New insights into the carbonate karstic fault system and reservoir formation in the Southern Tahe area of the Tarim Basin

As worldwide hydrocarbon exploration has extended from shallowly to deeply buried strata, reservoir quality has attracted substantial and persistent interest in petroleum geology. In particular, deeply buried strata (>5500 m) in the Tarim Basin have attracted considerable attention because carbonate reservoirs that have experienced fracture or dissolution have also been shown to demonstrate considerable hydrocarbon potential. Therefore, it is necessary to determine how these reservoirs are developed and distributed in detail from both scientific and practical standpoints.In this paper, we address this issue using a case study in the southern Tahe area, which is contained within the largest Palaeozoic marine oilfield in China. In the northern Tahe area, mega-paleokarst systems developed in the Ordovician strata; however, the reservoir quality in the southern part of the Tahe area is relatively poor because it is covered by insoluble formations during karstification. Observations of cores and analyses of images of well logging demonstrate that these reservoirs are dominated by caves, vugs and fractures that have developed near faults. We speculate that the faults penetrating insoluble formations represent the main dissolution passages that originally developed these karstic fault systems. Additionally, we analyse a series of outcrops, seismic data, and structures to characterize the spatial geometry of these major faults and their surrounding fractures in detail. Most of these are strike-slip faults, and their subsequent reservoirs can be divided into three categories based on their development, including dendritic, sandwich and slab reservoirs. Recent studies demonstrate that karstic fault reservoirs are most common traps in the study area. Although various types of carbonate karstic fault reservoirs are represented in this region, the dendritic karstic fault reservoir is the most hydrocarbon-rich.Guided by these initial results, 108 wells were drilled from 2013 to 2014, producing 485 thousand tons of oil and yielding success ratios greater than 89%. The average production of dendritic reservoirs is 37.4 tons per day (t/d), while those of sandwich and slab types are 20.2 t/d and 14.0 t/d, respectively. These results represent significant references for future hydrocarbon exploration and the development of similar deeply buried karstic fault reservoirs in the Tarim Basin and elsewhere.     

Evaluation method and application of the relative contribution of marine hydrocarbon source rocks in the Tarim basin: A case study from the Tazhong area

In total, 2.37 million tons of marine crude oil originating from mixed source rocks has been discovered in the Tarim basin. Geological and geochemical analyses have confirmed that these mixed hydrocarbons are mainly from two sets of source rocks, including the Cambrian – Lower Ordovician and Middle-Upper Ordovician hydrocarbon source rocks. In this study, we determined the set of source rocks primarily responsible for the mixed hydrocarbons and the next location to be explored. Differences in n-alkane carbon isotopes in end-member oils from Cambrian–Lower Ordovician and Middle-Upper Ordovician source rocks were examined. A material balance model and simulation methods were used to evaluate the relative amounts contributed by each source. The results from known reserves in the Tazhong area show that the mixing ratio or contribution is up to 65% from Cambrian–Lower Ordovician source rocks and is generally higher than that from Middle-Upper Ordovician source rocks. The discovery of deep hydrocarbons has caused the total oil contribution from the Cambrian–Lower Ordovician to increase. The mixing ratio of Cambrian–Lower Ordovician oil varies depending on the well, formation, and block. It increases from west to east horizontally and from top to bottom vertically. Hydrocarbons from Cambrian–Lower Ordovician source rocks migrate upward along faults, and the mixing ratio decreases as the distance from the oil source fault increases. Favorable areas for Cambrian–Lower Ordovician hydrocarbon exploration are deep layers and areas near the fault zone that are connected to deep layers. The material balance model for carbon isotopes and evaluation methods for relative contributions considered differences in relative concentration and carbon isotope structure of n-alkanes. Herein, new methods for the identification and evaluation of hydrocarbons in the petroleum system of this superimposed basin are presented.     

