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The Cenozoic stratigraphy of the Zagros records the ongoing collision between the Arabian and Eurasian Plates and the closure of NeoTethys. A Paleogene NW‐SE trending foreland basin was inherited from a Late Cretaceous precursor. Widespread progradation into the foredeep was a feature of both margins which, allied to ongoing tectonism, had by the late Eocene led to the narrowing and subsequent division of the foredeep into the Lurestan – Khuzestan and Lengeh Troughs, separated by the northward continuation of the rejuvenated Qatar‐Fars Arch. This sub‐division strongly influenced subsequent deposition and the petroleum geology of the area. In addition, the diachronous nature of the Arabian – Eurasian collision led to strong diachroneity in lithostratigraphic units along the length of the Zagros. Hence its petroleum geology is best understood within a regional sequence stratigraphic framework. This study identifies three tectono‐megasequences (TMS 10, TMS 11a, TMS 11b) and multiple depositional sequences. The Cenozoic contains a world class hydrocarbon province with prolific oil reservoirs in the Oligo‐Miocene Asmari Formation sealed by the evaporite‐dominated Gachsaran Formation, mostly contained within giant NW‐SE trending "whaleback" anticlines concentrated in the Dezful Embayment. Reservoirs in the SW are dominantly siliciclastic or comprise mixed siliciclastics and carbonates, whereas those to the east and NE are dominated by fractured carbonates. There remains untested potential in stratigraphic traps, especially in deeperwater sandstone reservoirs deposited along the SW margin of the foredeep. Late Miocene to Pliocene charge to the Asmari reservoirs was mostly from Aptian – Albian Kazhdumi Formation source rocks. In some fields, an additional component was from organic‐rich late Eocene to earliest Oligocene Pabdeh Formation source rocks confined to the narrowing Lurestan – Khuzestan Trough. Where mature, the latter source rock is also a potential unconventional reservoir target, although the prospective area is limited due to recent uplift and erosion. Deeper Jurassic source rocks contributed to the Cheshmeh Khush field in Dezful North. Silurian source rocks charged gas‐bearing structures in the Bandar Abbas region. [ABSTRACT FROM AUTHOR]

In order to make clear the waterflood development potential of the thin conglomerate reservoir named Cardium A in Cardium Formation of Western Canada Basin, the reservoir type was classified according to the core observation, mercury injection and phase permeability experiments. The waterflood development effect was analyzed based on the data from the field water injection test. The results show that the conglomerate reservoir can be classified into type I pure conglomerate and type II impure con-glomerate. The well productivity is controlled by the conglomerate reservoir type and reservoir thickness. The field water injection can hardly form extensive and effective waterflood channels due to the heterogeneity and rapid rock face changes of the conglomerate reservoir. The producer dynamic responses present the type of quick water breakthrough and the type of slight influence. The numerical simulation of waterflood shows that the total oil increase of the gentle water injection scenario is larger than that of the enhanced water injection scenario. The oil increase of water injection scenarios is little compared with that of the scenario without water injection. This research confirms that the waterflood feasibility for Cardium A, the thin conglomerate reservoir, to increase oil production is quite low, which also provides references for water injection development of other similar reservoirs. [ABSTRACT FROM AUTHOR]

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Accurate classification of drainage and extraction reservoir types of coalbed methane wells can lay a foundation for the study of pressure propagation in drainage process. Taking 3# coal seam of Changcun Mine Field as the research object, the main parameters affecting the conductivity of coal reservoir and the recharge capacity of surrounding rock in the process of drainage and extraction are analyzed and selected. The method of obtaining these parameters is proposed, and the critical value is determined. The study area is divided into four types of drainage reservoirs. The water production and gas production of CBM wells in the field verify the reliability of the theory. The significance of classification of drainage and extraction reservoir types was discussed. The results show that the study area can be divided into high-conductivity weak supply reservoir, high-conductivity strong supply reservoir, low-conductivity weak supply reservoir and low-conductivity strong supply reservoir. Among them, the high conductivity and weak recharge reservoir is most conducive to reduce coal reservoir pressure, showing the characteristics of small water production and short casing pressure time. The low conductivity and strong recharge reservoir shows the characteristics of large water production and long casing pressure time.

