Lower Jurassic Reservoirs Research Articles

Diagenetic controls over reservoir quality of tight sandstone in the lower Jurassic reservoir in the Lenghu area, the north margin of Qaidam basin

The Lower Jurassic Reservoir (LJR) in the Lenghu area on the northern margin of the Qaidam Basin (NMoQB) has become the most promising target for hydrocarbon exploration. The reservoir has experienced complex diagenesis; however, the porosity evolution and the influence of different diagenesis events on reservoir densification remains unclear. In this study, various analytical methods was first used to clarify the diagenetic stage and sequence, establish a porosity evolution model, quantitatively analyze the time and influence of different diagenesis events on reservoir densification, and illustrate the densification mechanism of tight sandstone reservoir in the Lenghu area. The results showed that the dominant rock types in the LJR were feldspathic litharenite, followed by litharenite, lithic arkose, and a small amount of subarkose and sublitharenite. The reservoir is a typical tight sandstone reservoir (TSR), with average porosity and permeability of 5.5% and 0.08 mD, respectively. The pore types were primarily secondary pores, followed by residual intergranular pores and occasional fractures. Diagenesis of LJR has entered the meso-diagenetic stage A, with minor progression into meso-diagenetic stage B. Quantitative calculation showed that the initial porosity of LJR is 32.2%. In eo-diagenetic stage A, compaction is the main factor for porosity reduction. In eo-diagenetic stage B, the porosity loss rates caused by compaction and cementation were 81.5% and 11.8%, respectively. In this stage, the LJR in the Lenghu area has almost been densified, mainly affected by compaction, calcite cementation and clay minerals cementation. Additionally, cementation is an important factor causing reservoir heterogeneity and is dominated by calcite and clay mineral cementation. After entering the meso-diagenetic stage A, dissolution is the main diagenesis event, which can increase porosity by 6.0%. This stage is the critical period for forming high-quality reservoir of LJR in the Lenghu area, mainly in the 4,400 m depth. In meso-diagenetic stage B, the influence of dissolution gradually decreased. Simultaneously, in this stage, the cementation of iron-bearing calcite further strengthened the densification of the LJR in the Lenghu area.

Molecular and Carbon Isotopic Compositions of Crude Oils from the Kekeya Area of the Southwest Depression, Tarim Basin: Implications for Oil Groups and Effective Sources

Molecular and stable carbon isotopic compositions of 32 crude oils from the Kekeya area of the Southwest Depression, Tarim Basin, were analyzed comprehensively to clarify oil groups and trace oil sources. The results indicate that lacustrine shale sequences within the Upper-Middle Permian Pusige Formation (P3–2p) are the major effective oil sources; the thermal maturation effects exert the crucial impact on geochemical compositions of crude oils. In the Kekeya structural belt, crude oils produced from the Lower-Neogene, Middle-Paleogene and Middle-Cretaceous sandstone reservoirs were generated mainly from deeply buried P3–2p at the late-to-high maturity stage. These condensates are depleted in terpanes, steranes and triaromatic steranes and enriched in adamantanes and diamantanes. The evaluated thermal maturity levels of crude oils by terpanoids and steranes are generally lower than that of diamondoids, implying at least two phases of oil charging. In the Fusha structural belt, oils produced from the Lower-Jurassic reservoirs (J1s) of Well FS8 were generated from the local P3–2p at the middle to late mature stage. On the contrary, these oils are relatively rich in molecular biomarkers such as terpanes and steranes and depleted in diamondoids with only adamantanes detectable. The P3–2p-associated oils can migrate laterally from the Kekeya to Fusha structural belt, but not to the location of Well FS8. The Middle-Lower Jurassic (J1–2) lacustrine shales as the major oil sources are limited to the area around Well KS101 in the Kekeya structural belt. Crude oils originated from J1–2 and P3–2p can mix together within the Cretaceous reservoirs of Well KS101 by presenting the concurrence of high concentrations of terpane and sterane biomarkers and diamondoids as well as 2–4% 13C-enriched n-alkanes than those of P3–2p derived oils. This study provides a better understanding of hydrocarbon sources and accumulation mechanisms and hence petroleum exploration in this region.

