Quantitative Grain Fluorescence Research Articles

Hydrocarbon Generation from Low-Mature Saline Lacustrine Sediments Studied Using Machine Learning and Chemometric Methods: The Succession of the Sikeshu Sag, Junggar Basin, NW China.

Significant attention has been given to the extensive development of saline environments in petroliferous basins. Further exploration and studies have discovered that saline environments, such as those for the deposition of source rocks in the Paleogene Anjihaihe (E2-3 a) Formation of the Sikeshu Sag, are ubiquitous in terrestrial lake basins. Previous studies have suggested that the oil reservoirs in the Sikeshu Sag and its peripheral regions are predominantly derived from the black mudstone and coal measures of the Lower Jurassic Badaowan (J1 b) Formation. However, with deeper exploration of the study area, a growing number of reservoirs with geochemical characteristics different from the J1 b oil source have been discovered, indicating that there are oil sources other than the J1 b source rocks. In this study, various machine learning algorithms were used (random forest, RF; convolutional neural networks, CNN; extreme gradient boosting, XGBoost; ElasticNetCV; Bayesian Ridge; and particle swarm optimization-support vector regression) to select the most suitable algorithm for predicting and comparing the quality of potential source rocks. A violin plot and Taylor diagram were applied to visually compare the reliability and application effectiveness of the models. The results demonstrated that XGBoost and RF can become essential tools for predicting the quality of potential source rocks. Moreover, the measured and predicted values of total organic carbon (TOC), hydrocarbon potential (S1 + S2), and hydrogen index indicate that there are three main source rocks: the E2-3 a, Lower Jurassic Sangonghe (J1 s), and J1 b formations. The thermal maturity of the E2-3 a source rocks is still early mature because of the saline-brackish water nature of these rocks, although large-scale hydrocarbon generation and expulsion can be achieved in the early mature stage. Based on their geochemical characteristics and stepwise discriminant analysis, the oils in the Sikeshu Sag and its peripheral regions can be categorized into two types: groups A and B. Comprehensive organic geochemical evidence suggests that genetically, group A oils are originated from E2-3 a less-mature saline lacustrine sedimentary rocks, while group B oils indicate similar affinity to the Jurassic source. Fluid inclusion microthermometry and one-dimensional basin modeling showed that the oil charging periods of group A and B oils were Middle-Late Miocene (13-8 Ma) and Late Oligocene (23-20 Ma), respectively. Quantitative grain fluorescence (QGF) analysis further propose that the hydrocarbon supply region of the E2-3 a sources is mainly located east of the Western Chepaizi Uplift and the interior area of the Sikeshu Sag, which breaks through the previous understanding that the Jurassic coal-derived oil source is the only main contributor in this study area. The research results can be widely applied to assess the petroleum resources of source rocks in similar areas worldwide.

Permian and Triassic hydrocarbon migration and accumulation in the Cainan area, Junggar Basin, China

Gas Chromatography-Mass Spectrometer (GC-MS), chloroform asphalt “A”, and carbon isotope measurements were used to determine hydrocarbon migration pathways. This study focused on hydrocarbon migration pathways and accumulation distribution in the Wucaiwan region, Junggar Basin, China. The biometric parameters were used to compare oil sources. Type and distribution characteristics of natural gas were determined in order to study the different strata. Quantitative grain fluorescence (QGF) and quantitative grain fluorescence on extract (QGF-E) were analyzed to determine the hydrocarbon migration and charging periods. Geochemical indexes, such as, n-alkane, triterpenoids, sterane, and hopane, were utilized to investigate the pathways of hydrocarbon migration. Recent studies on petroleum maturity have focused on comparison of source rocks and reported that the maturity effects of source rock and reservoir oil are weak, while those effects are high in the Liuchu area. Analysis of triterpenoid and steroid hydrocarbon biomarkers elucidate the underground petroleum migration pathways to the reservoirs. Geochemical analyses of hopane and cholestanes were used. The ααα C29 (20 S)/(20 S + 20 R), C29ββ/(αα + ββ), and C31 hopane 22R/C30 hoopane ratios, and C19/C21 tricyclic terpane ratio, C19/C21 tricyclic terpenes, C31 (22 S)/(22 S + 22 R), and C29 (20 S)/(20 S + 20 R) ratios were analyzed to determine the maturity of crude oil. Petroleum migrated along fault, sandbody, and unconformity, which suggest vertical and lateral migration occurred. Reservoir sandstone porosity and mudstone content of the thick caprock are likely to limit lateral hydrocarbon migration. Petroleum migration and accumulation primarily occurred by vertical migration and lateral migration was weak. The study offers an improved understanding of uncertain hydrocarbon migration pathways and further developed the hydrocarbon migration and accumulation models.

