефтегазоносного района. Литолого-петрографическая характеристика выполнена на основе оптической микроскопии. Методами органической геохимии, хромато-масс-спектрометрии определено содержание в породе подвижных углеводородов, включая ряды н-алканов, н-алкилбензолов, компонентов рядов нафталина и фенантрена. Результаты и выводы. Построена геохимическая модель меж- и внутрипластовой миграции углеводородов. Состав углеводородов верхней части юрского разреза указывает, что залежи нефти в васюганской свите (пласт Ю11) формировались в результате эмиграции углеводородов из аргиллитов баженовской и георгиевской свит. Органическое вещество пород фундамента и низов юрского разреза отличается от вышележащих отложений по молекулярному и групповому составу углеводородов и, вероятно, не участвовало в заполнении верхнеюрских ловушек. Триасовые вулканиты неблагоприятны для образования резервуаров УВ, пустоты залечены вторичными минералами из-за развитых гидротермальных процессов и отсутствия значимой дизъюнктивной тектоники, прогноз заполнения ловушек коры выветривания из вышележащего «юрского источника» маловероятен. В доюрском основании из органического вещества палеозойского генезиса могут сформироваться мелкие залежи. В рассматриваемой зоне континентального палеорифта реализуется классический депрессионный режим нефтегазообразования.

Основные механизмы формирования залежей углеводородов в эрозионных выступах фундамента

Основные механизмы формирования залежей углеводородов в эрозионных выступах фундамента

An experimental study simulating the dissolution of gypsum rock

The dissolution of gypsum rock is of significance to study because it affects the formation of hydrocarbon reservoirs, cap rocks and evaporite deposits. However, the characteristics and mechanism of the dissolution process remain unclear. Here, we present data from experiments performed to address this issue. The experiments simulate various geological conditions, including different diagenetic stages of burial under different fluid types. The diagenetic stages include: 30°C and 0.3 MPa for the epidiagenetic stage; 60°C and 13 MPa for the early diagenetic stage; 100°C and 27 MPa for the middle diagenetic stage; and 150°C and 43 MPa for the late diagenetic stage. The different fluid types include pure water representing continental water, seawater, 0.3 wt.% CO2 solution representing meteoric water, and a 0.2 wt.% acetic acid solution representing organic fluid. We also carried out the experiments on limestones and dolomites, because these rocks also occur in saline water sedimentary systems with gypsum rocks. Experimental results show that lithology, fluid type and temperature–pressure conditions can all affect dissolution. In terms of lithology, gypsum rocks dissolve more easily than limestones and dolomites. Fluid type has little effect on the dissolution of gypsum rock, and gypsum is soluble in all four types of fluids. In contrast, limestones and dolomites are almost insoluble in pure water and seawater, but show clear dissolution in CO2 and acetic acid solutions. The data indicate that gypsum rock has a dissolution peak close to the early diagenetic stage. In contrast, limestones and dolomites have dissolution peaks in the CO2 solution at the early–middle diagenetic stage, and do not show a peak in the acetic acid solution under surficial temperature–pressure conditions. The dissolution rates of limestone and dolomite show different trends with increasing temperature and pressure: limestone dissolution rates decline whereas dolomite dissolution rates increase. Therefore, we infer that the physicochemical properties of a rock are important drivers of dissolution.

Identify a Good New Potential Zones for Hydrocarbon Reservoir Formation, Using Seismic Data Interpretation, Attributes and 3d Modeling in Komombo Basin, Southern Western Desert, Upper Egypt

Identify a Good New Potential Zones for Hydrocarbon Reservoir Formation, Using Seismic Data Interpretation, Attributes and 3d Modeling in Komombo Basin, Southern Western Desert, Upper Egypt

Mineral dating of mantle−derived CO2 charging and its application in the southern Songliao Basin, China

