Primary Intergranular Pores Research Articles

Pore formation and occurrence in the organic-rich shales of the Triassic Chang-7 Member, Yanchang Formation, Ordos Basin, China

Shale-reservoir appraisal depends greatly on its pore characteristics (e.g., diameter, geometry, connectivity). Using a new pore-classification scheme based on the matrix type and occurrence state, four types of pores are identified in the organic-rich shales of the Triassic Chang-7 Member: intergranular, intragranular, organic pore, and microfracture. The intergranular pores are subdivided into primary pores between clastic grains, clay-mineral aggregates, and secondary dissolution pores between clastic grains or clay-mineral aggregates based on their origins, respectively. The intragranular pores are subdivided into secondary dissolved pores in feldspars, intra-clay-mineral aggregates and inter-pyrite. Organic pores include primarily microfractures in the organic matter and isolated organic pores. Microfracture is mainly developed along sandy and muddy laminations. Analysis by integration of data from pore imaging, low-temperature liquid nitrogen absorption, relationships between pore geometry and mineral components and between TOC and maturity of organic matter indicates that depositional environment, diagenesis, and thermal evolution of organic matter controlled the formation and preservation of pores. Organic-rich shales deposited in a deep and semi-deep lake environment contains thinly bedded turbidite sandstones, which are characterized by high content of clastic particles and thus favor the development of primary intergranular and intragranular pores, as well as microfractures along sandy laminations. During the early diagenesis process, precipitation of pyrite favors the development of inter-pyrite pores. However, compaction reduced the diameter and bulk pore volume. Organic pore has been greatly reduced under compaction. Dissolution led to formation of both inter and intra-feldspar pores, which has improved reservoir quality to some extent. Organic pore started to develop after shale maturity reaches a threshold (RO = 0.75%). Consequently, low organic pores could have been caused by the combination effect of low maturity and compaction. In addition, hydrocarbon is adsorbed on the surface of the organic matter, which could have caused the expansion of kerogen and then the reduction of organic pore.

Reservoir properties and controlling factors of contact metamorphic zones of the diabase in the northern slope of the Gaoyou Sag, Subei Basin, eastern China

Hydrocarbons reserved in the contact metamorphic zones of magmatic rocks are found in rift basins as a new type of unconventional resources. However, their reservoir characteristics are relatively underexplored. On the basis of core samples, thin sections, and analysis data available, this study investigates the reservoir properties of contact metamorphic zones of the diabase from the northern slope of the Gaoyou Sag, Subei Basin in eastern China. The factors that control the reservoir quality are also investigated. In the studied area, diabase intrusion exerts significant influences on contact sedimentary rocks (including contact mudstones and sandstones) as hydrocarbon reservoirs. After contact metamorphism, the impermeable mudstones are altered into permeable metamudstones, including intermediate-metamorphosed hornfelses and low degree-metamorphosed slates. Various types of reservoir spaces, including structural fractures, hydrothermal microfissures, contraction microfissures, cleavage microfissures, intercrystalline micropores, and dissolved micropores, are created in metamudstones. Among them, numerous fractures and microfissures are the main factors of reservoir quality enhancement. Contact sandstones are altered into metasandstones, whose reservoir space types are similar to those of unaffected sandstones. The reservoir spaces mainly include primary intergranular pores, dissolved intergranular pores, dissolved intragranular pores, moldic pores, ultralarge pores, and dissolved micropores.The formation of reservoir spaces in contact metamudstones is mainly controlled by diabase intrusion, and it is not influenced by burial compaction. The controlling mechanisms of this formation include physical fracturing, hydrothermal activity, dissolution, and cooling contraction. The reservoir quality of contact metasandstones is primarily controlled by lithofacies and diagenesis before intrusion. However, later-stage diabase intrusion also exerts considerable control on reservoir quality by causing physical pressure, dissolution, and cementation. Although dissolution increases porosity moderately, it insufficiently compensates for the porosity reduction caused by physical pressure and cementation. Thus, the reservoir quality of contact metasandstones is generally decreased by diabase intrusion. A comprehensive reservoir model of contact metamorphic rocks is proposed based on the preceding analysis. This model serves to predict the distribution of high-quality reservoir in contact metamorphic rocks in the studied area. It can also be applicable to other formations of similar intrusive background.