Transformation of a Large Ancient Oil Reservoir to a Dry Gas Reservoir: A Case Study of the Kela-2 Gas Field in the Kuqa Foreland Basin, NW China

Various lines of evidence, including the occurrence of bitumen and fluid inclusions, show that oil charge once took place in the Kela-2 gas field, Kuqa foreland basin, Northwest China. However, the scale of the ancient oil reservoir remains unclear, as does the process by which the reservoir evolved into the present dry gas field. Here, using data from analyses of fluid inclusions, petrography, laser Raman spectroscopy, and quantitative fluorescence, the hydrocarbon accumulation history of the Kela-2 gas field is reconstructed. The results show that the gas field underwent three periods of hydrocarbon charging and one period of adjustment. The first oil charging occurred at about 12 Ma, as recorded by the first group of oil inclusions containing 0–8 vol.% gas with yellowish-brown fluorescence. The second charging involved mature oil charging at about 4 Ma, recorded by the second group of oil inclusions containing 15–25 vol.% gas with blue-white fluorescence. According to quantitative grain fluorescence (QGF) and rock pyrolysis analysis, an ancient oil reservoir existed with an oil-column height of about 350 m, and the paleo oil–water contact was lower than the present gas–water contact. Under intense thrusting from 3 Ma, the ancient oil reservoir was destroyed, with oil escaping through the Kashangtuokai thrust fault, which broke the salt layer, as this layer at that time lay in the brittle deformation domain. The inferred destruction of the ancient oil reservoir is supported by the numerous oil and gas shows at the surface and in shallow layers near the Kashangtuokai fault, as well as the anomalous development of authigenic kaolinite in the gas reservoir, which was enhanced by an open or semiopen system caused by the fault breaking through the salt layer. Subsequently, with increasing burial depth to more than 3000 m, the fault that had cut through the salt layer annealed because the salt layer then lay within the ductile deformation domain. The higher overpressure that occurred during the third gas charging at about 2 Ma reflected the annealing of the fault in the salt layer, favoring late gas accumulation and preservation. The evolution of the Kela-2 gas field provides an important case study for understanding the role of the salt layer crossing the brittle–plastic transition and the dynamic evolution of the salt caprock in salt-containing foreland basins.

Hydrocarbon Accumulation Process and Mechanism in the Lower Jurassic Reservoir in the Eastern Kuqa Depression, Tarim Basin, Northwest China: A Case Study of Well Tudong 2 in the Tugerming Area.

The Lower Jurassic reservoir has recently made a significant breakthrough in petroleum exploration in the Tugerming area of the eastern Kuqa depression, Tarim Basin, northwest China. Therefore, it is significantly essential to simulate the hydrocarbon charging process and analyze the accumulation mechanism in the study area. In our study, we mainly combine three geochemical techniques to identify the origin of crude oils and fluid inclusion characteristics in the target well (Tudong 2), including gas chromatography–mass spectrometry (GC–MS), comprehensive two-dimensional GC-time-of-flight MS (GC × GC–TOFMS), fluid inclusion analysis, and quantitative fluorescence technique. Combined comprehensive experiments with a set of burial history and tectonic thermal evolution history realize the reconstruction of the hydrocarbon charging process in the Yangxia formation. The results show that Jurassic coal-bearing source rocks are primary hydrocarbon sources, and there are three hydrocarbon charging events in the Lower Jurassic reservoir. First, the mature oils have expelled into the reservoir during the early-middle period (15–10 Ma) of the Miocene Kangcun Formation, forming yellow fluorescent oil inclusions and most of the quantitative grain fluorescence (QGF) indexes exceed 4. Second, numerous condensate oils have charged into the reservoir in the period of late Miocene Kangcun Formation-early Kuqa Formation (9–6 Ma), accompanied by blue-white oil inclusions and QGF on extract intensity greater than 4. Finally, vast natural gas has accumulated in the reservoir since Kuqa Formation (5–0 Ma), resulting in the adjustment of ancient reservoir and residual bitumen. Interestingly, we find that the hydrocarbon accumulation mechanism is characterized by self-generation and self-storage in the Jurassic Yangxia Formation, and the study area has prominent characteristics of late accumulation. Thus, the evidence obtained from our analysis suggests favorable geological conditions for the formation of a large oil and gas reservoir in the eastern Kuqa Depression.