Alteration and multi-stage accumulation of oil and gas in the Ordovician of the Tabei Uplift,Tarim Basin,NW China: Implications for genetic origin of the diverse hydrocarbons

The Ordovician is the most important exploration target in the Tabei Uplift of the Tarim Basin, which contains a range of petroleum types including solid bitumen, heavy oil, light oil, condensate, wet gas and dry gas. The density of the black oils ranges from 0.81 g/cm³ to 1.01 g/cm³ (20 °C) and gas oil ratio (GOR) ranges from 4 m³/m³ to 9300 m³/m³. Oil-source correlations established that most of the oils were derived from the Mid-Upper Ordovician marine shale and carbonate and that the difference in oil properties is mainly attributed to hydrocarbon alteration and multi-stage accumulation. In the Tabei Uplift, there were three main periods of hydrocarbon accumulation in the late Caledonian stage (ca. 450–430 Ma), late Hercynian stage (ca. 293–255 Ma) and the late Himalayan stage (ca. 12–2 Ma). The oil charging events mainly occurred in the late Caledonian and late Hercynian stage, while gas charging occurred in the late Hercynian stage. During the late Caledonian stage, petroleum charged the reservoirs lying east of the uplift. However, due to a crustal uplifting episode in the early Hercynian (ca. 386–372 Ma), most of the hydrocarbons were transformed by processes such as biodegradation, resulting in residual solid bitumen in the fractures of the reservoirs. During the late Hercynian Stage, a major episode of oil charging into Ordovician reservoirs took place. Subsequent crustal uplift and severe alteration by biodegradation in the west-central Basin resulted in heavy oil formation. Since the late Himalayan stage when rapid subsidence of the crust occurred, the oil residing in reservoirs was exposed to high temperature cracking conditions resulting in the production of gas and charged from the southeast further altering the pre-existing oils in the eastern reservoirs. A suite of representative samples of various crude oils including condensates, lights oils and heavy oils have been collected for detailed analysis to investigate the mechanism of formation. Based on the research it was concluded that the diversity of hydrocarbon physical and chemical properties in the Tabei Uplift was mainly attributable to the processes of biodegradation and gas washing. The understanding of the processes is very helpful to predict the spatial distribution of hydrocarbon in the Tabei Uplift and provides a reference case study for other areas.     

Timing and mechanism of reservoir forming in the Upper Triassic Halahatang Formation,Yuqi block,Tarim Basin,northwestern China

The Yuqi block is an important area for oil and gas exploration in the northern Akekule uplift, Tarim Basin, northwestern China. The Upper Triassic Halahatang Formation (T₃h) within the Yuqi block can be subdivided into a lowstand system tract (LST), a transgressive system tract (TST), and a highstand system tract (HST), based on a study of initial and maximum flood surfaces. Oil in the lowstand system tract of the Halahatang Formation is characterized by medium to lightweight (0.8075 g/cm³–0.9258 g/cm³), low sulfur content (0.41%–1.4%), and high paraffin content (9.65%–10.25%). The distribution of oil and gas is principally controlled by low-amplitude anticlines and faults. Based on studies of fluorescence thin sections and homogenization temperatures of fluid inclusions, reservoirs in the T₃h were formed in at least two stages of hydrocarbon charge and accumulation. During the first stage (Jurassic–Cretaceous) both the structural traps and hydrocarbon reservoirs were initiated; during the second stage (Cenozoic) the structural traps were finally formed and the reservoirs were structurally modified. The reservoir-forming mechanism involved external hydrocarbon sources (i.e. younger reservoirs with oil and gas sourced from old rocks), two directions (vertical and lateral) of expulsion, and multi-stage accumulation. This model provides a theoretical fundament for future oil and gas exploration in the Tarim Basin and other similar basins in northwestern China.     

Fault system impact on paleokarst distribution in the Ordovician Yingshan Formation in the central Tarim basin,northwest China

The paleokarst-unconformity at the top of the Ordovician Yingshan Formation in the central Tarim basin was exposed to air for at least 10 Ma, providing favorable conditions for the later formation of high-quality reservoirs. During the karstification process, the fault system plays an important role in controlling the development of paleokarst. This study characterized the fault system through the paleokarst features on the northern slope of the Tazhong High and examined in detail the impacts of the fault system on paleokarst distribution. Formation Micro-Imager logs and seismic curvature change rate were used for characterizing the fault system in different scales. The results revealed three sets of faults in this region. Cross-cutting relationships, unconformities, and relation between faults and karstification indicate Mid-to-Late Ordovician thrust faults, Silurian-Devonian strike-slip faults, and Permian tension faults. “Bright spots” in seismic records calibrated by Formation Micro-Imager logs were used for indicating paleokarst features and different depth distributions, respectively. Furthermore, the study employed spectral decomposition technique to characterize the morphology of paleocave complexes in detail. The results show the Mid-Late Ordovician thrust faults heavily impacted the distribution of paleokarst mainly distributed along master and secondary thrust faults in shallow areas, as well as along master basement-involved thrust faults in deep strata, and along the most pronounced area of paleokarst, Tazhong No. 10 fault zone bounded by back thrusts. The data provides new forecasting information for deep hydrocarbon exploration in paleokarst-related reservoirs of the Yingshan Formation.     