The relevance of the study is caused by the need to improve the methods of typing reservoir rocks in interpretation of petrophysical data obtained in the laboratory. Typing of the reservoir rocks according to the structure of the pore space is an important step in the interpretation of petrophysical data obtained in the laboratory, but according to established practice, it is carried out only by an expert method, based on the lithological description of core samples and on the dependences of gas permeability on porosity. Purpose: approbation of the accumulated correlation method and individual probabilistic models in combination with facies analysis data for typing terrigenous reservoir rocks according to the structure of the pore space. Object: core samples from five wells of the field named after Sukharev, represented by deposits of the Tula horizon of the Visean stage of the Lower Carboniferous. When conducting research, 165 core samples were used, with a diameter and length of 30 mm. Methods: modern methods for studying porosity-permeability and lithological-petrographic properties, methods of mathematical statistics for the analysis of experimental studies. Results. It is shown that with the help of individual probabilistic models built as a function of the open porosity coefficient and taking into account information about the type of pore structure, lithology and facies, it is possible to characterize changes in dip angles and other effects identified on the graphs of the accumulated correlation in the entire range of calculations. It was established as well that the use of the accumulated correlation method in combination with individual probabilistic models and facies analysis data makes it possible to typing terrigenous reservoir rocks according to the structure of the pore space with a sufficiently high degree of reliability. On the basis of the linear discriminant analysis carried out, the practical problem of separation by reservoir type was solved for the C1tlter object of the field named after Sukharev. The obtained results show that the use of the principle of zoning when identifying reservoirs allows, with a high degree of accuracy, selecting a collection of samples for filtration studies that will most correctly reflect the physical and hydrodynamic picture of the reservoir.

The Feixianguan Formation reservoirs in northeastern Sichuan are mainly a suite of carbonate platform deposits. The reservoir types are diverse with high heterogeneity and complex genetic mechanisms. Pores, vugs and fractures of different genetic mechanisms and scales are often developed in association, and it is difficult to classify reservoir types merely based on static data such as outcrop observation, and cores and logging data. In the study, the reservoirs in the Feixianguan Formation are grouped into five types by combining dynamic and static data, that is, karst breccia-residual vuggy type, solutionenhanced vuggy type, fractured-vuggy type, fractured type and matrix type (non-reservoir). Based on conventional logging data, core data and formation microscanner image (FMI) data of the Qilibei block, northeastern Sichuan Basin, the reservoirs are classified in accordance with fracture-vug matching relationship. Based on the principle of cluster analysis, K-Nearest Neighbor (KNN) classification templates are established, and the applicability of the model is verified by using the reservoir data from wells uninvolved in modeling. Following the analysis of the results of reservoir type discrimination and the production of corresponding reservoir intervals, the contributions of various reservoir types to production are evaluated and the reliability of reservoir type classification is verified. The results show that the solution-enhanced vuggy type is of high-quality sweet spot reservoir in the study area with good physical property and high gas production, followed by the fractured-vuggy type, and the fractured and karst breccia-residual vuggy types are the least promising. [ABSTRACT FROM AUTHOR]