Migration and accumulation of crude oils in the Qionghai Uplift, Pearl River Mouth Basin, Offshore South China Sea

The crude oils migration and accumulation of the Qionghai (QH) Uplift in the Zhu Ⅲ Super-depression was investigated from the perspective of oil source and migration conduit using gas chromatography-mass spectrometry (GC-MS), stable carbon isotope, quantitative grain fluorescence (QGF) analysis and basin simulation methods. The results on the oil-source correlation showed that oil origins of the five typical reservoirs were very complicated. Crude oils of the eastern and western parts of the QH Uplift were from the Wenchang A sag and the Wenchang B sag, respectively, whereas oil sources of the central part of the QH Uplift were from both the Wenchang A and B sags. The research on the migration conduit showed that structure ridge, fault and connectivity sand body jointly controlled crude oil migration and accumulation in the study area. Under the control of structure ridges and well-connected sand bodies, crude oils accumulated at a low-magnitude folding structure forming the WC13-1, WC13-2 and QH18-1 reservoirs, whereas the sealed fault played an important role in forming the WC8-3 and WC13-6 reservoirs. Combing the differences in oil origins and crude oils migration conduits, we finally identified two types of crude oils migration and accumulation modes from the Wenchang Sag to the QH Uplift. One was a gentle-slope long-distance migration and accumulation model, which was developed from the Wenchang A sag to the QH Uplift. The other was a steep-slope short-distance migration and accumulation model, which was developed from the Wenchang B sag to the QH Uplift. This study could provide guidance for exploring the petroleum potential and prospecting promising zones in the South China Sea.

Insight into pore-throat size distribution and the controls on oil saturation of tight sandstone reservoirs using nuclear magnetic resonance parameters: A case study of the Lower Cretaceous Quantou Formation in the southern Songliao Basin, China

Pore-throat structure characterization is crucial in tight-oil sandstone reservoir studies. To better understand pore-throat size distribution and the effects on reservoir oil saturation, petrographic, scanning electron microscopy, quantitative grain fluorescence (QGF), nuclear magnetic resonance (NMR), and pressure-controlled mercury injection investigations were performed on a suite of tight sandstones from the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, China. The tight sandstone samples showed similar compositional and textural maturity but different reservoir qualities at different depth intervals. Two oily indicators, QGF index and QGF on extract spectra intensity, varied significantly with respect to burial depth, suggesting the existence of strong oil heterogeneities in the K1q4 tight sandstones. Oil emplacement occurred mainly in the primary pores associated with the absence of pore-filling authigenic minerals. Pore-throat size distributions had wider ranges in the oil-rich layers than in the samples lacking oil emplacement. The NMR pore-throat radii ranged from 0.01 to 10 μm in oil lacking samples but ranged from 0.01 to 100 μm in oil-rich layers. Oil signals were mainly detected in the pore throats with radii ranging from approximately 0.1 to 1.0 μm in oil-rich layers. The NMR porosity can be divided into three parts based on transverse relaxation time (T2) spectrum: (1) immovable fluid, (2) porosity of effective movable fluid (PEMF), and (3) porosity of bound fluid. Bivariate plots of the ratios of various porosity types have significant effects in deciphering the oil saturation of tight sandstone reservoirs. The PEMF reflected well the reservoir QGF index, among others. Therefore, it can be considered as an effective NMR parameter to characterize pore size distribution and helpful in oil reservoir prediction. A good relationship exists between PEMF and geometric mean of the T2 distribution (T2gm), indicating that T2gm could also reflect reservoir oil saturation. The PEMF is mainly contributed by large pore throats, and the poorly sorted pore-throat distribution is better for effective movable fluids occurrence in tight sandstones. The approach employed in this study provides a more comprehensive and accurate pore-throat structure characterization in tight sandstone oil reservoirs, generating effective parameters and convenient ways to evaluate reservoir oil saturation. Importantly, it could be applicable for improving tight sandstone oil exploration and development efficiencies.