Hydrogeochemistry of productive Lower Jurassic deposits of the Talinskoye oil field in Western Siberia

The aim of the study is to determine, in terms of the prevalence of influence of natural or technogenic factors, the factors of formation of the hydrogeochemical composition of productive Lower Jurassic deposits of the Talinskoye oil field. During the study, the authors of the article evaluated the effects of sedimentogenesis, elutriation, neotectonic processes and oilfield water injection on the chemical composition of the waters studied. Water injection is known to cause changes in the hydrogeochemical balance and the formation of technogenic hydrogeological systems. Formation water salinities currently range from 3.7 to 15.3 g/dm3. More than 8960.3 thou-sand m3 of water was injected from overlying sediments into productive formations to maintain reservoir pressure (2014-2021). The authors analysed the genetic coefficients of different types of water (including injected water). Then they compared the coefficients. It was concluded that injected water currently doesn't have a significant impact on the hydrogeochemical appearance of the productive Lower Jurassic reservoirs of the Talinskoye oil field.

An integrated workflow for petrophysical characterization, microfacies analysis, and diagenetic attributes of the Lower Jurassic type section in northeastern Africa margin: Implications for subsurface gas prospection

The Jurassic sedimentary sequences are an important source and reservoir rocks in the North Africa margin, with its type section, outcropped at the Gebel El-Maghara massif and some other sites along the southern Tethys. These exposed Jurassic outcrops, of the intercalated continental and marine sediments, allow us to conduct more detailed and integrated studies on the various depositional settings with diverse lithologies as analogous for the subsurface reservoirs. The present study concerns the implication of the mineralogical components and the diagenetic controls on the petrophysical properties and the reservoir characteristics of the Lower Jurassic in Gebel El-Maghara outcrop sequence (from base to top Mashaba, Rajabia, and Shusha Formations) in north Sinai, Egypt. Some field trips were conducted, and samples were collected, to characterize the petrographical and petrophysical characteristics of these deposits using comprehensive standard techniques including studying thin sections, SEM imaging, XRD analysis, and various petrophysical measurements. A workflow is proposed to apply a full set of petrophysical measurements on the collected samples including porosity (∅He), permeability (k), grain and bulk densities (ρg and ρb, respectively), and true formation resistivity factor. In this workflow, we have integrated the petrophysical data with detailed microfacies analysis to reveal the implication of diagenesis on the reservoir quality of the Lower Jurassic reservoirs. The Lower Jurassic sequence is subdivided into five hydraulic flow units (HFUs) that consist of three reservoir rock types (RRTs). These RRTs are composed of three microfacies associations (MFAs). The RRT1 plug samples consist of the mostly clastic MFA1; they are porous, permeable, and have good reservoir quality that is using the flow zone indicator (FZI), and the reservoir quality index (RQI). The lowest reservoir quality is assigned to the RRT samples which are mostly composed of tight carbonates. Based on the petrographical studies, SEM imaging, and the XRD analysis, dissolution and fracturing slightly enhanced the reservoir potentiality of the RRT1 samples, whereas physical compaction, tight cementation, and authigenic clay content (kaolinite, hematite, and goethite) are responsible for the deterioration of the reservoir properties of RRT3 samples and reduction of the RRT2 samples. The study outcrop has the potential to be an excellent analogue for the important subsurface Jurassic gas-bearing deposits on the African's northern margins. Furthermore, it may provide insights into the fluid flow units, mineralogical composition, and diagenetic controls on the unique Lower Jurassic deposits of Gebel El-Maghara for the assessment of subsurface gas-bearing sequences in the nearby Mediterranean and Gulf of Suez from the southern Tethys shorelines.

COMPOSITION OF LIGHT HYDROCARBONS IN JURASSIC TIGHT OILS IN THE CENTRAL SICHUAN BASIN, CHINA: ORIGIN AND SOURCE ROCK CORRELATION