Selective dissolution of eodiagenesis cements and its impact on the quality evolution of reservoirs in the Xing’anling Group, Suderte Oil Field, Hailar Basin, China

Reservoirs in the Xing’anling Group in the Suderte Oil Field, Hailar Basin exhibit ultra-low to low permeability and high tuffaceous material content. This study comprehensively analyzed diagenesis and quality evolution of these low-permeability reservoirs using thin sections, SEM samples, rock physical properties, pore water data, as well as geochemical numerical simulations. Calcite and analcite are the two main types of cements precipitated in the eodiagenetic stage at shallow burial depths in the reservoirs. These two cements occupied significant primary intergranular pores and effectively retarded deep burial compaction. Petrography textures suggest selective dissolution of massive analcite and little dissolution of calcite in the mesodiagenetic stage. Chemical calculations utilizing the Geochemist’s Workbench 9.0 indicated that the equilibrium constant of the calcite leaching reaction is significantly smaller than that of the analcite leaching reaction, resulting in extensive dissolution of analcite rather than calcite in the geochemical system with both minerals present. Numerical simulations with constraints of kinetics and pore water chemistry demonstrated that the pore water in the Xing’anling group is saturated with respect to calcite, but undersaturated with analcite, leading to dissolution of large amounts of analcite and no dissolution of calcite. Significant secondary intergranular pores have formed in analcite-cemented reservoirs from selective dissolution of analcite in the mesodiagenetic stage; the analcite dissolution formed preferential flow paths in the reservoirs, which promoted feldspar dissolution; and dissolution of such minerals led to the present reservoirs with medium porosity and low permeability. Calcite-cemented tight reservoirs have not experienced extensive dissolution of cements, so they exhibit ultra-low porosity and permeability.

Gas sorption and flow capabilities of lignite, subbituminous and high-volatile bituminous coals in the Southern Junggar Basin, NW China

Coalbed methane (CBM) resources are abundant in the Southern Junggar Basin in NW China, encompassing a total volume of 3.54 × 1012 m3. However, the gas sorption and flow capabilities of lignite, subbituminous and high-volatile bituminous coals (LSBC, Ro, m <1.0%) in targeted research remain ambiguous. The pore-fractures characteristics of coals (pore size/volume distribution, pore surface areas, fracture geometry, low-field nuclear magnetic resonance (NMR) porosity, permeability, and fractal dimension) are investigated to elaborate the gas adsorption and transport capabilities based on laboratory measurements, including optical microscopy, scanning electron microscopy (SEM), low-temperature (77 K) N2 adsorption/desorption (LTNA), mercury intrusion porosimetry, low-field NMR and a CH4 isotherm adsorption analysis. The SEM images show that the coal pores are primary intergranular pores, residual plant tissue pores and gas outburst pores. Pores that have varying pore widths (3.7–22.5 nm), pore surface areas (0.05–17.23 m2/g) and pore volumes (0.19–18.07 × 10−3 mL·g−1) are divided into five types of seepage pores (pore size >102 nm) and four types of adsorption pores (pore size <102 nm) based on mercury intrusion porosimetry and LTNA. The coal pores consist of transition pores and macropores with diameter of 10–102 nm and > 103 nm, followed by pores with diameter of 102–103 nm and <10 nm. The fractal investigation shows that coals with Langmuir volumes of 15–23 m3/t on a dry ash-free basis are considerably affected by the fractal dimension D1, with a P/Po of 0–0.5. Gases in the coal are concentrated on adsorbing at the pore surface in pores with 2–10 nm and 10–50 nm diameters. The coal permeability is closely related to the coal’s maceral composition (e.g., the ratio of vitrinite to inertinite, V/I) and existing micro-fractures. V/I has a positive influence on the macropores contents and a negative influence on mesopores contents. The NMR results show that the areas of T2 (>2.5 ms) distribution (0.71–14.50 × 103 ms) and movable fluid porosity (1.47–20.34%) significantly affect the coal permeability (0.001–15.584 mD), exhibiting power function relationships. The T2 (0.5–2.5 ms) distribution with slight addition after centrifuging probably owed to the retention water onto internal movable pore surfaces. Therefore, those conclusions can have significant implications for LSBC coalbed methane exploration and development.

Prediction of Diagenetic Facies using Well Logs: Evidences from Upper Triassic Yanchang Formation Chang 8 Sandstones in Jiyuan Region, Ordos Basin, China