Low porosity and ultra-low permeability reservoirs are developed in Chang 8 Member of Yanchang Formation in southern Ansai area, Ordos Basin. For better understanding the enrichment rules of tight oil reservoirs, Chang 8 tight oil reservoir in Dandong-Hezhuangping, southern Ansai area is comprehensive studied in reservoir characteristics, hydrocarbon enrichment control factors and distribution rules of Chang 8 oil layer group. Furthermore, Chang 8 oil reservoir enrichment modes are constructed by the integration of different data types including large mumbers of cores, thin sections, electron microscopy, physical properties, geochemical and well logging data. The results show that Chang 8 oil formation in the study area belongs to the delta front subfacies, and the lithology is dominated by feldspar sandstone, followed by feldspar lithic sandstone. The sorting property of Chang 82 is better than that of Chang 81 . The reservoir space of Chang 8 reservoir is dominated by intergranular pores, followed by intergranular dissolved pore. There are two main types of pore assemblages: intergranular pores+dissolved pores, and dissolved pores+intergranular pores. The surface porosity of target layer is generally low, with an average value of 3. 3%. Predominant microfacies, such as underwater distributary channel and estuary bar, have relatively high production test oil production, while the test oil production in channel flank is obviously low. The classification and evaluation criteria for Chang 8 oil layer group in study area were formulated. Types Ⅰ and Ⅱ reservoirs are the main reservoir type for hydrocarbon accumulating, while type Ⅲ reservoirs have the maximum are aproportion. The average test oil production of Type Ⅲa and Ⅲb reservoirs 3. 45 and 0. 62 t / d respectively. The structure of study area has no obvious control over the hydrocarbons enrichment, and the distribution of hydrocarbons is mainly controlled by sedimentary facies belt and physical properties of the reservoir. Fractures, high-permeability sand bodies, and high excess pressure provide channels for oil-gas migration and driving forces for hydrocarbon accumulation. [ABSTRACT FROM AUTHOR]

MM Oilfield was located in Bohai Basin, far from the western hydrocarbon source kitchen. The reservoir types in MM Oilfield were mainly lithological-structural reservoirs with small-scale. By studying the structural evolution history of Bohai Basin and fully combining the seismic data, logging data and geology data of MM Oilfield, the hydrocarbon accumulation pattern of MM oilfield was summarized. That was remote hydrocarbon source and fault shielding accumulation. Reservoir abundance of MM Oilfield was affected by the structural location and the remote source of oil and gas. The distribution of the oil reservoir was influenced by the lateral sealing of the fault. The scale of the oil reservoir was controlled by the size of the trap and the physical conditions of the reservoir. C7 layer of the formation was the main carrier for lateral migration. Faults was the channel for vertical migration of oil and gas. The accumulation model of MM oilfield was jointly determined by the matching relationship between the fault distance, the thickness of the caprock and the trap conditions. Three types of oil reservoirs were mainly developed, namely, broken nose reservoir, lithology-fault reservoir and fault-lithology reservoir. [ABSTRACT FROM AUTHOR]

The low-permeability conglomerate reservoir in the Mahu Sag has great resource potential, but its strong heterogeneity and complex microscopic pore structure lead to a high oil-gas decline ratio and low recovery ratio. Clarifying the migration rule of crude oil in microscopic pore throat of different scales is the premise of efficient reservoir development. The low-permeability conglomerate reservoir of the Baikouquan Formation in the Mahu Sag is selected as the research object, and two NMR experimental methods of centrifugal displacement and imbibition replacement are designed to reveal the differences in the migration rule of crude oil in different pore throats. According to the lithology and physical properties, the reservoirs in the study area can be divided into four categories: sandy grain-supported conglomerates, gravelly coarse sandstones, sandy-gravelly matrix-supported conglomerates and argillaceous-supported conglomerates. From type I to type IV, the shale content of the reservoir increases, and the physical property parameters worsen. Centrifugal displacement mainly produces crude oil in large pore throats, while imbibition replacement mainly produces crude oil in small pores. In the process of centrifugal displacement, for type I reservoirs, the crude oil in the pore throats with radii greater than 0.5 μm is mainly displaced, and for the other three types, it is greater than 0.1 μm. The crude oil in the pore throats with radii of 0.02–0.1 μm, which is the main storage space for the remaining oil, is difficult to effectively displace. The crude oil in the pore throats with radii less than 0.02 μm cannot be displaced. The two experimental methods of centrifugation and imbibition correspond to the two development methods of displacement and soaking in field development, respectively. The combination of displacement and soaking can effectively use crude oil in the full-scale pore throat space to greatly improve the recovery of low-permeability conglomerate reservoirs. [ABSTRACT FROM AUTHOR]