Crude oil reserves in tight Middle and Lower Jurassic reservoirs are of increasing exploration interest in the central Sichuan Basin, SW China. However, the origin of these “tight oils” is poorly understood. In this study, sixteen samples of light oils/condensates from tight Middle and Lower Jurassic reservoir rocks were analysed using gas chromatography (GC) and isotope ratio mass spectrometry to investigate the oils’ origin and to classify them into genetic families. The tight oils can be divided into two families. Family I oils occur in the Gongshanmiao oilfield where reservoir units comprise the Da'anzhai Member of the Lower Jurassic Ziliujing Formation, the Lower Jurassic Lianggaoshan Formation, and the First Member of the Middle Jurassic Shaximiao Formation. Family I oils are characterized by relatively low values of the methylcyclohexane (MCH) and cyclohexane (CH) indexes, low values of Mango's parameter K2 for light hydrocarbon composition, and relatively negative δ13C values ranging from ‐30.8‰ to ‐28.9‰. Family I oils are inferred to be self‐sourced by lacustrine shales in the Da'anzhai Member and the Lianggaoshan Formation in the study area, both of which are rich in sapropelic organic matter. These source rocks also charged reservoirs in the First Member of the Shaximiao Formation. By contrast, the newly discovered Family II oils, which occur at the Jinhua oilfield and the as‐yet undeveloped Qiulin and Bajiaochang structures, are reservoired in the Second Member of Shaximiao Formation. Family II oils have higher values of the MCH index, CH index and Mango's K2 parameter, and δ13C values varying from ‐27.5‰ to ‐25.4‰. These oils have similar light hydrocarbon compositions and δ13C values to oils derived from source rocks in the Upper Triassic Xujiahe Formation which contain dominantly humic organic matter. Family II oils are therefore inferred to be derived from the coaly mudstones in the Xujiahe Formation.The different compositions of the tight oils in the First and Second Members of the Shaximiao Formation appear to be controlled by the distribution and thickness of source rocks in the study area. Thus, the Gongshanmiao oilfield where Family I oils occur in the First Member is close to the depocentre of source rocks in the Da'anzhai Member and Lianggaoshan Formation. These source rocks are inferred to have charged the First Member reservoirs which may also be present in nearby oil‐ and gas‐bearing structures such as Nanchong and Yingshan. By contrast, Family II oils occur in tight reservoirs in the Second Member in areas with thick successions of Upper Triassic Xujiahe Formation mudstone source rocks, such as the Jinhua oilfield. In areas where both source rocks are present such as the Zhongtaishan and Lianchi oilfields, Shaximiao Formation reservoirs appear to contain both Family I and Family II oils.

Characteristics of hydrocarbon migration and accumulation in the Lower Jurassic reservoirs in the Tugerming area of the eastern Kuqa Depression, Tarim Basin

The hydrocarbon migration and accumulation process in the Kuqa Depression are complex. In recent years, the Jurassic strata have recorded hydrocarbon discoveries in the Tugerming area of the eastern Kuqa Depression. However, it is a new exploration area, and the characteristics of hydrocarbon accumulation are unclear, restricting oil and gas exploration and development. In our study, the deeply-buried and shallow-buried Jurassic strata in the Tugerming area are the research objects. Quantitative fluorescence technique and the observation of fluid inclusions are implemented on the selected samples of Jurassic reservoirs to determine the stages and times of hydrocarbon charging. Gas chromatography-mass spectrometry analysis for saturated hydrocarbons is used to identify the origin of organic matter in oils. Combined analytical data with the reconstructed histories of burial, thermal evolution and tectonic evolution, allow simulating the hydrocarbon migration and accumulation process in the Tugerming area. The results show that two categories of hydrocarbon accumulation mechanisms (Burnham and Sweeney, 1989). The first type is acted as the type of “self-generation and self-storage and late accumulation”. Three stages of hydrocarbon charging have occurred in the deeply-buried Lower Jurassic reservoirs, represented by two wells (Tudong 2 and Tuge 4). The charging time is the early-middle stage of Miocene Kangcun Formation (18–9 Ma), forming the yellow or yellow-green fluorescent oil inclusions and paleo-oil reservoir. During the sedimentary period of the late Kangcun Formation to the early Kuqa Formation (9–5 Ma), the reservoir experienced massive condensate oil migration, corresponding to blue-white fluorescent oil inclusions. Large-scale natural gas was expelled into the reservoirs since the deposition stage of Kuqa Formation (5–0 Ma), and then accumulated in the trap controlled by the late Himalayan movement, forming the current gas reservoir. Moreover, the hydrocarbons are generated from Jurassic coal measure source rocks in the Well Tudong 2 based on the characteristics of biomarkers (Burruss et al., 1991). The second type is characterized by “lower source rock and upper reservoir and accumulation in the late or recent period”, developed in the shallow-buried Lower Jurassic reservoirs containing two wells (Tuxi 1 and Mingnan 1). In this case, there are two stages of crude oil charging: mature oil charging in the early-medium Miocene (18–12 Ma) and condensate oil migration in the late Miocene (8–5 Ma). The strata suffered denudation due to the stratigraphic uplifting in the orogenic movement, resulting in the leakage of the early oil reservoir. In both categories, it suggests that the Lower Jurassic reservoirs in the Tugerming area have the favorable potential for oil and gas exploration. The understanding of hydrocarbon migration and accumulation in the Lower Jurassic reservoirs in the Kuqa Depression of Tarim Basin can contribute to the knowledge of the potential to form large oil and gas reservoirs Tugerming Area, and reservoirs of basins with a similar tectonic settings, such as the Jungar Basin.

