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1.
An integrated petrographical and petrophysical study was carried out on a set of 35 outcrop chalk samples, covering a wide range of lithologies and textures. In this study various chalk rock-types have been characterized, in terms of microtextures and porous network, by integrating both geological, sediment-petrological and petrophysical data, including porosity, permeability, low-field NMR (Nuclear Magnetic Resonance), MICP and specific surface area (BET) measurements. The data allow an in depth understanding of the NMR signal of chalks, with a focus on tight chalks, including all low reservoir quality chalks independently of their sedimentological and/or diagenetic history. The study aims to develop an NMR-based approach to characterize a broad range of chalk samples. The provided laboratory low-field NMR chalk classification can be used as a guide to interpret NMR logging data.Based on the petrographical and petrophysical analysis, 6 groups of samples were identified, each of them characterized by a unique NMR signature: (1) micritic chalks, (2) grainy chalks, (3) cemented chalks, (4) marl-seam chalks, (5) argillaceous chalks and (6) silicified chalk. NMR T2 distributions were linked to pore body size and T2 logarithmic (T2lm) was calculated. It is apparent that tight chalks, whether their characteristics are sedimentological or diagenetic, yield smaller pore body sizes (T2lm < 20 ms), as well as narrower pore throats (average radius < 150 nm) and lower permeability values (typically below 0.2 mD). Grainy chalks possess T2 distributions reflecting larger pore sizes (T2lm > 60 ms) and pore throats (average radius > 290 nm) and higher permeabilities (up to 13 mD). The marl-seam chalk samples yield bimodal T2 distributions, with a first peak related to the micritic matrix pores and a second peak related to intraparticle pores within fossils. For all samples, permeability was inferred from NMR spectra using SDR (Schlumberger Doll Research) model. 相似文献
2.
Understanding the pore structure characteristics of tight gas sandstones is the primary purpose of reservoir evaluation and efforts to characterize tight gas transport and storage mechanisms and their controls. Due to the various pore types and multi-scale pore sizes in tight reservoirs, it is essential to combine several techniques to characterize pore structure. Scanning electron microscopy (SEM), nitrogen gas adsorption (N2GA), mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) were conducted on tight sandstones from the Lower Cretaceous Shahezi Formation in the northern Songliao Basin to investigate pore structure characteristics systematically (e.g., type and size distribution of pores) and to establish how significant porosity and permeability are for different pore types. The studied tight sandstones are composed of intergranular pores, dissolution pores and intercrystalline pores. The integration of N2GA and NMR can be used as an efficient method to uncover full pore size distribution (PSD) of tight sandstones, with pore sizes ranging from 2 nm to dozens of microns. The full PSDs indicate that the pore sizes of tight sandstones are primarily distributed within 1.0 μm. With an increase in porosity and permeability, pores with larger sizes contribute more to porosity. Intercrystalline pores and intergranular/dissolution pores can be clearly distinguished on the basis of mercury intrusion and surface fractal. The relative contribution of intercrystalline pores to porosity ranges from 58.43% to 91.74% with an average of 79.74%. The intercrystalline pores are the primary contributor to pore space, whereas intergranular/dissolution pores make a considerably greater contribution to permeability. A specific quantity of intergranular/dissolution pores is the key to producing high porosity and permeability in tight sandstone reservoirs. The new two permeability estimation models show an applicable estimation of permeability with R2 values of 0.955 and 0.962 for models using Dmax (pore diameter corresponding to displacement pressure) and Df (pore diameter at inflection point), respectively. These results indicate that both Dmax and Df are key factors in determining permeability. 相似文献
3.