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The objective of this research was to prepare reservoir-type nicotine transdermal patches (R-NTPs) using deproteinized natural rubber latex (DNRL) blends as the release control layer (RCL). Hydrophobic DNRL was blended with either hydrophilic hydroxypropylmethylcellulose or polyvinyl alcohol polymer, and either glycerin or dibutylphthalate as plasticizer, and the RCLs were made by plating technique. These RCLs were more hydrophilic compared to the original DNRL film. Nicotine was filled into the reservoir compartment between commercial backing layer and DNRL blended RCL, and was then heat sealed to ensure there was no leak from the R-NTPs. In vitro release and permeation studies of nicotine from the R-NTPs, drug stability, and irritation of the R-NTP devices were evaluated. DNRL blends provided a suitable controlled release and permeation rate for R-NTPs. The release and permeation rates of nicotine from the R-NTPs depended on types of polymer and plasticizer blends that increased the hydrophilicity of DNRL. The addition of an adhesive layer slightly decreased the nicotine release and permeation rates. The release and permeation behaviors of nicotine were described by first and zero order kinetics, respectively. Furthermore, these R-NTPs were stable when stored in a tight container for up to 90 d, and safe to apply to the skin without producing any irritation. [ABSTRACT FROM AUTHOR]

To research the effects of capillary pressure of coalbed methane reservoir on the development of coalbed methane, this paper, based on wettability experiments and field production data, proposes the seal mechanism and types by capillary pressure of coalbed methane formation, and then proposes three types of coalbed methane reservoirs and their typical production curves. The results show that the wettability of coal and rock is water wet and capillary pressure is resistance in the process of coalbed methane production. After the methane is generated, it is adsorbed on the pore surface of coal under the influence of capillary pressure and reservoir hydrostatic pressure. When the gas pressure in the pore is less than the breakthrough pressure, the gas is closed in the pore. According to the difference of gas-sealing type of capillary pressure, coalbed methane reservoir can be divided into three types: capillary pressure trapping type, under-saturated type and saturated type. The capillary pressure of capillary trapping type reservoir is greater than the gas pressure in the pores. Continuous drainage cannot overcome the capillary pressure, and the development effect is the worst. The gas pressure in the pores of the unsaturated reservoir is greater than the capillary pressure, and the static water pressure can be reduced by continuous drainage, making the gas continuously produced, and the development performance is relatively good. The gas pressure in the pores of saturated reservoirs is greater than the gas breakthrough pressure, and methane gas can be produced without drainage and depressurization, so high and stable production can be achieved.

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On the basis of the present situation of oil and gas exploration and geological research of the west slope in the northern Songliao Basin, the factors controlling reservoir formation, oil and gas migration and accumulation, have been re-examined from the aspects of structure, deposition and reservoir formation. The results show that: (1) The west slope is a gentle slope which overlaps to the west, and nose structure is developed near the hydrocarbon generation depression, which is in the dominant direction area of hydrocarbon migration. A series of NE structural belts are developed on the slope and are favorable places for oil and gas accumulation. (2) The west slope can be further divided into the upper slope and the lower slope, and there are many kinds of oil and gas reservoirs, including structural, structural-lithologic and lithologic ones. In the upper slope, the major oil layer is Sartu controlled by structure; in the lower slope, multi-layers are oil-bearing, and the oil reservoirs are mostly composite ones. (3) Faults, unconformity surfaces and continuous sand bodies are the main channels of oil and gas migration; structure, sand body and fault jointly control the oil and gas enrichment in the slope; and the matching relationship between micro-amplitude and sand body, small fault and sand body control the oil and gas accumulation. On the basis of the above research, fine identification and effectiveness evaluation technology of composite trap has been developed through extensive study. Combination traps were identified by multiple technologies, including fault classification, micro-amplitude structure identification, fine sedimentation research, and lithologic trap identification by waveform indication inversion; and then the configuration relationship between fault and sand body, structural amplitude and sand body were analyzed to set up the evaluation criteria of effective traps. According to the criteria, the traps were selected to enhance the exploration success rate. [ABSTRACT FROM AUTHOR]