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.

Influence of capillary threshold pressure and injection well location on the dynamic CO2 and H2 storage capacity for the deep geological structure

The subject of this study is the analysis of influence of capillary threshold pressure and injection well location on the dynamic CO2 and H2 storage capacity for the Lower Jurassic reservoir of the Sierpc structure from central Poland. The results of injection modeling allowed us to compare the amount of CO2 and H2 that the considered structure can store safely over a given time interval. The modeling was performed using a single well for 30 different locations, considering that the minimum capillary pressure of the cap rock and the fracturing pressure should not be exceeded for each gas separately.Other values of capillary threshold pressure for CO2 and H2 significantly affect the amount of a given gas that can be injected into the reservoir. The structure under consideration can store approximately 1 Mt CO2 in 31 years, while in the case of H2 it is slightly above 4000 tons. The determined CO2 storage capacity is limited; the structure seems to be more prospective for underground H2 storage. The CO2 and H2 dynamic storage capacity maps are an important element of the analysis of the use of gas storage structures. A much higher fingering effect was observed for H2 than for CO2, which may affect the withdrawal of hydrogen. It is recommended to determine the optimum storage depth, particularly for hydrogen. The presented results, important for the assessment of the capacity of geological structures, also relate to the safety of use of CO2 and H2 underground storage space.

Impact of Diagenesis on the Low Permeability Sandstone Reservoir: Case Study of the Lower Jurassic Reservoir in the Niudong Area, Northern Margin of Qaidam Basin

The Lower Jurassic reservoir in the Niudong area of the northern margin of Qaidam Basin is a typical low permeability sandstone reservoir and an important target for oil and gas exploration in the northern margin of the Qaidam Basin. In this paper, casting thin section analysis, scanning electron microscopy, X-ray diffraction, and stable isotope analysis among other methods were used to identify the diagenetic characteristics and evolution as well as the main factors influencing reservoir quality in the study area. The predominant types of sandstone in the study area are mainly feldspathic lithic sandstone and lithic arkose, followed by feldspathic sandstone and lithic sandstone. Reservoir porosity ranges from 0.01% to 19.5% (average of 9.9%), and permeability ranges from 0.01 to 32.4 mD (average of 3.8 mD). The reservoir exhibits robust heterogeneity and its quality is mainly influenced by diagenesis. The Lower Jurassic reservoir in the study area has undergone complex diagenesis and reached the middle diagenesis stage (A–B). The quantitative analysis of pore evolution showed that the porosity loss rate caused by compaction and cementation was 69.0% and 25.7% on average, and the porosity increase via dissolution was 4.8% on average. Compaction was the main cause of the reduction in the physical property of the reservoir in the study area, while cementation and dissolution were the main causes of reservoir heterogeneity. Cementation can reduce reservoir space by filling primary intergranular pores and secondary dissolved pores via cementation such as a calcite and illite/smectite mixed layer, whereas high cement content increased the compaction resistance of particles to preserve certain primary pores. δ13C and δ18O isotopes showed that the carbonate cement in the study area was the product of hydrocarbon generation by organic matter. The study area has conditions that are conductive to strong dissolution and mainly occur in feldspar dissolution, which produces a large number of secondary pores. It is important to improve the physical properties of the reservoir. Structurally, the Niudong area is a large nose uplift structure with developed fractures, which can be used as an effective oil and gas reservoir space and migration channel. In addition, the existence of fractures provides favorable conditions for the uninterrupted entry of acid fluid into the reservoir, promoting the occurrence of dissolution, and ultimately improves the physical properties of reservoirs, which is mainly manifested in improving the reservoir permeability.