To better understand reservoir quality and to produce accurate petrophysical interpretations, it is necessary to understand complex and heterogeneous pore throat structures in tight sands and to develop a technique to reveal the full range of pore and throat distributions. In this study, in order to characterize the features and evolutions of pore throat structures, nine samples from the Lower Cretaceous tight gas sandstone in the Songliao Basin of China are measured by nuclear magnetic resonance (NMR), rate-controlled porosimetry (RCP) and scanning electron microscopy (SEM). Throats with bifractal structures are found in these tight sands and can be divided into a backbone formation (BF) region and a percolation region using RCP data. Because (i) throats in the percolation region record treelike pore structures and are predominant in small pore spaces and (ii) a good correlation exists between NMR-derived T2 relaxation times and the RCP-derived radius of throats, the throat distribution obtained via RCP can be used to calibrate the NMR PSD and then to partition the PSD into distributions of pore bodies and throats. These data indicate that (i) throats are more common than pore bodies in pore spaces of tight sands with lower permeability, (ii) pore bodies are connected to throats from both the BF and percolation regions, in which the fluid mobility in pore bodies is mainly controlled by the pore to throat ratio (PTR), which is related to the intersection throat of these two regions, and (iii) compaction, dissolution, clay cementation and sediment properties (e.g., rock compositions) have different impacts on the evolutions of pore bodies and throats, in which larger PTR values in tight sands are mainly produced by compaction and pore-bridging clay cementation, and lower contents of pore bodies are commonly related to abundant plastic compositions and pore-bridging clay cementation. 相似文献
4.
Shixi Bulge of the central Junggar Basin in western China is a unique region that provides insight into the geological and geochemical characteristics of large-scale petroleum reservoirs in volcanic rocks of the western Central Asian Orogenic Belt. Carboniferous volcanic rocks in the Shixi Bulge mainly consist of striped lava and agglomerate, as well as breccia lava and tight tuff. Volcanic rocks differ in porosity and permeability. Striped lava exhibits the highest porosity (average: 14.2%) but the lowest permeability (average: 0.67 × 10−15 m) among the rock types. Primary gas pores are widely developed and mostly filled. Secondary dissolution pores and fractures are two major reservoir storage spaces. Capillary pressure curves suggest the existence of four pore structure types of reservoir rocks. Several factors, namely, lithology, pore structure, and various diagenesis, govern the physical properties of volcanic rocks. The oil is characterized by a high concentration of tricyclic terpane, a terpane distribution of C23 < C21 > C20, and sterane distributions of C27 < C28 < C29 and C27 > C28 < C29. Oil and gas geochemistry revealed that the oil is a mixture derived primarily from P2w source rock and secondarily from P1j source rock in the sag west of Pen-1 Well. The gases are likely gas mixtures of humic and sapropelic organic origins, with the sapropelic gas type dominant in the mixture. The gas mixture is most likely cracked from kerogen rather than oils. The Carboniferous volcanic reservoirs in Shixi Bulge share some unique characteristics that may provide useful insights into the various roles of different volcanic reservoir types in old volcanic provinces. The presence of these reservoirs will undoubtedly encourage future petroleum exploration in volcanic rocks up to the deep parts of sedimentary basins. 相似文献
5.