Factors controlling reservoir properties and hydrocarbon accumulation of lacustrine deep-water turbidites in the Huimin Depression,Bohai Bay Basin,East China

Lacustrine deep-water turbidite plays are a novel area for exploration in the Huimin Depression, Bohai Bay Basin. Turbidites in the Shang 847 block, a typical turbidite play in the Huimin Depression, provide an opportunity to study the factors controlling the reservoir properties and hydrocarbon accumulation in lacustrine turbidite sandstones. The reservoir quality of turbidite sandstones (very fine-grained, moderately to well sorted, mainly lithic arkose) in this study area are mainly controlled by the distribution patterns of carbonate cements and pseudomatrix. Significant inverse relationships exist between the volume of carbonate cement and both porosity and permeability of the turbidite sandstones. Carbonate cement is located preferentially near the margins of the sandstone bodies. Sandstones with distance from the sandstone–mudstone contact surface less than 0.7 m or with thickness less than 1.2 m are commonly tightly cemented (carbonate cement >15%) with low porosity and permeability (lower than 10% and 0.1 mD, respectively). The source of carbonate cement was most likely external, probably derived from the surrounding mudstone. Most pore-filling carbonate cements occurred during late diagenesis at burial depths greater than 2200 m. The petrophysical properties of turbidites have a positive relationship with the content of kaolinite and chlorite, but have a negative relationship with the content of illite. 2-D and 3-D reconstructions of non-oil bearing and oil-bearing layers indicate that dissolution of carbonate cement, feldspars and unstable rock fragments was more developed in oil-bearing layers than in non-oil bearing layers and hance oil-bearing layers have higher porosity and larger pore sizes. Petrophysical property appears to have a significant effect on the hydrocarbon accumulation in the turbidite sandstones. Sandstones with porosities lower than 9% and/or permeabilities lower than 0.78 mD are not prone to contain oil.     

Multiple dolomitization and later hydrothermal alteration on the Upper Cambrian-Lower Ordovician carbonates in the northern Tarim Basin,China

Thick Upper Cambrian-Lower Ordovician carbonates were deposited on a shallow marine platform in the northern Tarim Basin, which were extensively dolomitized, particularly for the Upper Cambrian carbonates. The resulting dolomite rocks are predominantly composed of matrix dolomites with minor cement dolomites. Based on petrographic textures, matrix dolomites consist of very finely to finely crystalline, nonplanar-a to planar-s dolomite (Md1), finely to medium crystalline, planar-e(s) dolomite (Md2), and finely to coarsely crystalline, nonplanar-a dolomite (Md3). Minor cement dolomites include finely to medium crystalline, planar-s(e) dolomite (Cd1) and coarsely crystalline, nonplanar saddle dolomite (Cd2), which partially or completely fill dissolution vugs and fractures; these cements postdate matrix dolomites but predate later quartz and calcite infills. Origins of matrix and cement dolomites and other diagenetic minerals are interpreted on the basis of petrography, isotopic geochemistry (O, C and Sr), and fluid inclusion microthermometry. Md1 dolomite was initially mediated by microbes and subsequently precipitated from slightly modified brines (e.g., evaporated seawater) in near-surface to very shallow burial settings, whereas Md2 dolomite was formed from connate seawater in association with burial dissolution and localized Mg concentration (or cannibalization) in shallow burial conditions. Md3 dolomite, however, was likely the result of intense recrystallization (or neomorphism) upon previously-formed dolomites (e.g., Md1 or Md2 dolomite) as the host carbonates were deeply buried, and influenced by later hydrothermal fluids. Subsequent cement dolomite and quartz crystals precipitated from higher-temperature, hydrothermal fluids, which were contributed more or less by the extensive Permian large igneous province (LIP) activity in Tarim Basin as evidenced by less radiogenic Sr in the cement and parts of matrix dolomites. This extensive abnormal hydrothermal activity could also have resulted in recrystallization (or neomorphism) on the previous matrix dolomites. Faults/fractures likely acted as important conduit networks which could have channeled the hydrothermal fluids from depths. However, the basin uplift triggered by the Late Hercynian Orogeny from the Late Permian would have facilitated downward infiltration of meteoric water and dilution of hydrothermal fluids, resulting in precipitation of later calcites in which lighter C and more radiogenic Sr components demonstrate such a switch of fluid properties. This study provides a useful analogue to understand the complicated dolomitizing processes and later hydrothermal alteration intimately related to the Permian LIP activity within Tarim Basin and elsewhere.     