Thermal waters of central Poland: a case study from Mogilno\u2013\u0141\xf3d\u017a Trough, Poland

Thermal waters in Poland occur in several different geothermal regions, but the best parameters for their effective utilisation are connected i.a. with the area of Polish Lowlands. One of the most prospective areas in the central part of Polish Lowlands for managing geothermal waters for various purposes is the area of Mogilno–Łódź Trough. There are currently 2 operating geothermal heating plants and several others in various stages of development. In this area, water with a temperature of 97.5 °C has been documented. The aim of this article is to determine and visualise the potential of geothermal waters of the central Poland (Mogilno–Łódź Trough) by providing the most important, potential geothermal water parameters. It is done by providing maps of potential temperature, mineralization, water outflow capacity, thermal power and physicochemical analysis (mineralization, waters type). The two most prospective geothermal reservoirs—Lower Jurassic and Lower Cretaceous—were analysed. The results of the studies indicate that this area is characterised by very favourable hydrogeological conditions. Geothermal energy utilisation should be connected with Lower Jurassic and Lower Cretaceous reservoirs, but it should be emphasised that a larger energy potential relates to waters from Lower Jurassic reservoir; however, they are characterised by high water mineralisation (up to 170 g/L). Waters of Lower Cretaceous reservoir are characterised by not only lower mineralisation (up to 100 g/L), but also lower temperature (max. 75 °C). The highest temperatures in the Lower Jurassic are recorded in the axial part of the Trough, where, locally, they exceed in the top of formation 100 °C. On the other hand, in edge Trough zones, water temperatures are 30–40 °C. The actual geothermal potential of the area is much higher than currently used. For example, potential discharge of wells is to over 400 m3/h in the Lower Cretaceous and up to over 500 m3/h in the Lower Jurassic.

Variability of lithofacial parameters of Lower Jurassic geothermal aquifer in the Malanów region revealed by interpretation of geophysical well logs and seismic data

The Lower Jurassic aquifer is the main target for exploitation of geothermal waters in the Polish Lowlands as it covers over 80% of the area of Poland. Particularly favorable geothermal conditions dominate in the Mogilno-Łodź Trough (central part of the Polish Lowlands), where that aquifer occurs at greatest depth, which results in high temperatures of geothermal waters. The main Lower Jurassic reservoirs in that area are Sinemurian, Pliensbachian, and Upper Toarcian sandstones. These sediments show high lithofacial variability, which results in local changes of hydrogeothermal parameters. Such local variability can be effectively estimated using the seismic data and the interpretation of well logs. Both methods were used for determination of depths to the top surface of Lower Jurassic formation and of distribution of porosity, and clay content, which enabled the researchers to recognize the spatial arrangement of groundwater horizons. The study area is a local structure within the Mogilno-Łodź Trough, in the vicinity of Malanow village. This is a synclinal structure built of Lower Jurassic strata close to the Turek Salt Pillow. Temperature of groundwater in that structure exceeds 80 °C and favorable reservoir parameters ensure relevant discharge. Sandstone horizons show thicknesses over 50 m, low clay contents and porosity around 0.15–0.20.

Characteristics and accumulation models of Middle and Lower Jurassic reservoirs in Kongnan area, Huanghua depression

Characteristics and accumulation models of Middle and Lower Jurassic reservoirs in Kongnan area, Huanghua depression

Modelling geothermal conditions in part of the Szczecin Trough – the Chociwel area

Abstract The Chociwel region is part of the Szczecin Trough and constitutes the northeastern segment of the extended Szczecin-Gorzów Synclinorium. Lower Jurassic reservoirs of high permeability of up to 1145 mD can discharge geothermal waters with a rate exceeding 250 m3/h and temperatures reach over 90°C in the lowermost part of the reservoirs. These conditions provide an opportunity to generate electricity from heat accumulated in geothermal waters using binary ORC (Organic Rankine Cycle) systems. A numerical model of the natural state and exploitation conditions was created for the Chociwel area with the use of TOUGH2 geothermal simulator (i.e., integral finite-difference method). An analysis of geological and hydrogeothermal data indicates that the best conditions are found to the southeast of the town of Chociwel, where the bottom part of the reservoir reaches 3 km below ground. This would require drilling two new wells, namely one production and one injection. Simulated production with a flow rate of 275 m3/h, a temperature of 89°C at the wellhead, 30°C injection temperature and wells being 1.2 km separated from each other leads to a small temperature drop and moderate requirements for pumping power over a 50 years’ time span. The ORC binary system can produce at maximum 592.5 kW gross power with the R227ea found as the most suitable working fluid. Geothermal brine leaving the ORC system with a temperature c. 53°C can be used for other purposes, namely mushroom growing, balneology, swimming pools, soil warming, de-icing, fish farming and for heat pumps.