Distribution and characteristics of paleo-oil reservoirs in Cambrian Longwangmiao Formation in Anyue area of Sichuan Basin, China

The Anyue gas field is a giant marine gas field with the largest reserves of a single reservoir and the oldest strata in China. In this area, the proved gas reserves in the Cambrian Longwangmiao Formation are 4, 404×108 m3, which are believed to originate from crude oil cracking according to substantial evidences. The paleo-oil reservoirs in the area have been destroyed, and their fluid properties, scale and other characteristics are unclear, despite of the distribution preliminarily determined. In this paper, the paleo-oil reservoirs in the Cambrian Longwangmiao Formation in the Moxi–Gaoshiti area were analyzed thoroughly through conventional microscopic observation, together with quantitative grain fluorescence (QGF), total scanning fluorescence (TSF), and micro-laser Raman analysis. The study results indicate that the Longwangmiao Formation contains bitumen, which is mainly distributed in four types of pore space, i.e. vein-like fractures, dissolution pores, intergranular pores, and intercrystalline pores. The bitumen in vein-like fractures was formed mostly in relation to hydrocarbon migration, while the bitumen in dissolution pores, intergranular pores and intercrystalline pores was formed by in-situ cracking of petroleum, mostly as a result of thermal alteration. The QGF index suggests the existence of paleo-oil reservoirs in certain scale in the study area, and the high QGF-E intensity indicates the property of residual bitumen. The laser Raman spectroscopy reveals the maturity of the extensive solid bitumen in reservoir rocks. The well-cross section illustrates that the paleo-oil reservoirs are mainly layered, have experienced mostly in-situ cracking, and match with the present gas reservoirs.

A method for evaluating paleo hydrocarbon pools and predicting secondary reservoirs: a case study of the Sangonghe Formation in the Mosuowan area, Junggar Basin

Taking the Jurassic Sangonghe Formation in the Mosuowan-Mobei area of the Junggar Basin as an example, this paper provides a method that evaluates paleo hydrocarbon pools and predicts secondary reservoirs. Through Quantitative Grain Fluorescence (QGF) experiments, well-tie seismic correlation, and paleo structure analysis, the scale and distribution of paleo hydrocarbon pools in the study area are outlined. Combining current structural features and fault characteristics, the re-migration pathways of paleo oil and gas are depicted. Based on barrier conditions on the oil re-migration pathways and current reservoir distribution, we recognize three types of secondary reservoirs. By analyzing structural evolution and sand body-fault distribution, the major control factors of secondary reservoirs are specified and, consequently, favorable zones for secondary reservoirs are predicted. The results are mainly as follows. (1) In the primary accumulation period in the Cretaceous, paleo hydrocarbon pools were formed in the Sangonghe Formation of the Mosuowan uplift and their size and distribution were extensive and the exploration potential for secondary reservoirs should not be ignored. Besides, paleo reservoirs were also formed in the Mobei uplift, but just small scale. (2) In the adjustment period in the Neogene, traps were reshaped or destroyed and so were the paleo reservoirs, resulting in oil release. The released oil migrated linearly northward along the structural highs of the Mobei uplift and the Qianshao low-relief uplift and then formed secondary reservoirs when it met new traps. In this process, a structural ridge cooperated with sand bodies and faults, applying unobstructed pathways for oil and gas re-migration. (3) The secondary hydrocarbon pools are classified into three types: low-relief anticlinal type, lithologic pinch-out type and fault block type. The distribution of the first type is controlled by a residual low uplift in the north flank of the paleo-anticline. The second type is distributed in the lithologic pinch-out zones on the periphery of the inherited paleo uplift. The third type is controlled by fault zones of which the strikes are perpendicular to the hydrocarbon re-migration pathways. (4) Four favorable zones for secondary reservoirs are predicted: the low-relief structural zone of the north flank of the Mosuowan paleo-anticline, the fault barrier zone on the western flank of the Mobei uplift, the Qianshao low-relief uplift and the north area of the Mobei uplift that parallels the fault zone. The study above effectively supports the exploration of the Qianshao low-relief uplift, with commercial oil discovered in the Qianshao1 well. Besides, the research process in this paper can also be applied to other basins to explore for secondary reservoirs.