In situ stress field evaluation of deep marine tight sandstone oil reservoir: A case study of Silurian strata in northern Tazhong area,Tarim Basin,NW China

Deep marine tight sandstone oil reservoirs are the subject of considerable research around the world. This type of reservoir is difficult to develop due to its low porosity, low permeability, strong heterogeneity and anisotropy. A marine tight sandstone oil reservoir is present in the Silurian strata in the northern Tazhong area of the Tarim Basin, NW China, at a depth of more than 5000 m. The porosity is between 6% and 8%, and the gas permeability is between 0.1 and 1 × 10⁻³ μm². The features of this type of reservoir include the poor effects of conventional fracturing modifications and horizontal wells, which can lead to stable and low levels of production after staged fracturing. Here, we conduct a comprehensive evaluation of the mechanical properties of the rock and the in situ stress of the target tight sandstones by using numerous mechanical and acoustic property tests, conducing crustal stress analysis and using data from thin section observations. The dispersion correction technique is used to transform velocity at the experimental high frequency (1 MHz) to velocity at the logging frequency (20 kHz). The logging interpretation models of the transverse wave offset time, mechanical parameters and in situ stress are calculated, and each model represents a high precision prediction. Simulating the in situ stress field of the Silurian strata using a three-dimensional finite element method demonstrates that the average error between the simulation result and the measured value is less than 6%. The planar distribution of each principal stress is mainly controlled by the burial depth and fault distribution. By conducting in situ stress orientation analysis for the target layer via the analysis of paleomagnetism, borehole enlargement, fast shear wave orientation and stress field simulation, we show that the direction of the maximum horizontal stress is N45E. In this paper, a typical and successful comprehensive evaluation of the stress field of the deep tight sandstone oil reservoir is provided.     

An inland facies-controlled eogenetic karst of the carbonate reservoir in the Middle Permian Maokou Formation,southern Sichuan Basin,SW China

Carbonate karst is one of the research highlights in the field of carbonate reservoir geology. Here, we report on a new type of karst formed in the Middle Permian Maokou Formation, southern Sichuan Basin, SW China, i.e., inland facies-controlled eogenetic karst, which is different from the previously defined telogenetic karst. This karst is eogenetic as the formation was buried at shallow depths prior to being subaerially exposed for a period of 7–8 Myr, in the paleo-continental region of the Upper Yangtze Uplift. Subaerial exposure may have been caused by a sea level regression during the Tungwu Orogeny, which gave rise to a depositional hiatus over a broad area. The top of the Maokou Formation is commonly marked by a weathered crust and an unconformable relationship with overlying layers. Below the surface, the Maokou Formation contains sediments deposited by an underground drainage. The geological setting can be inferred from an inland karst far from coastline. The subsurface karst interval consists mainly of coarse-grained limestone and micrite, with the former occurring in shoal facies deposited in a high-energy depositional environment, and the latter in non-shoal facies deposited in a low-energy environment. Both of them were interbedded with in variable thicknesses. The coarse-grained limestone layers with high porosity and permeability acted as inception horizons, more favourable for the development of karst than the micritic layers with low porosity and permeability. Therefore, in places where both coarse-grained limestone and micrite are present, the karst is considered to be facies-controlled. The primary permeability of the coarse-grained limestone, combined with the permeability provided by faults and fractures, provides sufficient channels for karst water. Formation of the karst system was characterized by contemporaneous development at multiple levels, as controlled by the stratigraphic position of coarse-grained shoal facies. The karst reservoir therefore developed in both karst highland and karst transitional zone (area between the karst highland and karst basin). According to this model of karstification, hydrocarbon exploration should focus on karst highlands located on palaeohighs and in synclines located far from fault zones.     