The timing of mantle−derived CO2 charging in sedimentary basins is the basis for studying CO2-sandstone interactions and CO2-oil interactions. In general, the time of the volcanic eruption near the CO2 gas reservoir is considered to be the time of mantle-derived CO2 charging. However, this approach is not suitable for hydrocarbon-bearing basins that have experienced multiple volcanic events. In this paper, using dawsonite-bearing sandstones contained in an oil-bearing CO2 gas and oil reservoir in the southern Songliao Basin as the object of the study on the basis of paragenetic sequence and fluid inclusions, we establish a mineral dating method for determining the time of mantle-derived CO2 charging. In this method, the mineral used for dating is dawsonite, which is formed under a high CO2 partial pressure and records the migration and aggregation of mantle-derived CO2 in geologic history. By interpreting the dawsonite-bearing sandstone in the southern Songliao Basin, we find two hydrocarbon charges and one CO2 charge and that the mantle-derived CO2 charging occurred slightly later than or quasi-simultaneously with the second hydrocarbon filling. Combining the currently known time of hydrocarbon reservoir formation and the time of tectonic fracture development, we deduce that the mantle-derived CO2 formed the dawsonite in the southern Songliao Basin at the end of the Cretaceous (end of the Mingshui period) and the beginning of the Paleogene.

Factors Controlling Hydrocarbon Reservoir Formation and Distribution and Prediction of Favourable Areas in the Jurassic Toutunhe Formation in the Fudong Slope, Junggar Basin, China

In recent years, many oil and gas reservoirs have been discovered in the Jurassic Toutunhe Formation in the Fudong slope, Junggar Basin. The total reserve in the formation is nearly 100 million tonnes, indicating huge exploration potential in the area. However, the main factors controlling the hydrocarbon accumulation remain unclear, and the mechanisms of hydrocarbon accumulation and enrichment are controversial. In this work, by studying the mechanism and main factors controlling hydrocarbon accumulation in the Toutunhe Formation in the Fudong area, a quantitative model of the reservoir rock and caprocks that control hydrocarbon distribution was constructed, the critical conditions for hydrocarbon accumulation were determined and favourable exploration areas were predicted. The results indicated that the oil in the Toutunhe Formation was derived from both Permian and Jurassic source rocks, the oil migrated from west to east after generation and both reservoir rock and caprock controlled the formation and distribution of oil reservoirs. The oil-bearing capacity improved with increases in the storage coefficient and caprock thickness. Accumulation did not occur when the reservoir rock and caprock index ( RCI) was ≤ 0.5 but was favoured when the values were higher; this factor was the critical condition for hydrocarbon accumulation.

Petroleum geology features and research developments of hydrocarbon accumulation in deep petroliferous basins

As petroleum exploration advances and as most of the oil–gas reservoirs in shallow layers have been explored, petroleum exploration starts to move toward deep basins, which has become an inevitable choice. In this paper, the petroleum geology features and research progress on oil–gas reservoirs in deep petroliferous basins across the world are characterized by using the latest results of worldwide deep petroleum exploration. Research has demonstrated that the deep petroleum shows ten major geological features. (1) While oil–gas reservoirs have been discovered in many different types of deep petroliferous basins, most have been discovered in low heat flux deep basins. (2) Many types of petroliferous traps are developed in deep basins, and tight oil–gas reservoirs in deep basin traps are arousing increasing attention. (3) Deep petroleum normally has more natural gas than liquid oil, and the natural gas ratio increases with the burial depth. (4) The residual organic matter in deep source rocks reduces but the hydrocarbon expulsion rate and efficiency increase with the burial depth. (5) There are many types of rocks in deep hydrocarbon reservoirs, and most are clastic rocks and carbonates. (6) The age of deep hydrocarbon reservoirs is widely different, but those recently discovered are predominantly Paleogene and Upper Paleozoic. (7) The porosity and permeability of deep hydrocarbon reservoirs differ widely, but they vary in a regular way with lithology and burial depth. (8) The temperatures of deep oil–gas reservoirs are widely different, but they typically vary with the burial depth and basin geothermal gradient. (9) The pressures of deep oil–gas reservoirs differ significantly, but they typically vary with burial depth, genesis, and evolution period. (10) Deep oil–gas reservoirs may exist with or without a cap, and those without a cap are typically of unconventional genesis. Over the past decade, six major steps have been made in the understanding of deep hydrocarbon reservoir formation. (1) Deep petroleum in petroliferous basins has multiple sources and many different genetic mechanisms. (2) There are high-porosity, high-permeability reservoirs in deep basins, the formation of which is associated with tectonic events and subsurface fluid movement. (3) Capillary pressure differences inside and outside the target reservoir are the principal driving force of hydrocarbon enrichment in deep basins. (4) There are three dynamic boundaries for deep oil–gas reservoirs; a buoyancy-controlled threshold, hydrocarbon accumulation limits, and the upper limit of hydrocarbon generation. (5) The formation and distribution of deep hydrocarbon reservoirs are controlled by free, limited, and bound fluid dynamic fields. And (6) tight conventional, tight deep, tight superimposed, and related reconstructed hydrocarbon reservoirs formed in deep-limited fluid dynamic fields have great resource potential and vast scope for exploration. Compared with middle–shallow strata, the petroleum geology and accumulation in deep basins are more complex, which overlap the feature of basin evolution in different stages. We recommend that further study should pay more attention to four aspects: (1) identification of deep petroleum sources and evaluation of their relative contributions; (2) preservation conditions and genetic mechanisms of deep high-quality reservoirs with high permeability and high porosity; (3) facies feature and transformation of deep petroleum and their potential distribution; and (4) economic feasibility evaluation of deep tight petroleum exploration and development.