The eighth member of Upper Triassic Yanchang Formation (Chang 8) is the major oil reservoir unit in Jiyuan oil field, though with the high potential for oil exploration. The Chang 8 sandstones are characterized with low porosity, low permeability and strong microscopic heterogeneities due to the complex deep-burial diagenetic history. Detailed petrological studies by thin section, X-ray diffraction, scanning electron microscopy, core analysis have been used to investigate the lithogology characteristics, diagenesis, diagenetic minerals and their coupling impacts on reservoir property. The results show that Chang 8 sandstones comprise fine to mediumgrained subarkoses, feldspathic litharenites. The pore systems are dominated by remaining primary intergranular pores, secondary dissolution porosity and micropores. Then, five diagenetic facies were divided in Chang 8 sandstones based on the type and degree of diagenesis, diagenetic minerals assemblages and their coupling effects on the reservoir quality. They consist of grain-coating chlorite weak dissolution facies, unstable component dissolution facies, tight compaction facies, clay minerals filling facies and carbonate cementation facies.The well logging response characteristics of various diagenetic facies are summarized on Gamma Ray (GR), Density Logging (DEN), Acoustic (AC), Compensated Neutron Logging (CNL), and True Formation Resistivity (RT) by translating diagenetic facies to well log responses, the diagenetic facies were defined by a set of log responses, and porosity, permeability ranges for each diagenetic facies were determined from core analyses. Well log data of Luo 13 and Chi 212 are processed to evaluate the accuracy of the predictive model. The diagenetic facies are predicted on the vertical profile based on the generated model. Predicted distribution of diagenetic facies precisely coincide with the microscopic observations, and diagenetic facies in Chang 8 sandstones are generally locally distributed. Tight compaction and carbonate cementation diagenetic facies mainly correspond to the non-reservoir and dry layers of Chang 8 sandstones, layers with higher oil potentials are mainly developed in the grain-coating chlorite weak dissolution and unstable component dissolution diagenetic facies. By translating diagenetic facies to well log responses, diagenetic facies and reservoir properties of intervals that lack core control could be predicted with the same or similar log responses.

Hydrocarbon storage space within lacustrine gas shale of the Triassic Yanchang Formation, Ordos Basin, China

The Triassic Yanchang Formation lacustrine shale is a source of conventional oil accumulation in the Ordos Basin, China. The Yanchang Formation, a hybrid system of organic-rich shale, interbedded silty shale, and siltstone, is believed to be a potential unconventional oil and gas play. Our crossdisciplinary investigation of the storage space included the outcrop description, core observation, thin sections, and scanning electron microscope pore imaging. We evaluated the results from these techniques to reveal that the storage space within the Yanchang Formation shales included primary intergranular pores, secondary generated pores, tectonic fractures, and bedding-parallel fractures. We conducted adsorption experiments, combined with burial and thermal history, in which the primary migration process can be divided into three stages. In the Early Jurassic, organic matter did not reach the oil generation threshold. From the Late Jurassic to the Early Cretaceous, organic matter entered the oil generation window, and gas was generated and stored as adsorbed gas, dissolved gas, and free gas. From the Middle to Late Cretaceous, the storage of shale gas was dynamically transformed by tectonic uplift. Variations in chemical and carbon isotopic compositions from canister-core desorption were directly related to the gas supply in shales. An abrupt decrease in gas dryness and positive [Formula: see text] values indicated the depletion of gas supply drainage. Our ultimate recovery factor reached 70%.

Movable Fluid Saturation of Low-Permeability and Tight Sandstone Oil Reservoir: Taking Chang 6 Reservoir in Banqiao-Heshui Area as an Example

By analyzing the thin sections, physical property and nuclear magnetic resonance, the petrology character, pore types and the movable fluid saturation distribution characteristics of Chang 6 reservoir in Banqiao-Heshui area were tested. The research shows that the main lithology of Chang 6 reservoir in study area is lithic arkose. The pore space of reservoir mainly include the solution pores and the primary residual intergranular pores. Fine pore-tiny throat is the main pore configuration. The physical properties of Chang 6 reservoir in Banqiao-Heshui area are weak and it belongs to low-permeability and porosity oil reservoir. There are two models of T2 spectrum, including bimodal and unimodal modes. Movable fluid saturation and fluid porosity varies a lot, the reservoir can be classified as many types by movable fluid saturation and for each of them, its movable fluid saturation differs obviously.

Characteristics and origin of abnormally high porosity zones in buried Paleogene clastic reservoirs in the Shengtuo area, Dongying Sag, East China