Authigenic minerals related to wettability and their impacts on oil accumulation in tight sandstone reservoirs: An example from the Lower Cretaceous Quantou Formation in the southern Songliao Basin, China

Oil accumulation, being difficult and complicated, is an important issue in petroleum exploration researches. Authigenic minerals, such as carbonate cements and chlorite, can in certain reservoirs alter the wettability of some pore spaces from water-wet to oil-wet. Generally, these oil-wet pore spaces are favorable for oil accumulation. The alteration of reservoir wettability induced by authigenic minerals and the impacts on oil accumulation in tight sandstone reservoirs were investigated using a suite of mineralogical and geochemical characterization techniques, including thin section observation, SEM-EDS, XRD, QEMSEM, CL, quantitative grain fluorescence (QGF), fluorescence spectral analysis, contact angle measurement and sealed coring oil saturation testing on the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, China. The study shows that the tight sandstone reservoirs are compositionally immature with detrital grains distributed homogeneously. Quartz, carbonates and clay minerals that show heterogeneous distribution characteristics are the major authigenic minerals in some parts of the intergranular pores. The detrital mineral assemblage suggests that the reservoir rocks at deposition and before diagenesis had characterized by strong water-wet properties. With the development of authigenic minerals, carbonate cements and authigenic chlorite tend to alter the wettability of some parts of the existing pore spaces from water-wet to oil-wet. In the K1q4 sandstone reservoirs, oil prefers to accumulate in the cemented residual pore spaces around carbonate cements and chlorite. Reservoirs containing about 4–5% carbonate cements are suggested to be more preferable to oil accumulation. These reservoirs are mainly located between sandstone-mudstone interfaces and central parts of the sand bodies. Chlorites have mainly two effects: on one hand, chlorite alters the wettability of existing pore spaces and provides preferential accumulation sites for oil in the tight sandstone reservoirs, on the other hand it can reduce the adhesion of oil through forming “clay-oil flocs” and promote further migration. Consequently, the reservoirs with moderate amount of carbonate cements or chlorite always show relative high oil saturation in the K1q4 tight sandstones.

Utility of GOI, QGF, and QGF-E for interpreting reservoir geohistory and oil remigration in the Hudson oilfield, Tarim basin, northwest China

The physical mechanisms responsible for hydrocarbon migration in carrier beds are well understood. However, secondary migration is one of poorly understood facets in petroleum system. The Carboniferous Donghe sandstone reservoir in the Tarim Basin's Hudson oilfield is an example of a secondary (or unsteady) reservoir; that is, oil in this reservoir is in the process of remigration, making it a suitable geologic system for studying hydrocarbon remigration in carrier beds. Experimental methods including grains containing oil inclusions (GOI), quantitative grain fluorescence (QGF) and quantitative grain fluorescence on extract (QGF-E) -- together with the results from drilling, logging and testing data -- were used to characterize the nature of oil remigration in the Donghe sandstone. The results show that (1) significant differences exist between paleo- and current-oil reservoirs in the Donghe sandstone, which implies that oil has remigrated a significant distance following primary accumulation; (2) due to tectonic inversion, oil remigration is slowly driven by buoyancy force, but the oil has not entered into the trap entirely because of the weak driving force. Oil scarcely enters into the interlayers, where the resistance is relatively large; (3) the oil-remigration pathway, located in the upper part of the Donghe sandstone, is planar in nature and oil moving along this pathway is primarily distributed in those areas of the sandstone having suitable properties. Residual oil is also present in the paleo-oil reservoirs, which results in their abnormal QGF-E. A better understanding of the characteristics of oil remigration in the Donghe sandstone in the Hudson oilfield can contribute to more effective oil exploration and development in the study area.

How does the pore-throat size control the reservoir quality and oiliness of tight sandstones? The case of the Lower Cretaceous Quantou Formation in the southern Songliao Basin, China

Pore-throat size is a very crucial factor controlling the reservoir quality and oiliness of tight sandstones, which primarily affects rock-properties such as permeability and drainage capillary pressure. However, the wide range of size makes it difficult to understand their distribution characteristics as well as the specific controls on reservoir quality and oiliness. In order to better understand about pore-throat size distribution, petrographic, scanning electron microscopy (SEM), pressure-controlled mercury injection (PMI), rate-controlled mercury injection (RMI), quantitative grain fluorescence (QGF) and environmental scanning electron microscopy (ESEM) investigations under laboratory pressure conditions were performed on a suite of tight reservoir from the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, China. The sandstones in this study showed different types of pore structures: intergranular pores, dissolution pores, pores within clay aggregates and even some pores related to micro fractures. The pore-throat sizes vary from nano- to micro-scale. The PMI technique views the pore-throat size ranging from 0.001 μm to 63 μm and revealed that the pore-throats with radius larger than 1.0 μm are rare and the pore-throat size distribution curves show evident fluctuations. RMI measurements indicated that the pore size distribution characteristics of the samples with different porosity and permeability values look similar. The throat size and pore throat radius ratio distribution curves had however significant differences. The overall pore-throat size distribution of the K1q4 tight sandstones was obtained with the combination of the PMI and RMI methods. The permeability is mainly contributed by a small part of larger pore-throats (less than 30%) and the ratio of the smaller pore-throats in the samples increases with decreasing permeability. Although smaller pore-throats have negligible contribution on reservoir flow potential, they are very significant for the reservoir storage capacity. The pore-throats with average radius larger than 1.0 μm mainly exist in reservoirs with permeability higher than 0.1mD. When the permeability is lower than 0.1mD, the sandstones are mainly dominated by pore-throats with average radius from 0.1 μm to 1.0 μm. The ratio of different sized pore-throats controls the permeability of the tight sandstone reservoirs in different ways. We suggest that splitting or organizing key parameters defining permeability systematically into different classes or functions can enhance the ability of formulating predictive models about permeability in tight sandstone reservoirs. The PMI combined with QGF analyses indicate that oil emplacement mainly occurred in the pore-throats with radius larger than about 0.25–0.3 μm. This result is supported by the remnant oil micro-occurrence evidence observed by SEM and ESEM.