Relationship between Tanlu Fault and hydrocarbon accumulation in Liaozhong Sag, Bohai Bay, eastern China

Tanlu fault (Liaozhong segment) goes straight through Liaodong Bay along NNE direction and it is divided into three segments, i.e., the northern segment, the middle segment and the southern segment, according to the differences in structural features. There are obvious changes in deposit thickness, sag structure, tectonic nature and other aspects of the layers. Tanlu fault is a special controlling factor concerning the reservoir formation in Liaozhong sag. First, its activities affect paleogeomorphology and paleogeographic framework and control the distribution of the sedimentary facies and then they proceed to control the distribution of the source rock and reservoir sand bodies. Second, its activities affect the formation and deformation of the structure, control the formation of abundant traps and cause the destruction of some traps. Third, its activities also affect the juxtaposition relation among the fault, the sand bodies and unconformity surfaces and control the function and efficacy of the three as the main hydrocarbon translocation system. In this paper the hydrocarbon reservoir formation process of JZ21-1, JX1-1 and LD27-2 oil and gas fields, the representatives of Tanlu strike slip fault zone are mainly analyzed. The modes of hydrocarbon reservoir formation can be generalized as follows—hydrocarbon source acts as “soil” and oil and gas as “nutrient”; hydrocarbon expulsion relies on “roots”; hydrocarbon migration relies on “trunks”; reservoir forms in “brunches” and the whole process follows the pattern that “hydrocarbon accumulates in strike slips and oil and gas reservoir forms like the growth of trees”.

Sequence stratigraphy and architectural variability in Late Eocene lacustrine strata of the Dongying Depression, Bohai Bay Basin, Eastern China

Stratigraphic sequences and architectural variability in the Late Eocene lacustrine strata of the Dongying Depression, eastern China, were investigated using the interpretation of 2-D and 3-D high-resolution seismic profiles, analysis of spontaneous potential and resistivity curves, and observation of drill cores. Four third-order sequences controlled by syndepositional faults or fault slope break zones were identified, based on the characteristics of sequence boundaries and sedimentary successions. The architecture of the sequences in the different structural belts of the depression is complicated by the relationship between the rate at which fault-controlled accommodation was created and the rate of sediment supply. At fault margins, the rate of sediment supply exceeded accommodation space. Here, lowstand systems tracts consist of lowstand fan deltas with small progradational to retrogradation stacking patterns controlled by steeply dipping, parallel and cross-shaped syndepositional faults or fault slope-break zones; transgressive systems tracts consist of fan deltas with retrogradational to aggradational stacking patterns; and highstand systems tracts consist of fan deltas with normal regressive or progradational stacking pattern. At hinged margins, the rate of sediment supply was equal to or exceeded accommodation controlled by faults. Lowstand systems tracts at hinged margins consist of incised channel fills deposited on the landward side of gently dipping parallel and broom-shaped syndepositional faults or fault slope break zones and lowstand fans or sublacustrine fans deposited on the shores of lakes. Transgressive systems tracts consist of delta systems and shore to shallow-lake subfacies with retrogradational stacking patterns. Highstand systems tracts consist of braided deltas and fluvial delta systems with progradational or normal regressive and aggradational stacking patterns. Along the axis, the rate of sediment supply far exceeded accommodation. Only the lowstand systems tracts developed, consisting of lowstand deltas deposited on the landward side of the syndepositional faults or fault slope break zones, and lowstand fans or sublacustrine fans deposited on the lakeward side of the zones. Here, transgressive systems tracts consist of thin, deep lacustrine deposits and fluvial delta systems with retrogradational or transgressive stacking patterns; and highstand systems tracts consist of thick fluvial delta systems with a progradational configuration or normal regressive stacking patterns.The four kinds of syndepositional fault slope-break zones controlled the stratal architecture of sequences and the distribution of lowstand systems tracts. Sand bodies within lowstand systems tracts provide suitable conditions for the formation of hydrocarbon reservoirs when they are overlain by sediments from transgressive systems tracts, and are therefore favorable sites for lithostratigraphic trap exploration.