There are three abnormally high porosity zones developed in buried Paleogene nearshore subaqueous fan and sublacustrine fan clastic reservoirs at 2,800–3,200 m, 3,250–3,700 m and 3,900–4,400 m, respectively, within the Shengtuo area of the Dongying Sag. Here the porosity of reservoirs buried deeper than 4,000 m can still be greater than 20%. Investigation of these three abnormally high porosity (AHP) zones in the 3rd to 4th member of the Paleogene Shahejie Formation in the Shengtuo area was carried out with utilization of core observation, thin section identification, SEM observation, image analysis, core physical property testing and other technical methods. The results show that, the AHP zones in 2,800–3,200 m and 3,250–3,700 m are visible pores primary AHP zones dominated by significant primary intergranular pores (more than 50% of the total porosity), while secondary pores and micropores in authigenic clays may develop in some reservoirs. AHP reservoirs in the AHP zone of 3,900–4,400 m are dominated by micropores in matrix, visible pores are mainly grain dissolution pores but with low absolute content (< 1%), so this zone belongs to the micropores primary AHP zone. The genesis of the three AHP zones was studied to distinguish between porosity enhancement and porosity preservation. Our research shows that, in deeply buried clastic reservoirs in the Shengtuo area, mineral dissolution occurred in a relatively closed diagenetic system with high temperature and high salinity. Reservoir rocks underwent extensive feldspar dissolution, while detrital carbonate grains and carbonate cements show no evidence of extensive dissolution. Although significant feldspar dissolution pores developed, feldspar dissolution enhanced porosity only a little due to the precipitation of almost isovolumetric dissolution products in the nearby primary intergranular pores in forms of authigenic clays and quartz cements. Net enhanced porosity originating from feldspar dissolution is generally less than 0.25%. Thus, the subsurface dissolution has little impact on the mid-deep buried high porosity reservoirs. Reservoirs in braided channels of middle fans in sublacustrine fans and reservoirs in the middle-front of fan bodies of nearshore subaqueous fans provide the basis for the development of AHP zones. The shallow development of fluid overpressure and early hydrocarbon emplacement have effectively retarded compaction and carbonate cementation, so that the high porosity in the superficial layers is preserved in the mid-deep layers. These are the main controlling factors in the development of AHP zones.

Characteristics and genesis of the Feixianguan Formation oolitic shoal reservoir, Puguang gas field, Sichuan Basin, China

The Lower Triassic Feixianguan Formation at the well-known Puguang gasfield in the northeastern Sichuan Basin of southwest China produces a representative oolitic reservoir, which has been the biggest marine-sourced gasfield so far in China (discovered in 2003 with proven gas reserves greater than 350×108 m3). This study combines core, thin section, and scanning electron microscopy observations, and geochemical analysis (C, O, and Sr isotopes) in order to investigate the basic characteristics and formation mechanisms of the reservoir. Observations indicate that platform margin oolitic dolomites are the most important reservoir rocks. Porosity is dominated by intergranular and intragranular solution, and moldic pore. The dolomites are characterized by medium porosity and permeability, averaging at approximately 9% and 29.7 mD, respectively. 87Sr/86Sr (0.707536–0.707934) and δ13CPDB (1.8‰–3.5‰) isotopic values indicate that the dolomitization fluid is predominantly concentrated seawater by evaporation, and the main mechanism for the oolitic dolomite formation is seepage reflux at an early stage of eodiagenesis. Both sedimentation and diagenesis (e.g., dolomitization and dissolution) have led to the formation of high-quality rocks to different degrees. Dolomite formation may have little contribution, karst may have had both positive and negative influences, and burial dissolution-TSR (thermochemical sulfate reduction) may not impact widely. The preservation of primary intergranular pores and dissolution by meteoric or mixed waters at the early stage of eogenesis are the main influences. This study may assist oil and gas exploration activities in the Puguang area and in other areas with dolomitic reservoirs.

Geological features of Mesozoic lacustrine shale gas in south of Ordos Basin, NW China

Abstract The geological characteristics of Mesozoic lacustrine shale gas are summarized from the following aspects: distribution of shale, geochemistry of shale gas, characteristics of shale reservoir, enrichment form of shale gas etc, based on the lacustrine shale gas exploration research and practices in southeast of the Ordos Basin. The geochemical characteristics and thermal evolution degree of shale gas source rocks are controlled by the evolution of lacustrine basin in the early and middle stages of late Triassic Period, and the main hydrocarbon-generation rocks are shale from the Chang 7 and Chang 9 members of the Triassic Yanchang Formation, with high abundance of organic matter and in the mature to wet gas stage. The most mineral compositions are quartz, feldspar and clay mineral in shale gas reservoir, and the primary intergranular pores and secondary dissolution pores are the main pore types. The shale gas in the study area is oil-type gas, dominantly wet gas. The shale gas occurs mostly in the adsorption state, the free state and the dissolved state. Estimated by the volumetric method, the total shale gas resources of Chang 7 is 5 318.27×108 m3, and the total shale gas resources of Chang 9 is 3 067.29×108 m3.