Petrophysical examination of CO₂-brine-rock interactions-results of the first stage of long-term experiments in the potential Zaosie Anticline reservoir (central Poland) for CO₂ storage.

The objective of the study was determination of experiment-induced alterations and changes in the properties of reservoir rocks and sealing rocks sampled from potential reservoir for CO2. In the experiment, rocks submerged in brine in specially constructed reactors were subjected to CO2 pressure of 6 MPa for 20 months at room temperature. Samples of Lower Jurassic reservoir rocks and sealing rocks (sandstones, claystones, and mudstones) from the Zaosie Anticline (central Poland) were analysed for their petrophysical properties (specific surface area, porosity, pore size and distribution) before and after the experiment. Comparison of the ionic composition the brines before and after the experiment demonstrated an increase in total dissolved solids as well as the concentration of sulphates and calcium ions. This indicates partial dissolution of the rock matrix and the cements. As a result of the reaction, the properties of reservoir rocks did not changed significantly and should not affect the process of CO2 storage. In the case of the sealing rocks, however, the porosity, the framework density, as well as the average capillary and threshold diameter increased. Also, the pore distribution in the pore space changed in favour of larger pores. The reasons for these changes could not be explained by petrographic characteristics and should be thoroughly investigated.

The oil and gas contents of the Lower Jurassic and Achimovka reservoirs of the Nyurol’ka megadepression

The paper describes Lower Jurassic (horizons J16 and J15) and Achimovka (Neocomian clinoforms) reservoirs in the area of the Nyurol’ka megadepression and its framing (42,000km2). The total thicknesses of seven Achimovka sedimentary cycles are mapped. The thermal history of the Togur and Bazhenov parental sediments in the sections of 39 deep wells is reconstructed by paleotemperature modeling. The geotemperature criterion is used to identify paleosources of oil generation, starting from the Jurassic. The distribution of the relative density of the resources of the generated Togur and Bazhenov oils is estimated and shown on sketch maps. The Lower Jurassic reservoir is divided into zones depending on the distribution of the relative density of the Togur oil resources, and the Achimovka reservoir, of the Bazhenov oil resources. The priority oil search zones are proposed.

The influence of the pre-existing topography on the depositionary systems, the development of the Lower Jurassic reservoirs and hydrocarbon accumulation in Central Western Ordos Basin

Pre-existing topography not only influenced the development of the Jurassic depositional systems and the reservoirs, but also controlled the hydrocarbon accumulation in Central Western Ordos Basin. Detailed re-construction of the paleotopography and mapping of the depositional systems and reservoir fairways reveal that the two are closely related. In order to better understand their relationships, detailed environmental facies, channel fairways, source directions of the sediment supplies, burial depth/history, and paleo-bathymetries have been rebuilt and mapped out using well, seismic and log data. The mapping results show that the pre-existing topography and paleogeography prior to the deposition of the Jurassic rocks have a clear influence on (1) a monadnock rising from a third-order valley; (2) sediment microfacies that result in primary distribution of the oil reservoir on the marginal bank region of a watercourse; and (3) factors such as current structural culmination on the top surface. These findings should provide useful guidance for the exploration and development of hydrocarbons from the Lower Jurassic formation in the region.

Salinity variations in North Sea formation waters: implications for large-scale fluid movements

Sodium chloride is the major salt dissolved in formation waters, even at a considerable distance away from any evaporites. Chloride anions are not consumed to any significant extent by diagenetic reactions outside the salt deposits. Chloride ions are therefore preserved in the pore waters, and the distribution of pore water salinities in sedimentary basins may help to constrain pore water flow and the transport of dissolved species of silica and carbonate minerals. In the North Sea Basin and Haltenbanken (mid-Norway), salinity gradients can be inferred from formation water samples. Measurements of pore water salinity from wireline logs are less accurate than formation water samples, but have the advantage that a much larger database can be obtained. Data from 150 wells in the North Sea and Haltenbanken show that the salinities measured from well logs range from 20000 to 300000 ppm. In the southern part of the Norwegian North Sea and Haltenbanken, there is a clear trend towards higher salinities with greater burial depth. There is a pronounced salinity increase in the 500 m of section closest to the evaporites. In the northern North Sea, where underlying evaporites are not known, there is only a slight increase in the measured salinities with depth. There are, however, no measurements of high salinity pore water (>100000 ppm) at depths shallower than 2200 m. This pattern of salinity distribution in the pore water precludes large-scale convection of the pore water during diagenesis. It also indicates limited compaction-driven flow. Log-derived salinity data from the North Sea suggest that the pore waters in Upper Jurassic and Tertiary reservoirs are generally more saline than those of Middle and Lower Jurassic reservoirs at the same depth. The constraints on pore water flow that can be deduced from salinity variations puts severe limitations on the mechanisms of transport of dissolved solids in sedimentary basins and thus also on aspects of diagenetic models.