Impacts of the tectonic stress field on natural gas migration and accumulation: A case study of the Kuqa Depression in the Tarim Basin,China

Stress, fluid and temperature are three of the major factors that impact natural gas migration and accumulation. In order to study the influences of tectonic stress field on natural gas migration and accumulation in low-permeability rocks, we take the Kuqa Depression as an example and analyze the evolution of the structure and tectonic stress field at first. Then we study the influences of tectonic stress field at different tectonic episodes on fractures and fluid potentials through the numerical simulation method on the section across the KL2 gas field. We summarize two aspects of the impact of the tectonic stress field on natural gas migration and accumulation. Firstly, under the effects of the tectonic stress field, the rock dilation increases with the added stress and strain, and when the shear stress of rock exceeds its shear strength, the shear fractures are well developed. On one hand, the faults which communicate with the hydrocarbon source rocks become the main pathways for natural gas migration. On the other hand, these positions where fractures are well developed near faults can become good reservoirs for natural gas accumulation. Secondly, because fluid potentials decrease in these places near the faults where fractures are well developed, natural gas can migrate rapidly along the faults and accumulates. The impact of tectonic stress fields on natural gas migration and accumulation allows for hydrocarbon migration and accumulation in the low-permeability rocks in an active tectonic compressive setting.     

High-resolution characterization and integrated study of a reservoir formation: the danian carbonate platform in the Aquitaine Basin (France)

This paper provides an example of an integrated multi-scale study of a carbonate reservoir. The Danian Lower R2 carbonate reservoir is located in the South of the Aquitaine Basin (France) and represents a potential underground gas storage site for Gaz de France. The Danian Lower R2 reservoir was deposited as a prograding carbonate platform bordered by a reef barrier. The effects of sedimentary and diagenetic events on the reservoir properties, particularly dolomitization, were evaluated. In this study, the reservoir quality has been assessed by seismic analyses at the basin scale, by log-analysis at the reservoir scale, by petrographic methods and by petrophysical tools at the pore-core scale.Two dolomitization stages, separated by a compaction event with associated fracturing and stylolites, have been identified. These diagenetic events have significantly improved the Lower R2 carbonate reservoir properties. It is demonstrated that the reservoir quality is mainly controlled by the pore-geometry, which is determined by various diagenetic processes. The permeability values of the reservoir range over 4 orders of magnitude, from 0.1 to 5600 mD and the porosity values range between 2 and 42%. Reservoir unit 4 (a karstic dolomite) shows the best reservoir properties with average porosity values ranging between 11.1% and 19.3% and an average permeability ranging between 379 and 766 mD. Reservoir unit 2 (a fine-grained limestone) shows the worst reservoir properties. The cementation factors range from 1.68 to 2.48. The dolomitic crystal carbonate texture (mainly units 3 and 4) shows the highest value of the cementation factor (1.98–2.48) and formation factor (9.54–36.97), which is due to its high degree of cementation. The saturation exponents vary between 1.2 and 3.4. Using these experimental electrical parameters and the resistivity laterolog tool we predicted the water saturation in the various reservoir units. The permeability was predicted by combining the formation factor with the micro-geometric characteristic length. The best fit is obtained with the Katz and Thompson's model and for a constant of 1/171.     

Diagenetic alterations and reservoir heterogeneity within the depositional facies: A case study from distributary-channel belt sandstone of Upper Triassic Yanchang Formation reservoirs (Ordos Basin,China)