Dynamic Field Division of Hydrocarbon Migration, Accumulation and Hydrocarbon Enrichment Rules in Sedimentary Basins

Abstract:Hydrocarbon distribution rules in the deep and shallow parts of sedimentary basins are considerably different, particularly in the following four aspects. First, the critical porosity for hydrocarbon migration is much lower in the deep parts of basins: at a depth of 7000 m, hydrocarbons can accumulate only in rocks with porosity less than 5%. However, in the shallow parts of basins (i.e., depths of around 1000 m), hydrocarbon can accumulate in rocks only when porosity is over 20%. Second, hydrocarbon reservoirs tend to exhibit negative pressures after hydrocarbon accumulation at depth, with a pressure coefficient less than 0.7. However, hydrocarbon reservoirs at shallow depths tend to exhibit high pressure after hydrocarbon accumulation. Third, deep reservoirs tend to exhibit characteristics of oil (–gas)–water inversion, indicating that the oil (gas) accumulated under the water. However, the oil (gas) tends to accumulate over water in shallow reservoirs. Fourth, continuous unconventional tight hydrocarbon reservoirs are distributed widely in deep reservoirs, where the buoyancy force is not the primary dynamic force and the caprock is not involved during the process of hydrocarbon accumulation. Conversely, the majority of hydrocarbons in shallow regions accumulate in traps with complex structures. The results of this study indicate that two dynamic boundary conditions are primarily responsible for the above phenomena: a lower limit to the buoyancy force and the lower limit of hydrocarbon accumulation overall, corresponding to about 10%–12% porosity and irreducible water saturation of 100%, respectively. These two dynamic boundary conditions were used to divide sedimentary basins into three different dynamic fields of hydrocarbon accumulation: the free fluid dynamic field, limit fluid dynamic field, and restrain fluid dynamic field. The free fluid dynamic field is located between the surface and the lower limit of the buoyancy force, such that hydrocarbons in this field migrate and accumulate under the influence of, for example, the buoyancy force, pressure, hydrodynamic force, and capillary force. The hydrocarbon reservoirs formed are characterized as “four high,” indicating that they accumulate in high structures, are sealed in high locations, migrate into areas of high porosity, and are stored in reservoirs at high pressure. The basic features of distribution and accumulation in this case include hydrocarbon migration as a result of the buoyancy force and formation of a reservoir by a caprock. The limit fluid dynamic field is located between the lower limit of the buoyancy force and the lower limit of hydrocarbon accumulation overall; the hydrocarbon migrates and accumulates as a result of, for example, the molecular expansion force and the capillary force. The hydrocarbon reservoirs formed are characterized as “four low,” indicating that hydrocarbons accumulate in low structures, migrate into areas of low porosity, and accumulate in reservoirs with low pressure, and that oil(–gas)–water inversion occurs at low locations. Continuous hydrocarbon accumulation over a large area is a basic feature of this field. The restrain fluid dynamic field is located under the bottom of hydrocarbon accumulation, such that the entire pore space is filled with water. Hydrocarbons migrate as a result of the molecular diffusion force only. This field lacks many of the basic conditions required for formation of hydrocarbon reservoirs: there is no effective porosity, movable fluid, or hydrocarbon accumulation, and potential for hydrocarbon exploration is low. Many conventional hydrocarbon resources have been discovered and exploited in the free fluid dynamic field of shallow reservoirs, where exploration potential was previously considered to be low. Continuous unconventional tight hydrocarbon resources have been discovered in the limit fluid dynamic field of deep reservoirs; the exploration potential of this setting is thought to be tremendous, indicating that future exploration should be focused primarily in this direction.