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Influence of wettability to petrophysical responses in low permeability reservoirs is increasingly evident, but research of nuclear magnetic resonance (NMR) technology on wettability calibration in such reservoirs is very limited even though it has been used promisingly. The challenge is that the empirical interpretation model only applies to simple pore structure. It is urgent to develop a relatively simple, quick, and practicable model for wettability evaluation in low permeable reservoirs. This paper presents an experimental NMR study, integrating with Amott tests, X-ray diffraction, and scanning electron microscope (SEM) measurements, on wettability characterization of five typical core samples from different low-permeability reservoirs. NMR relaxation mechanisms and the effect of the aging were analyzed in detail. The study showed that all the core samples had a shift of T 2 (spin-spin relaxation time) spectra between before and after aging. According to the shift characteristics, the core samples were divided into two types. The first type is that the wettability alteration relied on the aging and it displaced crude oil into original water-wet movable pore spaces to restore reservoir wettability. This type of formation is generated in distant-source reservoirs, which mainly involves fluid transport through buoyancy. Another type is that the wettability alteration was attributed to the natural oil-wet property of the rock matrix. This formation is mainly found in inner-source or near-source reservoirs, which may generate abundant oil-wet materials. Thus, the wettability alteration is the result of hydrocarbon accumulation modes. Based on the observations, a potential method for obtaining the wettability index was proposed. The method uses both the ratio of oil-wetted to water-wetted pore surface areas and diffusion-relaxation diagrams. The estimated results corresponded reasonably to the independent Amott tests. This study demonstrates that NMR relaxation is an effective solution to analyze and quantify wettability in low permeability reservoirs. • The effect of the aging process on wettability alteration of low-permeability rocks was analyzed using NMR T 2 -spectra. • The wettability alteration is associated with hydrocarbon accumulation models. • A new method to obtain the wettability index using D - T 2 diagrams was proposed. [ABSTRACT FROM AUTHOR]

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The section structure was characterized according to the lithological and petrophysical studies of the core from the Bazhenov Formation that has been uncovered in the central part of the Tundrin Depression. The productive oil intervals where the reservoirs of the pore and fissure-pore types occur were identified. [ABSTRACT FROM AUTHOR]

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We discuss the reservoir formation mechanisms in volcanic gas reservoirs within a volcanostratigraphic framework, with a focus on the Huoshiling Formation of the Wangfu fault depression in the Songliao Basin, China. The volcanic sequences are divided, from large to small, into the volcanic cycle (VC), cooling unit set (CUS) and cooling unit (CU). The CU is the basic volcanogenic stratigraphic unit and the CUS is a superposition of cooling units which may be recognized on seismic profiles. The Huoshiling Formation consists of two volcanic cycles and one volcanic-sedimentary cycle. The formation mechanisms of volcanic reservoirs include three processes based on the strata's evolution. First, CUs formed and primary pore spaces developed near cooling surfaces. Second, CUSs and VCs formed and parasyngenetic and secondary pore spaces developed around the crater or caldera, especially near the weathering surface. Lastly, numerous dissolved pores and structural fractures formed during burial and concentrated near the fault belt. CUs, volcanic edifices and structural systems controlled the formation of volcanic reservoirs. The overlapping crater-proximal crater region and the faulted area were centres of reservoir formation. In the Huoshiling Formation, CUS 6-CUS 8 and CUS 13 are the major horizons where volcanic reservoirs developed, forming dissolution reservoirs and structurally fractured reservoirs for natural gas accumulation. [ABSTRACT FROM AUTHOR]