Diagenesis is of decisive significance for the reservoir heterogeneity of most clastic reservoirs. Linking the distribution of diagenetic processes to the depositional facies and sequence stratigraphy has in recent years been discipline for predicting the distribution of diagenetic alterations and reservoir heterogeneity of clastic reservoirs. This study constructs a model of distribution of diagenetic alterations and reservoir heterogeneity within the depositional facies by linking diagenesis to lithofacies, sandstone architecture and porewater chemistry during burial. This would help to promote better understanding of the distribution of reservoir quality evolution and the intense heterogeneity of reservoirs. Based on an analogue of deltaic distributary channel belt sandstone in Upper Triassic Yanchang Formation, 83 sandstone plug samples were taken from 13 wells located along this channel belt. An integration of scanning electron microscopy, thin sections, electron microprobe analyses, rate-controlled porosimetry (RCP), gas-flow measurements of porosity and permeability, and nuclear magnetic resonance (NMR) experiments, together with published data, were analysed for the distribution, mineralogical and geochemical characteristics of detrital and diagenetic components and the distribution of reservoir quality within the distributary channel belt.Distribution of diagenetic alterations and reservoir heterogeneity within the distributary channel belt sandstones include (i) formation of high quality chlorite rims in the middle part of thick sandstones with coarser grain sizes and a lower content of ductile components resulted from the greater compaction resistance of these sandstones (providing larger pore spaces for chlorite growth), leading to formation of the intergranular pore – wide sheet-like throat and intergranular pore - intragranular pore – wide sheet-like throat (Φ>15%, k>1mD) in the middle part of thick sandstones; (ii) formation of thinner chlorite rims in the middle part of thinner sandstones is associated with the intergranular pore - intragranular pore – narrow sheet-like throat (9%<Φ<14%, 0.2mD<k<0.8mD); (iii) strong cementation by kaolinite in the more proximal sandstones of distributary channel owing to the strong feldspar dissolution by meteoric water, resulting in the intragranular pore - group of interstitial cement pores – narrow sheet-like throat/extremely narrow sheet-like throat (8%<Φ<11%, 0.1mD<k<0.3mD) due to the pore-filling kaolinite occluding porosity; (iv) formation of dense ferrocalcite zones (δ¹⁸O_VPDB = −23.4‰ to −16.6‰; δ¹³ C_VPDB = −4.0‰ to −2.3‰) favoured in the top and bottom of the channel sandstone which near the sandstone-mudstone bouding-surface, destroying pore space (Φ<8%, k<0.1mD); (v) strong compaction in sandstone of distributary channel edge laterally as a result of fine grain size and high content of ductile components in those sandstones, forming the group of interstitial cement pores – extremely narrow sheet-like throat with porosity values less than 8%.     

Effects of composition and pore structure on the reservoir gas capacity of Carboniferous shale from Qaidam Basin,China

Shale adsorption and breakthrough pressure are important indicators of shale gas development and key factors in evaluating the reservoir capacities of shales. In this study, geochemical tests, pore-structure tests, methane adsorption tests, and breakthrough-pressure tests were conducted on shales from the Carboniferous Hurleg Formation in eastern Qaidam Basin. The effects of the shale compositions and pore structures on the adsorption and breakthrough pressures were studied, and the reservoir capacities of the shales were evaluated by analyzing the shale adsorptions and sealing effects. The results indicate that the organic carbon content was only one of factors in affecting the adsorption capacity of the shale samples while the effect of the clay minerals was limited. Based on the positive correlation between the adsorption capacity and specific surface area of the shale, the specific surface area of the micropores can be used as an indicator to determine the adsorption capacity of shale. The micro-fracturing of brittle minerals, such as quartz, create a primary path for shale gas breakthrough, whereas the expansion of clay minerals with water greatly increases the breakthrough pressure in the shale samples. Methane adsorption tests showed that maximum methane adsorption for shale samples Z045 and S039 WAS 0.107 and 0.09655 mmol/g, respectively. The breakthrough pressure was 39.36 MPa for sample S039, maintained for 13 days throughout the experiment; however, no breakthrough was observed in sample Z045 when subjected to an injected pressure of 40 MPa for 26 days. This indicates that sample Z045, corresponding to a depth of 846.24 m, exhibited higher adsorption capacity and a better reservoir-sealing effect than sample S039 (498.4 m depth). This study provides useful information for future studies of Qaidam Basin shale gas exploration and development and for evaluation of shale quality.     

Geochemistry and charge history of oils from the Yuqi area of Tarim Basin,NW China

The geochemistry, origin and charge history of oils from the Yuqi area of Tarim Basin have been investigated, through GC, GC-MS and fluid inclusion microthermometry analysis. The Yuqi oils accumulated mainly in three intervals: (1) in the Lower-Middle Ordovician Yingshan Formation (O_1-2y) carbonate reservoirs; (2) in the overlying Upper Triassic Halahatang Formation (T₃h); and (3) in the Lower Cretaceous Yageliemu Formation (K₁y) sandstones. Oils from different reservoirs have distinct physical properties, varying from extra-heavy (O_1-2y), heavy (T₃h), to light oils (T₃h and K₁y). However, their geochemical compositions show a high degree of similarity, which indicates that they derive from the same source rock. Abundant tricyclic terpanes, gammacerane, dibenzothiophene and C₂₁C₂₂steranes, together with a low level of diasteranes, indicate an anoxic marine source rock for oils in the Yuqi area. Oil-oil correlation shows that Yuqi oils derive from the same source bed as Tahe oils. The co-occurrence of intact n-alkanes and 25-norhopanes in all the samples supports the proposition that there is a mixture of an early filled severely biodegraded oil and a late filled fresh oil.In this study, charge history is examined on the basis of integration of fluid inclusion homogenization temperature data with 1D burial-thermal history models. Two episodes of oil charging are identified in the O_1-2y reservoir (well YQX1-1) at around 436-420 Ma (Middle-Late Silurian) and 10-3 Ma (Miocene to Pliocene), respectively. For the samples from the T₃h and K₁y intervals, only one episode of oil charge is indicated by the homogenization temperatures of coexisting aqueous inclusions with an inferred timing around 10-3 Ma. The T₃h heavy oil reservoir is assumed to be a secondary hydrocarbon pool, which accumulated by re-migration and re-distribution of hydrocarbons from O_1-2y hydrocarbon pools. The few early biodegraded oils in the K₁y light oils were probably picked up along the migration pathway during the late fresh oil charging.     