Thickness maps of Neogene and Quaternary sediments in the Kloštar Field (Sava Depression, Croatia)

The Kloštar Oil Field is situated at the north-western part of Sava Depression in the Croatian part of the Pannonian Basin. It is a typical geological structure that evolved through the Neogene and Quaternary and that is why the structural evolution is reconstructed using palinspastic mapping (i.e., using selected chronostratigraphic horizons as datum planes). The total map set includes six structural and 15 palaeostructural maps interpolated over five E-log markers and one border. The mapping has been performed using the Ordinary Kriging. The maps were used for the interpretation of geological evolution during the Neogene and Quaternary, and particularly a description of hydrocarbon reservoir formation and migration pathways. The structural development can be explained through two phases of transtension and two of transpression that existed regionally in the Sava Depression. However, the maps and cross-sections that are described locally show changes of dominant tectonic styles, particularly during the Quaternary when most of the field was a depositional centre.

Determination of crustal fluid residence times using nucleogenic [formula omitted

Argon-39 is a radioactive isotope of Ar with a half-life of 269years. There are two natural sources of 39Ar on Earth; cosmogenic production in the upper atmosphere and nucleogenic production in rocks. Cosmogenic 39Ar has been recognized as an ideal tracer for groundwater residence times and oceanic circulation. Nucleogenic 39Ar has generally been considered problematic for groundwater studies. In this work, we developed simple models for the evolution of 39Ar/40Ar∗ ratios (where 40Ar∗ denotes radiogenic 40Ar produced in the model system) in rocks and fluids. In rocks, both 39Ar and 40Ar∗ are produced, and a fraction of the 39Ar and 40Ar∗ is released into the mobile fluid phase. In both reservoirs, 39Ar reaches production- or supply-decay equilibrium, whereas 40Ar∗ accumulates with time. Thereby, the 39Ar/40Ar∗ ratio in rocks and fluids generally decreases with time. Our models suggest that the co-evolution of these two isotopes in rocks and fluids provides a new chronometer of fluid migration and reaction in the crust. This chronometer is relevant to a much wider time range than that limited by radioactive decay of cosmogenic 39Ar (i.e., ∼1400years at the current detection limit of 3% modern atmospheric value). The 39Ar/40Ar∗ chronometer is applicable to estimating residence times of very old groundwater as well as for studying fluid–rock interactions and fluid migration rates, such as those occurring during CO2 sequestration and the formation of hydrocarbon reservoirs.

Alteration and Reformation of Hydrocarbon Reservoirs and Prediction of Remaining Potential Resources in Superimposed Basins

Abstract:Complex hydrocarbon reservoirs developed widely in the superimposed basins of China formed from multiple structural alterations, reformation and destruction of hydrocarbon reservoirs formed at early stages. They are characterized currently by trap adjustment, component variation, phase conversion, and scale reformation. This is significant for guiding current hydrocarbon exploration by revealing evolution mechanisms after hydrocarbon reservoir formation and for predicting remaining potential resources. Based on the analysis of a number of complex hydrocarbon reservoirs, there are four geologic features controlling the degree of destruction of hydrocarbon reservoirs formed at early stages: tectonic event intensity, frequency, time and caprock sealing for oil and gas during tectonic evolution. Research shows that the larger the tectonic event intensity, the more frequent the tectonic event, the later the last tectonic event, the weaker the caprock sealing for oil and gas, and the greater the volume of destroyed hydrocarbons in the early stages. Based on research on the main controlling factors of hydrocarbon reservoir destruction mechanisms, a geological model of tectonic superimposition and a mathematical model evaluating potential remaining complex hydrocarbon reservoirs have been established. The predication method and technical procedures were applied in the Tazhong area of Tarim Basin, where four stages of hydrocarbon accumulation and three stages of hydrocarbon alteration occurred. Geohistorical hydrocarbon accumulation reached 3.184 billion tons, of which 1.271 billion tons were destroyed. The total volume of remaining resources available for exploration is ∼1.9 billion tons.