Reservoir characteristics and main controlling factors of oil sand in Houba area, northwestern Sichuan Basin, China

Houba oil sand in frontier Longmenshan Mountain is one of the most typically important unconventional resources. The basic reservoir characteristics of oil sand and the main factors affecting reservoir quality were examined in this article based on porosity, permeability, and mercury porosimetry measurements; thin section analyses; SEM observation; and X-ray diffraction analysis. This study shows that the oil-bearing sandstone reservoir is mainly medium−coarse-grained sublitharenite and litharenite. The main pore type is intergranular pores, including residual primary intergranular pores, dissolved intergranular pores, and dissolved intragranular pores; fractures are common in this study area. The quality of sandstone reservoir is of high porosity and high permeability with a high oil saturation of 89.84 %. It is indicated that the main controlling factors of the reservoir in the study area include deposition, diagenesis, and tectonism. Deposition laid a foundation to porosity evolution, and channel sand is the most favorable depositional facies for the reservoir. Diagenetic alterations are the keys to reservoir evolution; dissolution and chlorite coatings cementation play an effective role in the generation and preservation of pores. Compaction, carbonate cementation, and quartz overgrowth cause many damages to the reservoir porosity. Fractures caused by structural breakages can improve the reservoir permeability and they also can provide fluid migration pathways to the late corrosion, which formed a lot of corroded fissures as reservoir and percolation spaces.

日本海東縁海底下に分布する砂層の孔隙特性と年代 : MD179航海

In 2010 the MD179 project was undertaken aiming at recovery of deep seated gas hydrate, methane induced carbonate, and deep sediments older than 300 ka. Sediment samples were obtained in the Umitaka Spur, Joetsu Channel, Toyama Trough, Japan Basin, Nishi Tsugaru and Okushiri Ridge areas. Small amounts of sandy sediment have been retrieved as thin intercalations in Pleistocene and Holocene muddy layers, where trace fossils and strong bioturbations are commonly observed.Those sandy sediments consist of very fine- to fine-grained sand grains, and are sometimes tuffaceous. Pore-size distribution measurements and thin-section observations of these sands were undertaken, which indicated that porosities of muddy sediments are around 50 % but those of arenites range from 42 to 52%. Mean pore sizes and permeabilities of those arenites are larger than those of mudstones. While the presence of gas hydrate in intergranular pores of sands has not been confirmed, the soupy occurrence in recovered sediments may strongly indicate the presence of hydrate filling the intergranular pore system of sands. Such arenites have been recognized till now in the Mallik, NW Territory Canada, as well as in the Nankai Trough areas, which are expected common even in the subsurface sandy sediments at the eastern margin of Japan Sea. Concentration of gas hydrate may need primary intergranular pores large enough for gas hydrate to occur within host sediments likely deposited in the sedimentary environment such as deep sea channels. Small amounts of sandy sediment were retrieved as thin intercalations in Pleistocene silty layers, because supplying sediments may not be abundant due to sea level fluctuation during Pleistocene ice age. As time of deposition of coarse-grained sediments can be recognized by the thermoluminescence (TL) dating method, sandy sediments are usually tuffaceous and contain a small amount of quartz grains, and TL dating has been completed only for seven samples, which indicate 48 to 980 ka in age. This study was performed as a part of the MH21 Research Consortium.

Reservoir Characteristics and its Main Controlling Factors of the Siegenian Formation of Devonian in X Block, Algeria

The Siegenian Formation reservoir is a tight sandstone reservoir with relatively poor porosity and low permeability. In this paper, the reservoir characteristics and its main controlling factors of the Siegenian Formation in X block have been studied based on cores, well-logs, and formation test data including the thin sections and cast thin sections, observation of scanning electron microscope, pressured-mercury testing and X-ray diffraction analysis of clay minerals. During deposition of the Siegenian Formation, the depositional environment was predominated by lower shoreface, middle shoreface and offshore. The fine sandstone and siltstone formed in the middle shoreface environment is the main reservoir of the Siegenian Formation in X block. Six pore types including primary intergranular pores, intragranular dissolved pores, intergranular dissolved pores, moldic pores, cement dissolved pores and microfractures are identified in the Siegenian Formation reservoir. The quartz intergranular dissolved pores and the quartz overgrowth cement dissolved pores are found for the first time in this area. The secondary dissolution pore is the main pore type in X block. The pore throat has a small radius, poor connectivity and the pore structure parameters are poor. Combined with the petrophysical property and capillary pressure curves, the reservoir of the research area is divided into three types: mesopore-ultra low permeability reservoir (type I), low-middle porosityultra low permeability reservoir (type II) and low porosity-ultra low permeability reservoir (type III). Type II is the main reservoir in this area. The sedimentary environment, tectonism and diagenesis are the main controlling factors. Diagenesis is the most important controlling factor in this area. Diagenesis may play a catalytic role or may play a negative role on damage in the reservoir pore evolution. The compaction, pressure solution, cementation, replacement and cementation are the main diagenesis types which reduce the pore volume during the reservoir pore evolution. The dissolution including acidic dissolution and alkaline dissolution are the main diagenesis types which produce extra pore volume during the reservoir pore evolution. This study of the reservoir will guide the future exploration of this area.