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

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

Effects of early petroleum charge and overpressure on reservoir porosity preservation in the giant Kela-2 gas field, Kuqa depression, Tarim Basin, northwest China

Kela-2 is a giant gas field with a proven reserve of 597 tcf in the Kuqa depression, northern Tarim Basin. Widespread overpressures have been encountered in the Eocene and Cretaceous sandstone reservoirs of the field, with pressure coefficients up to 2.1 from drill-stem tests and well-log data analysis. Disequilibrium compaction associated with horizontal tectonic compression may be the dominant overpressure mechanism in the sandstone reservoirs, because the overpressured sandstone with a maximum burial depth over 6000 m (19,685 ft) displays anomalously high porosity and low density. The causes for sandstone reservoirs with anomalously high porosity in the Kela-2 gas field were studied based on an integrated investigation of sandstone reservoir characteristics, paleo oil–water contact, petroleum charge history, and overpressure evolution. Collective evidence indicates that early oil charge had retarded the porosity reduction of the reservoir sandstone and resulted in disequilibrium compaction from overburden rocks, and overpressure from disequilibrium compaction and horizontal tectonic compression at the beginning of the rapid subsidence and deposition in the Kela-2 gas field again contributed to the preservation of the reservoir porosity: (1) overpressured mudstones in the Kela-2 gas field are characteristic of normal compaction, and overpressure was generated by horizontal tectonic compression instead of disequilibrium compaction; (2) the reservoir sandstones with high porosity and permeability are associated with high paleo oil saturation, as indicated by quantitative grain fluorescence (QGF) responses and anomalous QGF on extract intensity; (3) sandstone units below the paleo oil–water contact have very low porosity and permeability; and (4) three episodes of oil and one episode of gas charge are identified in the sandstone reservoirs of the Kela-2 gas field, and the later two episodes of oil charge occurred circa 5.5–4.5 Ma, which corresponds to the beginning of the rapid tectonic subsidence and deposition in the Kuqa depression. The initially charged oil in the sandstone reservoirs was subsequently displaced by gas at circa 3–2 Ma through fault activation at the edge of the anticline trap. The overpressure evolution for the K1bs reservoir sandstone in the Kela-2 gas field indicates that the apparent overpressure development in the sandstone reservoir began at 5 Ma following the major oil charge and has been maintained to the present. Overpressure development from 5 Ma in the sandstone reservoirs of the Kela-2 gas field is believed to be the dominant cause of the porosity preservation.

Two Quantitative Evaluation Methods for Identifying the Migration Pathways in Hydrocarbon Carrier: Application and Comparison

Carrier is an important media linking source rocks and reservoirs. In the past two decades, it is the hot topic for the hydrocarbon geology researchers. Migration pathways in carrier are main space for the hydrocarbon migration. The identification of these pathways has great meaning for the hydrocarbon exploration. In this paper, we define a pathway as a macroscopical area in any shape that relatively apparent hydrocarbon migration exists in the carrier according to some research methods. The sandstone carrier of the Neogene Shawan formation and the unconformity carrier of the Cretaceous being located in the Chepaizi uplift of the Junggar Basin (NW China) are selected as research objects. We used quantitative grain fluorescence analysis (QGF) and effective migration thickness analysis (EMT) to quantitatively study these two kinds of pathways. Migration characteristics of the hydrocarbons are analyzed in single wells and in plane. Analysis results show that evaluation and prediction results from two methods are very similar. This verifies the feasibility of those methods for pathways analysis. Based on the calibration of commercial oil flow well, distribution of migration pathways in plane is obtained, which narrow down the exploration areas. Through practical application, the application process and the considerations of the two methods are discussed and compared. For sandstone carrier, the thickness can be obtained from well logging reports and well logging diagrams. Precondition that the samples collected are located in the carrier interval in QGF analysis is needed. For unconformity carrier, identification of the unconformity surfaces is an important basic work. Increasing the sampling density can reduce the analytical errors caused by the inhomogeneous distribution of oil. EMT method is simple; however, the precondition for application is that the oil in the carrier is not too light and is well preserved in geology history.