Predicting rock mechanical properties of carbonates from wireline logs (A case study: Arab-D reservoir,Ghawar field,Saudi Arabia)

Four hundred plug samples from the Arab-D carbonate reservoir, Ghawar field, were tested for acoustic and mechanical properties at increasing triaxial stress. The results show that the rock mechanical parameters are primarily functions of porosity and, to a lesser degree, of mineralogy, texture and pore fabric (in order of degree of impact from higher to lower). The rock mechanical parameters of the intact matrix rock show no significant changes with stress under reservoir condition.     

Numerical simulation of hydrocarbon migration in tight reservoir based on Artificial Immune Ant Colony Algorithm: A case of the Chang 81 reservoir of the Triassic Yanchang Formation in the Huaqing area,Ordos Basin,China

The hydrocarbon migration in tight reservoirs is a complex process, the fluid flow patterns of which are notably different from those of conventional reservoirs. Therefore, specific mathematical models are needed to simulate the secondary hydrocarbon migrations. This study presents a numerical simulation method based on Artificial Immune Ant Colony Algorithm (AIACA) to simulate the secondary hydrocarbon migrations in tight reservoirs. It consists of three core parts: (1) the release modes of artificial ants based on the intensity of hydrocarbon generation; (2) the wandering patterns of artificial ants under the control of the dynamic field and the distribution of pheromones; (3) the updating modes of pheromones based on the changes in reservoir wettability. The simulation of secondary migration can be realized by the observing the dynamic movements and accumulations of the artificial ants. The method has been tested in the Chang 8₁ tight sandstone reservoir, which is part of the Triassic Yanchang Formation in the Huaqing Area, Ordos Basin in China, and proved to be successful in matching the current data in exploration and development.     

构造-沉积耦合过程的数值模拟：以南海北部阳江凹陷为例

以构造变形为核心的内动力过程和以沉积“源–汇”过程为核心的外动力过程,如何动态塑造盆地精细地貌景观,是油气精准勘探必须突破的关键技术。本研究以南海北部陆缘珠江口盆地的阳江凹陷为例,试图探索NW向阳江–一统暗沙深大断裂带对周缘新生代沉降中心分布的控制作用。为此,本文采用Badlands沉积数值模拟方法,定量分析阳江–一统暗沙断裂带的运动学特征,模拟阳江凹陷新生代地层构造-沉积耦合过程。模拟结果显示,阳江–一统暗沙断裂带在始新世末期是一条左行走滑断裂带,其走滑过程主要可分为两个阶段。其中,在早期慢走滑阶段,走滑位移量约800 m,沿断裂带走滑方向,恩平19洼的沉降中心发生迁移;在后期快走滑阶段,走滑位移量约1200 m,模拟剖面可识别出明显的花状构造,恩平19洼的沉降中心加速向北迁移,并发生逆时针旋转。     

Diagenesis of the palaeo-oil-water transition zone in a Lower Pennsylvanian carbonate reservoir: Constraints from cathodoluminescence microscopy,microthermometry, and isotope geochemistry