Reservoir Characteristics and Favorable Area Prediction of Devonian Kizirtag Formation in Bashituo Area, Tarim Basin

Tarim Basin is the largest petroleum potential in the west of China. As a co-prospecting project, some wells of the Devonian Kizirtage formation in Bashituo area have gained encouraging industrial oil flow. The basic characteristics of the reservoir beds are described in detail in this paper by collecting and processing plenty of existing data. The results of petrologic analysis show that the pore types of the Kizirtag formation are mainly residual primary intergranular pores and intergranular dissolution pores, and the lithology is mainly fine grain quartz sandstone. Based on the analyses of reservoir physical properties, the reservoir porosities of Kizirtag formation in study area mainly range from 2% to 8% with an average of 6.14%, and the reservoir has a lower permeability with a range less than 1 × 10−3μm2 with average of 1.86 × 10−3μm2. The core analyses indicate there is a distinct positive correlation between porosity and permeability, and members 4 to 6 are the main reservoir section. The inversion prediction of reservoir physical properties shows that the distributions of favorable zones are similar to the distribution of sand body and sedimentary facies. The favorable zones of reservoir physical property of member 6 in Kizirtag formation range from well BK8 to well BK2 and the northern area. Well Q003 and the south eastern area have the poorest physical properties. The favorable zones of reservoir physical property of member 5 distribute in the northwestern and south central area of the study area. The favorable zones of reservoir physical property of member 4 distribute in well BK8 area. Through the statistics analysis, it was found that the reservoir physical properties in study area were controlled by primary sedimentary environment and diagenetic transformation and was especially influenced by the carbonate cementation. There is an obvious negative correlation between the carbonate content and porosity and permeability. Based on the tectonic characteristics, reservoir distributions and hydrocarbon test results of the study area, the favorable areas of main productive layers in the Kizirtag formation were divided to I type, II type and III type. The I type area with the optimum forming conditions is the most favorable part for oil and gas accumulation. So it is suitable to immediately implement drilling, which poses a low drilling risk. The I type areas of the sixth member in the Kizirtag formation is mainly distributed in the intensive areas of exploration wells. The I type areas of the fifth member are mainly concentrated in east in the study area, and the distribution of I type areas in the fourth member of Kizirtag formation is similar to that of the sixth member, but the range is reduced. The distribution of the fourth member is concentrated in the Q002 well to BK9 well range. The II type area has better reservoir forming conditions, and belongs to a more favorable area for hydrocarbon accumulation. However, there are also some exploration risks. In II type areas it is appropriate to carry out drilling to explore objects combined with other hydrocarbon bearing series. The II type areas of the sixth member in Kizirtag formation is concentrated in the east of the study area,; that of the fifth member basically covers the scope of the two traps that are interpreted in this study. In addition, there are larger distribution areas in the east of the study area, and a small distribution area in the south western part of the study area. The II type area distribution of the fourth member in the Kizirtag formation is diminshed, and is mainly distributed in the north of the study area. The reservoir formation conditions of III type zone are poor, so there is no drilling under its current condition. It was considered that this research can provide a new method for future exploration of this area.

Formation Mechanisms of Paleogene Igneous Rock Plays in Huimin Sag, Eastern China

In order to understand the impact of volcanism and intrusion on the source rocks, how the pores and fissures formed and how the hydrocarbon was trapped, this study focuses on the formation mechanisms of the igneous rock plays in the Huimin Sag based on geochemical and lithological analyses and typical anatomy. The results indicate that volcanism enhanced the formation of Es3 source rocks with high TOC (3.41–5.12%) in the distribution areas of igneous rocks. Volcanism caused an abnormal heat field and accelerated the maturation of hydrocarbon source rocks, leading to a higher heat gradient (3.4–4.4 °C /100 m), increase of HC and chloroform bitumen “A” contents, earlier hydrocarbon generation threshold and higher biomarker maturity closer to the igneous rocks. The primary fractures, vesicular structures, inter-breccia pores, intergranular pores, intercrystal and intracrystal pores are primarily-formed. The structural fractures and corrosion space are secondarily formed. Rising fluid pressure associated with volcanism accelerated the hydrocarbons expulsion. Igneous body can act as a migration pathway or a seal constrained by its physical property. Volcanism in the Huimin Sag produces diaper arch trap, overlap trap in volcano slope and drape anticline trap on the volcanic cone. Five models for igneous rocks plays in the Huimin Sag, such as volcaniclastic play with outside source rocks, diabase plays with interior and exterior source rocks, basalt plays with exterior and mixed source rocks are proposed.