This paper discusses the reservoir space in carbonate rocks in terms of types, combination features, distribution regularity, and controlling factors, based on core observations and tests of the North Truva Oilfield, Caspian Basin. According to the reservoir space combinations, carbonate reservoirs can be divided into four types, i.e., pore, fracture-pore, pore-cavity-fracture, and pore-cavity. Formation and distribution of these reservoirs is strongly controlled by deposition, diagenesis, and tectonism. In evaporated platform and restricted platform facies, the reservoirs are predominately affected by meteoric fresh water leaching in the supergene-para-syngenetic period and by uplifting and erosion in the late stage, making both platform facies contain all the above-mentioned four types of reservoirs, with various pores, such as dissolved cavities and dissolved fractures, or structural fractures occasionally in favorable structural locations. In open platform facies, the reservoirs deposited continuously in deeper water, in an environment of alternative high-energy shoals (where pore-fracture-type reservoirs are dominant) and low-energy shoals (where pore reservoirs are dominant). [ABSTRACT FROM AUTHOR]

Abstract Taking the Ordovician fracture-cavity carbonate reservoir of Tahe oilfield, Tarim Basin as an example, the fracture-cavity reservoir has been classified according to the type and size of reservoir space, and a 3-D geological model of fracture-cavity reservoirs was built according to their types and classes. Based on core, drilling, logging and seismic data, the fracture-cavity reservoir was divided into four types, namely cave, dissolved pore, fracture and Matrix block types, in which the cave was subdivided into two subtypes, large cave and small cave; and the fracture was subdivided into four subtypes, large scale fracture, meso-scale fracture, small scale fracture and microfracture. The large cave model was established using deterministic method via seismic truncation and pattern modification. The small cave model was built using the method of multiple-point geostatistical simulation with large cave model as the training image. The dissolved pore model was built using sequential Gaussian simulation. The large scale fracture model was established using the deterministic method of manual interpretation, meso-scale fracture model was built using deterministic method of ant tracking, the small scale fracture model was built using stochastic object-based modeling. The micro-fracture and Matrix block have no discrete distribution model established because of their poor storage quality. Then the different types of reservoir space models were merged into one model to get the discrete distribution model of typical fracture-cavity unit. The application in Tahe blocks 6 and 7 showed that this classified hierarchical modeling improved the reservoir model precision, guided the water-flooding effectively and advanced the development efficiency. [ABSTRACT FROM AUTHOR]

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Reservoir-type nicotine transdermal patches (NTPs), composed of a concentrated nicotine solution embedded between a backing layer and a controlling layer membrane, were constructed by a heat-sealing technique. The aim of this research was the preparation of a novel controlling layer membrane from deproteinised natural rubber latex (DNRL). The ultimate tensile strength and percentage of elongation at breakage of the DNRL membrane were 0.23 ± 0.04 MPa and 604.46 ± 95.38%, respectively. The DNRL membrane existed as an amorphous phase and was poorly hygroscopic and dense. FT-IR and DSC analysis demonstrated that the membrane consisted almost entirely of isoprene functional groups with a Tg of -64.79 °C. The effects of the DNRL membrane thickness (100-300 µm) and different nicotine concentrations in the reservoir (1.75-4.25 mg/cm²) on the nicotine release rate and nicotine permeation through a pig skin membrane were studied in vitro. The in vitro nicotine release rate and skin permeation rate increased with decreasing membrane thickness and increasing nicotine content in the reservoir. The release and permeation profiles followed first- and zero-order kinetics, respectively. The release and permeation performance was similar to a commercially available Nicotinell TTS-20 patch. The newly developed NTPs were stable under storage in a tightly sealed container at 4 °C or at ambient temperature for up to 3 months. Thus, DNRL is suitable for use as a controlling layer membrane in NTPs in transdermal drug delivery systems. [ABSTRACT FROM AUTHOR]