Oil-water transition zones in carbonate reservoirs represent important but rarely studied diagenetic environments that are now increasingly re-evaluated because of their potentially large effects on reservoir economics. Here, data from cathodoluminescence and fluorescence microscopy, isotope geochemistry, microthermometry, and X-ray tomography are combined to decipher the diagenetic history of a 5-m-long core interval comprising the oil-water transition zone in a Lower Pennsylvanian carbonate reservoir. The aim is to document the cementation dynamics prior, during, and after oil emplacement in its context of changing fluid parameters. Intergrain porosity mean values of 7% are present in the upper two sub-zones of the oil-water transitions zone but values sharply increase to a mean of 14% in the lower sub-zone grading into the water-saturated portions of the reservoir and a very similar pattern is observed for permeability values. In the top of the water-filled zone, cavernous porosity with mean values of about 24% is found. Carbonate cements formed from the earliest marine to the late burial stage. Five calcite (Ca-1 through 5) and one dolomite (Dol) phase are recognized with phase Ca-4b recording the onset of hydrocarbon migration. Carbon and oxygen cross-plots clearly delineate different paragenetic phases with Ca-4 representing the most depleted δ¹³C ratios with mean values of about −21‰. During the main phase of oil emplacement, arguably triggered by far-field Alpine tectonics, carbonate cementation was slowed down and eventually ceased in the presence of hydrocarbons and corrosive fluids with temperatures of 110–140 °C and a micro-hiatal surface formed in the paragenetic sequence. These observations support the “oil-inhibits-diagenesis” model. The presence an earlier corrosion surface between phase Ca-3 and 4 is best assigned to initial pulses of ascending corrosive fluids in advance of hydrocarbons. The short-lived nature of the oil migration event found here is rather uncommon when compared to other carbonate reservoirs. The study is relevant as it clearly documents the strengths of a combined petrographic and geochemical study in order to document the timing of oil migration in carbonate reservoirs and its related cementation dynamics.     

Reservoir characterization of the Pennsylvanian Caddo Limestone in Stephens County,Texas: A case study of Komia-dominated algal mounds

The Caddo Limestone forms economic carbonate reservoirs in Stephens County, northern Texas. This study demonstrates that, in the Caddo Limestone of the Eliasville and Breckenridge fields, porosity and permeability are best developed in phylloid-algal wackestones and packstones, as well as Komia wackestones and packstones prevalent within the uppermost interval (i.e., Cycle A) of the formation in the study area. The main reservoirs formed in the upper and middle intervals of the Caddo algal mounds because of meteoric dissolution related to subaerial exposure (which created a large volume of secondary pores) and early cementation that prevented mechanical compaction. A great portion of the secondary pores remain open, providing the principal pore spaces of the reservoir interval. Vugs (including moldic voids) are abundant, and dissolution-enhanced intragranular pores are very common within widespread Komia. Intercrystalline pores are prevalent in dolomitized and neomorphised lithofacies where micrite was converted to microsparitic and sparitic calcite. Micropores are abundant in the matrix and within grains (especially Komia fragments). The lower or basal interval of Cycle A is commonly much less porous owing to the substantial loss of primary pores by physical compaction and lack (or rare presence) of secondary pores. Laterally, wells in the areas with thicker Cycle A (interpreted as algal mounds) have higher porosity and thicker net reservoir than those in intermound areas. This work provides a case study of carbonate reservoirs in which Komia wackestones and packstones are the major reservoir rocks.     

Study on the Cretaceous turbidite and reservoir features in the Qingshankou Formation in northern Songliao Basin,NE China

Based on analysis of well and drilling data, cores, sediment grains and 3D seismic data, four types of turbidites–slope fan, channelized, laminated and sublacustrine fan turbidite–are identified in Members 1 and 2 of the Qingshankou Formation in northern Songliao Basin. The slope fan turbidite is located in Members 1 and 2 of the Qingshankou Formation. It is dominated by silt and fine sand and is distributed in an SN-trending ribbon zone along the slope break at delta front in the western part of the basin. The channelized turbidite is located at the bottom of Member 1 of the Qingshankou Formation. It is dominated by silt and fine sand and is distributed in an SN-trending strip-shaped zone along the Qijia-Gulong sag, with funnel-shaped sublacustrine fans at the end. The laminated turbidite body is located in Member 2 of the Qingshankou Formation. It is dominated by siltstone and argillaceous siltstone and is distributed continuously in a tongue-shaped zone along the northern delta front towards the lacustrine region, with belt-like distributaries at the central part and sublacustrine fans at the end. Low-permeability and low-yield lithologic reservoirs are formed near the delta front within the slope fan turbidite and channelized turbidite. There are “sweet spots” in local regions, where reservoir reform techniques are required to attain high industrial yields. Laminated turbidite and sublacustrine fans can form unconventional and continuous reservoirs that generally have no natural productivity; industrial production is impossible until horizontal drilling and multistage volume fracturing are employed. Therefore, the research results are important to the exploration of unconventional oil and gas reservoirs in northern Songliao Basin.