Jia-2 Member doloarenite reservoir in the Moxi gas field, middle Sichuan Basin

Abstract Based on analysis on the macroscopic and microcosmic features of doloarenite in C layer, sub-member 2, Jia-2 Member of the Jialingjiang Formation in the Moxi gas field, the genetic mechanism of favorable reservoirs in beach facies carbonate rock is established. Primary inter-granular pores are the main reservoir spaces in the beach facies carbonates, and have the following key characteristics and identification signs: reservoir development was strictly controlled by the depositional microfacies; main pore types are residual inter-granular pores and dissolved-enlarged residual inter-granular pores; only submarine cement existed in grain contacts; initial compaction led to grains under framework support in line-concave-convex contact; and the burial cement in some separate inter-granular pores being not dissolved. The conservation mechanism of primary inter-granular pores is described as follows: after submarine cementation, the initial compaction created grains with early rim cement under framework support and the throats decreased accordingly; the compaction fluid cementation compressed the beach body's margin, the limited shallow burial cementation in inter-granular pores plugged the throats, and the cementation terminated after the diagenetic fluid reached dissolution-cementation balance. Late burial-dissolution adjusted and optimized early porous strata, which played a secondary role in increasing the reservoir space of each permeable reservoir bodies and did not change the spatiotemporal distribution of this kind of reservoir.

Primary intergranular pores in oolitic shoal reservoir of lower triassic feixianguan formation, Sichuan Basin, Southwest China: Fundamental for reservoir formation and retention diagenesis

The Lower Triassic Feixianguan (飞仙关) Formation oolitic shoal reservoir in the Sichuan (四川) basin (Southwest China) is currently an exploration and research highlight in China. The reservoir is widely believed to be formed mainly by burial dissolution and/or dolomitization on the basis of primary intergranular pores. In this study, through a comprehensive geological study on the whole basin, the dissolution and dolomitization are suggested not to be the fundamental factor of reservoir formation and there thus may be a possible new fundamental mechanism—the preservation of primary intergranular pores, i.e., the retention diagenesis. Based on this, a complex and multi-stage reservoir evolution and formation model is proposed. In the model, the depositional environment is the basis of reservoir initial formation. Subsequently, early compaction and shallow burial cementation result in the primary reservoir differentiation. Then, multi-stage burial dissolution alters and adjusts the reservoir. Because the last stage gaseous hydrocarbons have little diagenetic impact, the reservoir is formed finally. Therefore, this study presents a possible new fundamental mechanism and evolution model for the reservoir formation. The results can be applied in the regional reservoir predication and shaping exploration strategies, and provide reference for the study of shoal reservoirs in other areas.

Mechanisms of weathering of meteorites recovered from hot and cold deserts and the formation of phyllosilicates

Petrographic, mineralogical and chemical analysis of naturally weathered equilibrated ordinary chondrites collected from ‘ hot’ deserts and Antarctica has revealed striking similarities and also pronounced differences in weathering between the two environments. Terrestrial weathering in all meteorites studied is dominated by oxidation and hydration of Fe,Ni metal, producing Fe-oxides and oxyhydroxides that have partially replaced the metal grains and have also occluded primary intergranular pores to form veins. Troilite weathers readily in ‘ hot’ desert environments but undergoes very little alteration under Antarctic conditions. Most of the primary porosity of ordinary chondrites has been occluded by the time that ∼ 15 to 25% of the initial Fe 0 and Fe 2+ has been oxidised to Fe 3+ in both environments. Results from modelling the volume changes upon alteration of primary minerals to a range of weathering products demonstrates that the primary porosity of most meteorites is sufficient to accommodate weathering products. Dilation of primary pores and brecciation, which has been observed in parts of some meteorites, will only occur if the meteorite is especially metal-rich, or has a low primary porosity. These weathering products are absent from recent falls but have formed in a fall after ∼ 100 yr of museum storage. Cl-bearing akaganéite and hibbingite are common weathering products in Antarctic finds but occur in abundance in only one ‘ hot’ desert meteorite, Daraj 014. The majority of Fe-rich weathering products in meteorites from both environments contain low, but variable concentrations of Si, Mg and Ca. In most meteorites a proportion of these elements are inferred to be present as a very finely crystalline mineral with a ∼ 1.0-nm lattice fringe spacing; where seen within intragranular fractures this mineral has a topotactic relationship with olivine and orthopyroxene. In the heavily-weathered Antarctic finds ALHA 78045 and 77002, Si is concentrated in cronstedtite, a Fe-rich phyllosilicate. An unidentified hydrous Si-Fe-Ni-Mg mineral or gel has also partially replaced taenite in ALHA 78045. In addition to Fe-rich weathering products, ‘ hot’ desert meteorites contain sulphates, Ca-carbonate and silica, whereas such minerals are largely absent from Antarctic finds. The abundance of silicate weathering products in Antarctic meteorites is unexpected and indicates that olivine and pyroxene undergo significant chemical weathering in these environments. As preterrestrial cronstedtite is abundant in CM2 carbonaceous chondrites, the Antarctic environment may be a powerful analog for aqueous alteration in the asteroidal parent bodies of primitive meteorites.