Hydrocarbon charge in the onshore Canning Basin: insights from quantitative fluorescence and fluid inclusion investigations

The vast and mostly onshore Canning Basin—with an area of approximately 595,000 m2—is the least explored onshore sedimentary basin in Australia. As part of the petroleum system assessment carried out by WA DMP, more than 160 samples were investigated from eight wells in the onshore Canning Basin—they are: Acacia-1 Dodonea-1 Dodonea-2 Lake Hevern-1 Looma-1 White Hill-1 Wilson Cliffs-1 Yulleroo-1. Fluid inclusion and quantitative fluorescence techniques developed by CSIRO were used, including: The grains containing oil inclusions (GOITM) technique; The quantitative grain fluorescence (QGF) technique; QGF on extracts (QGF-E); and, the total scanning fluorescence (TSF) technique. The results reveal a widespread occurrence of hydrocarbon shows in the reservoir intervals investigated—7–8 wells showed evidence of oil migration and/or accumulations often occurring at multiple depth intervals. In White Hill-1, elevated QGF and QGF-E responses were recorded in the sandy units in a depth interval of more than 500 m in the Fairfield Group. A residual or palaeo oil column of >20 m gross height at 1,655 m was apparent from the QGF and QGF-E depth profiles—and GOI and TSF data. Oil inclusions from the Fairfield Group in White Hill-1 show spectral signature typical of thermally mature and light-medium API gravity. The TSF results also indicate the presence of some condensate species, as well as relatively heavy and possibly bio-degraded oils. The new fluid inclusion and fluorescence data provide direct evidence of an active petroleum system in the Canning Basin at multiple reservoir intervals, which may be of local significant quantity.

Hydrocarbon charge history of the Gippsland Basin

As part of a larger petroleum system analysis and resource re-evaluation research program in the Gippsland Basin, over 400 samples from 29 selected wells in the Gippsland Basin were investigated using quantitative fluorescence techniques developed by CSIRO Petroleum, including the quantitative grain fluorescence (QGF) and QGF on extracts (QGF-E) and the total scanning fluorescence (TSF) techniques. Preliminary results have provided new insight into the hydrocarbon migration and charge history of the Gippsland Basin. The investigation has revealed: widespread occurrence of palaeo oil columns in some of the major gas fields, indicating that a significant amount of oil was charged into these reservoirs prior to a subsequent gas accumulation; that some of the current oil intervals appear to have received a relatively late oil charge, either through new charge or through palaeo oil re-distribution due to adjustments within the petroleum system; palaeo oil columns appear to be restricted to a certain distance range from the major source kitchens; and, evidence of a sequential oil migration and displacement along structural highs where reservoirs distal to the source kitchens received progressively lighter and more mature palaeo oils. These findings are consistent with the oil generation and migration model proposed by O’Brien et al (2008). Fluid inclusion petrographic investigations and molecular composition of inclusions (MCI) analysis are currently underway that will provide additional information on the hydrocarbon charge history in the Gippsland Basin.

Application of quantitative grain fluorescence techniques to study subtle oil migration pathway of lithological reservoir

This paper analyzes the quantitative grain fluorescence (QGF) and quantitative grain fluorescence on extract (QGF-E) properties of 101 rock samples by using quantitative grain fluorescence techniques. The samples are collected from five wells in tight sandstone and thin siltstone in the third sector of the Shahejie Formation in the Niuzhuang sag of the Dongying depression. It was observed that both the tight sandstone and thin siltstone show relatively high fluorescence intensity of hydrocarbon, which suggests that they are possibly good subtle oil-migration pathways in the present or geological time. These thin subtle oil-migration pathways afford important clues for the researches on hydrocarbon accumulation in lithological reservoirs in the middle and lower of Es 3 in deep sag zone, which has the hydrocarbon source from the upper of Es 4 when there is no apparent fault playing oil migration conduits to connect lithologic traps and deep source rocks. This study shows good prospect of QGF techniques in discriminating oil migration pathways and paleo-oil zones. The results of this study may be of great significance to the researches on hydrocarbon accumulation mechanism of subtle reservoirs in the Dongying depression and other areas.