The caprock of the Snorre Field, Norway: a possible leakage by hydraulic fracturing

The Snorre Field, located on the Tampen Spur in the west of the Viking graben, presents a 300 m oil column in Triassic and Lower Jurassic reservoirs, and it is characterized by high pressures. The caprock is formed by thick shale of Cretaceous and Palaeocene age. Some oil shows are found in the caprock up to a few hundred metres above the reservoir and have the same origin as the oil in the reservoirs. The secondary migration process seems to be linked to high overpressures within the reservoir. The pore pressure at the top of the reservoir reaches about 82% of the total vertical stress, which is close to the minimum horizontal stress according to leak off test data. Hydraulic fracturing probably occurs, increasing the shale permeability so that some oil escapes from the reservoirs. The Snorre Field can be considered as a dynamic trap where a constant pressure regime is maintained by several processes linked to the local conditions and particularly to its structural situation, and where regulation of the system occurs at the top of the reservoirs. The pressure regime and the in situ stress conditions are the key factors in the prospectivity of the traps in this area.

Diagenetic peculiarities of potential Lower Jurassic reservoir sandstones, Troms 1 area, Off Northern Norway, and their tectonic significance

AbstractIn the Troms 1 area, sediments of Early to Middle Jurassic age, ranging from alluvial plain deposits at the base, passing through coastal plain/tidal flat sediments up into high-energy nearshore shallow-marine sands, mark a transgression. The sandstones, classified as mineralogically and texturally mature quartz-arenites, are potential reservoir rocks in the eastern part of the area. The apparent supermaturity, however, is of secondary origin because unstable detrital components were dissolved during diagenesis. The succession of complex diagenetic processes was: (i) mechanical compaction and simultaneous pressure solution, (ii) partial dissolution with corrosion of detrital quartz and dissolution of unstable fragments, (iii) silica cementation, (iv) calcite cementation, (v) partial carbonate dissolution, (vi) kaolinite/Fe-carbonate cementation in the remaining pore space. Porosity and permeability of the sandstones are controlled by the degree of silicification and by dissolution processes. Two dissolution stages led to partial ‘skeletonization’ of the detrital framework and to elimination of unstable detrital grains. The first stage was a basic process leading to corrosion of detrital quartz and creating transitory secondary porosity; the second stage was acidic leading to the present preserved secondary porosity. Diagenetic dissolution channels formed. The degree of diagenetic alteration was much higher than normally observed in sandstones of such burial depth. Hydrothermal solutions rising from deep-seated faults may have led to this unusual alteration and triggered a rift-related type of complex diagenesis.

Organic petrology and source rock potential of sediments in the Eromanga Basin, South Australia

Cuttings and cores from the Poolowanna 1 well, Eromanga Basin, South Australia (in which oil was discovered in Lower Jurassic reservoirs) and the Macumba 1 well (no oil) have been analyzed petrographically to assess the nature of the coals and dispersed organic matter present. The Jurassic and Cretaceous coals have medium to high vitrinite contents, low to relatively high exinite, and medium to low inertinite contents. The dispersed organic matter has comparatively less vitrinite, more exinite and/or more inertinite than the associated coals. The microlithotype compositions of the coals indicate that the original vegetation was largely woody in character and was buried before much oxidation had occurred. The Jurassic sediments contain up to 2% dispersed organic matter by volume, 0–75% of which is exinite, including alginite. Vitrinite reflectances range from 0.5 to 0.7%. Where sufficiently mature, the Jurassic sediments are good potential source rocks for hydrocarbons. Statistical testing of the analytical results for the Jurassic Poolowanna Formation using Kendall's τ as a measure of dependence shows that there is a significant association between the macerals in coal and dispersed organic matter. The ratio of exinite to inertinite in dispersed organic matter is reasonably well predicted by the corresponding ratio in the associated coal.