Petroleum geology and geochemistry of the Council Run gas field, north central Pennsylvania

The Council Run field of north central Pennsylvania is one of the most productive natural gas fields in the central Appalachian basin. The field is enigmatic because of its position near the eastern edge of the Appalachian Plateau, where strata with reservoir potential elsewhere have low porosities and permeabilities or are poorly sealed. Council Run has four principal reservoir sandstones. The lower three occur in a distinct fourth-order type 1 stratigraphic sequence. The stacking pattern of sandstones in this sequence defines lowstand, transgressive, and highstand systems tracts. Core, well-log, and map interpretations reveal that the lowest interval consists of multiple coarsening-upward parasequences deposited in deltaic and nearshore environments of the lowstand systems tract during a forced regression. Most of these sandstones are lithic, and some are highly feldspathic. Productive sandstones display hybrid void textures that consist of reduced primary intergranular pores preserved, in part, by relatively early petroleum emplacement and secondary oversized fabric-selective pores. The generative potential of the organic matter in the potential source rocks is exhausted, but geochemical and petrographic evidences indicate that these black shales originally contained oil-prone kerogens and generated liquid hydrocarbons. Stable isotope geochemistry suggests that gases were generated by primary cracking of kerogens and/or by secondary cracking of oil between 320 and 290 Ma. Dispersive migration paths were both lateral and vertical because of compression associated with Alleghanian orogenesis. Most of the oil in the Devonian section was cracked to gas during deeper burial between 270 and 240 Ma.

Reservoir properties of Arab carbonates, Al Rayyan Field, offshore Qatar

Abstract Oil is present in the Upper Jurassic Arab A and Arab C carbonates of the Al Rayyan Field. The Arab A consists of porous limestone with thin units of tight dolomite at the top and bottom. Two reservoir intervals can be distinguished, separated by a slightly less permeable unit. The upper reservoir consists of stromatolites and cross-bedded peloidal-grainstones, whereas the lower reservoir consists predominantly of ooliticgrainstones. The less permeable unit comprises moderately cemented, cross-bedded peloidal-grainstones. Higher porosity and permeability generally occurs in the coarser grained, cross-bedded grainstones, where pores are mostly primary and intergranular; lower permeability is characteristic of grainstones with moderately developed early cement. Porosity is enhanced at some levels by the presence of leached intragranular pores, but these have little effect on permeability. The Arab C is strongly stratified and completely dolomitized. Three reservoir intervals can be recognized, separated by less permeable layers of poorer quality rock. The upper reservoir consists of partially leached and moderately cemented, cross-bedded bioclastic-peloidal-grainstones. Porosity is high because of the presence of leached intragranular pores in addition to primary intergranular pores but permeability is relatively low because of the presence of early cement. The main reservoir comprises loosely compacted and lightly cemented, cross-bedded peloidal-grainstones. Porosity is lower than that in the upper reservoir because leached intragranular pores are generally absent, but permeability is higher because cementation is relatively light. The lower reservoir is made up of peloidal-grainstones and coarse-grained bioclastic-grainstones. The upper and main reservoirs are separated by a thick interval of relatively tight, thinly bedded, strongly cemented peloidal-grainstones, whereas the main and lower reservoirs are separated only by a thin bed of tight, nodular anhydrite. The pore types and cements observed in the Arab C are similar to those of the Arab A, but dolomitization has resulted in an enhancement of permeability and capillary pressure properties compared to those of the Arab A. Thus, the overall water saturation of the Arab C is lower than that of the Arab A, and the displacement pressures and irreducible water saturations are also significantly lower than those of Arab A carbonates.