It is known from macrocomparisons and microresearches of bioherm reservoirs in main sedimentary basins of the South China Sea through deep-water petroleum explorations and by means of 2D/3D seismic data and a whole-coring core from the Xisha (西沙) Islands that there are great differences between deep-sea oil and gas fields in the world and those in the South China Sea, as reservoir systems of the former are mainly clastic rocks, whereas the latter have organic reefs that act as reservoirs of their largest oil and gas fields, which are represented by large Liuhua (流花) 11-1 reef oilfield in the north and super-large L reef gas field in the south of the South China Sea. Therefore, it is of great significance to study deep-water bioherm reservoirs in the South China Sea. Comparisons of organic reefs in the four large islands of the South China Sea give evidences that such reefs in main sedimentary basins came into being during Cenozoic, especially in Neogene, and mainly occur as tower (point) reef, massive reef, platform-edge reef, and patch reef in shape, which show different reservoir physical properties and seismic reflection configurations and make up carbonate rock-bioherm formations in the island reef and sedimentary basin areas. Generally, the south and north parts differ from the east and the west of the South China Sea in geologic conditions, as their corresponding continental shelf/island shelf areas are relatively wide/narrow, large stream current systems are well developed/not so well developed, and terrigenous sediments are relatively sufficient/insufficient. The southeast and south parts of the South China Sea had organic reefs built up earlier than the north and the reef building mainly took place in Neogene; these Neogene organic reefs all belong to plant algal reef rocks. Liuhua oilfield in the Pearl River Mouth basin is found to mainly have red algal bindstone, Malampaya reef in the northern Palawan basin is rich in both red algal bindstone and green algal reef segmented rock, and especially Miocene red algal framestone and green algal segmented rock are discovered in the Xisha Islands. These algal reefs created different sedimentary microfacies as well as various rock structures and types, and through recent researches on the mechanism of dolomitization, freshwater dolomite was discovered and grouped under products from dolomitization in mixed water that was regression reefal dolomite of good reservoir properties. [ABSTRACT FROM AUTHOR]

Abstract: The method development and validation characteristics are described of a simple gas chromatographic–mass spectrometric (GC–MS) analytical procedure to determine residual fentanyl in used Durogesic® reservoir patches and Durogesic® D-Trans® matrix technology based systems to estimate the actual rate of transdermal fentanyl delivered in individual patients. The sample preparation protocol constituting a saline based extraction of sets of new patches of each nominal dose available, resulted in fentanyl extraction recoveries to increase steadily as a function of increasing extraction time. For the reservoir type transdermal therapeutic system (TTS), fentanyl extraction efficiencies at equilibrium (16h) ranged from approximately 60% (100-μg/h TTS) to 95% (25-μg/h TTS), whereas for the matrix type system considerable lower recoveries were demonstrated for the highest nominal dose rates (35%–52%), while reaching 90% for the 25-μg/h system. For the latter type of fentanyl TTS, an optimized methanol based extraction protocol yielded virtually quantitative fentanyl recoveries for each matrix patch nominal dose level at substantially shorter extraction periods (15min). The GC–MS analytical method using selected ion monitoring (SIM) and deuterated fentanyl as internal standard was shown to be adequately selective with regard to the presence of other compounds in the Durogesic® patches. It was further demonstrated that the developed analytical protocols provided highly reproducible and accurate estimates of the initial fentanyl content of each patch type at all available nominal doses, with coefficients of variation and relative errors generally below 10%. These advantageous assay validation characteristics can be further transposed to the application of residual fentanyl level estimates in used patches, provided that with each batch of samples also a set of new TTSs with equal dose is assayed to perfectly mimic extraction phenomena. Finally, the presented GC–MS analytical protocol was successfully applied for the determination of residual fentanyl in a subset of 57 reservoir type patches obtained from four palliative patients. [Copyright &y& Elsevier]