Petroleum charge history in the Lunnan Low Uplift, Tarim Basin, China – Evidence from oil-bearing fluid inclusions

The petroleum charge history in the Lunnan Low Uplift (Tarim Basin, China) was investigated by comparing the geochemical characteristics of fluid inclusion (FI) oils from Ordovician and Triassic reservoirs with crude oils from stratigraphically different reservoirs. Quantitative Grain Fluorescence (QGF) and Total Scanning Fluorescence (TSF) were used to screen the reservoir samples so as to identify suitable samples for Molecular Composition of Inclusion (MCI) analysis. All of the samples contain C 30 n-propylcholestanes, diagnostic of marine source rocks. The Ordovician-hosted FI oils differ from the Triassic-hosted FI oils, having higher relative abundances of C 19 tricyclic terpane, C 24 tetracyclic terpane and rearranged hopanes (Ts and C 29 Ts), and higher Pr/Ph ratios, while the Triassic-hosted FI oils have lower Pr/Ph ratios and higher relative abundances of C 23 tricyclic terpane, arylisoprenoids, 25-norhopanes and C 35 homohopane. Several of the crude oils are similar to the Triassic-hosted FI oils. Based on the geochemical characteristics of the FI and crude oils combined with information on the burial history of the area, at least two petroleum charge episodes can be distinguished in the Lunnan Low Uplift. An early charge represented by the Ordovician-hosted FI oils was biodegraded, as evidenced by the presence of 25-norhopanes in the Triassic-hosted FI oils and crude oils but not in the Ordovician-hosted FI oils. Ordovician-hosted FI oils provide the only evidence for oil generated from Cambrian-Lower Ordovician source rocks. Triassic-hosted FI oils and crude oils in the Ordovician, Carboniferous and Triassic reservoirs are mixtures of biodegraded oil from an early charge episode, and more mature oil from later charge.

Applying quantitative fluorescence techniques to investigate petroleum charge history of sedimentary basins in Australia and Papuan New Guinea

Two fluorescence techniques namely Quantitative Grain Fluorescence (QGF) and QGF on Extract (QGF-E) were employed to investigate hydrocarbon charge history in 17 wells from seven sedimentary basins in Australia and Papua New Guinea including the Exmouth, Barrow, Vulcan, Timor Sea (joint petroleum development area), Cooper, Gippsland, and Papuan basins. The investigation has delineated a widespread occurrence of residual and palaeo oils in all seven basins including (1) residual oil columns below current oil–water contacts (OWCs) and in currently water-bearing “dry” wells; (2) palaeo oil accumulation within current gas zone; (3) palaeo oil columns below current OWCs, and (4) palaeo oil in currently water-bearing “dry” wells. The QGF and QGF-E methods, which provide information on both current and palaeo oil saturation, have been shown to be very effective in unravelling hydrocarbon charge history in the wells investigated.

Quantitative fluorescence techniques for detecting residual oils and reconstructing hydrocarbon charge history

Two new fluorescence techniques, quantitative grain fluorescence (QGF) and quantitative grain fluorescence on Extract (QGF-E), can detect palaeo-oil zones and current residual oil zones in petroleum wells, respectively. QGF and QGF-E measure the fluorescence emission spectra of trace fluorescence from reservoir grains and their extracts. QGF is measured on dry, disaggregated reservoir grains after a cleaning procedure involving solvent, hydrogen peroxide and acid; whereas QGF-E is measured on the solvent extract from the QGF cleaned grains. Palaeo-oil zones have distinct QGF spectra with spectral peaks between 375 and 475 nm and elevated fluorescence intensities compared with spectra for rocks that have always been water saturated. Current and residual oil zones have distinct QGF-E spectra with spectral peaks at around 370 nm and elevated QGF-E intensities compared with that for current water zones. Both QGF and QGF-E responses increase upwards from the palaeo-oil–water and residual oil–water contacts, respectively. An oil producing well from Timor Sea, NW Australia was investigated in detail using the QGF and QGF-E techniques to illustrate how they can be used to reconstruct hydrocarbon migration history.