Compared to conventional reservoirs, pore structure and diagenetic alterations of unconventional tight sand oil reservoirs are highly heterogeneous. The Upper Triassic Yanchang Formation is a major tight-oil-bearing formation in the Ordos Basin, providing an opportunity to study the factors that control reservoir heterogeneity and the heterogeneity of oil accumulation in tight oil sandstones.The Chang 8 tight oil sandstone in the study area is comprised of fine-to medium-grained, moderately to well-sorted lithic arkose and feldspathic litharenite. The reservoir quality is extremely heterogeneous due to large heterogeneities in the depositional facies, pore structures and diagenetic alterations. Small throat size is believed to be responsible for the ultra-low permeability in tight oil reservoirs. Most reservoirs with good reservoir quality, larger pore-throat size, lower pore-throat radius ratio and well pore connectivity were deposited in high-energy environments, such as distributary channels and mouth bars. For a given depositional facies, reservoir quality varies with the bedding structures. Massive- or parallel-bedded sandstones are more favorable for the development of porosity and permeability sweet zones for oil charging and accumulation than cross-bedded sandstones.Authigenic chlorite rim cementation and dissolution of unstable detrital grains are two major diagenetic processes that preserve porosity and permeability sweet zones in oil-bearing intervals. Nevertheless, chlorite rims cannot effectively preserve porosity-permeability when the chlorite content is greater than a threshold value of 7%, and compaction played a minor role in porosity destruction in the situation. Intensive cementation of pore-lining chlorites significantly reduces reservoir permeability by obstructing the pore-throats and reducing their connectivity. Stratigraphically, sandstones within 1 m from adjacent sandstone-mudstone contacts are usually tightly cemented (carbonate cement > 10%) with low porosity and permeability (lower than 10% and 0.1 mD, respectively). The carbonate cement most likely originates from external sources, probably derived from the surrounding mudstone. Most late carbonate cements filled the previously dissolved intra-feldspar pores and the residual intergranular pores, and finally formed the tight reservoirs.The petrophysical properties significantly control the fluid flow capability and the oil charging/accumulation capability of the Chang 8 tight sandstones. Oil layers usually have oil saturation greater than 40%. A pore-throat radius of less than 0.4 μm is not effective for producible oil to flow, and the cut off of porosity and permeability for the net pay are 7% and 0.1 mD, respectively. 相似文献
6.
Pore-throat size is a very crucial factor controlling the reservoir quality and oiliness of tight sandstones, which primarily affects rock-properties such as permeability and drainage capillary pressure. However, the wide range of size makes it difficult to understand their distribution characteristics as well as the specific controls on reservoir quality and oiliness. In order to better understand about pore-throat size distribution, petrographic, scanning electron microscopy (SEM), pressure-controlled mercury injection (PMI), rate-controlled mercury injection (RMI), quantitative grain fluorescence (QGF) and environmental scanning electron microscopy (ESEM) investigations under laboratory pressure conditions were performed on a suite of tight reservoir from the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, China. The sandstones in this study showed different types of pore structures: intergranular pores, dissolution pores, pores within clay aggregates and even some pores related to micro fractures. The pore-throat sizes vary from nano- to micro-scale. The PMI technique views the pore-throat size ranging from 0.001 μm to 63 μm and revealed that the pore-throats with radius larger than 1.0 μm are rare and the pore-throat size distribution curves show evident fluctuations. RMI measurements indicated that the pore size distribution characteristics of the samples with different porosity and permeability values look similar. The throat size and pore throat radius ratio distribution curves had however significant differences. The overall pore-throat size distribution of the K1q4 tight sandstones was obtained with the combination of the PMI and RMI methods. The permeability is mainly contributed by a small part of larger pore-throats (less than 30%) and the ratio of the smaller pore-throats in the samples increases with decreasing permeability. Although smaller pore-throats have negligible contribution on reservoir flow potential, they are very significant for the reservoir storage capacity. The pore-throats with average radius larger than 1.0 μm mainly exist in reservoirs with permeability higher than 0.1mD. When the permeability is lower than 0.1mD, the sandstones are mainly dominated by pore-throats with average radius from 0.1 μm to 1.0 μm. The ratio of different sized pore-throats controls the permeability of the tight sandstone reservoirs in different ways. We suggest that splitting or organizing key parameters defining permeability systematically into different classes or functions can enhance the ability of formulating predictive models about permeability in tight sandstone reservoirs. The PMI combined with QGF analyses indicate that oil emplacement mainly occurred in the pore-throats with radius larger than about 0.25–0.3 μm. This result is supported by the remnant oil micro-occurrence evidence observed by SEM and ESEM. 相似文献
7.
The Upper Triassic Xujiahe Formation in the northwestern Sichuan Basin, China, is a typical tight gas sandstone reservoir that contains natural fractures and has an average porosity of 1.10% and air permeability less than 0.1 md because of compaction and cementation. According to outcrops, cores and image logs, three types of natural fractures, namely, tectonic, diagenetic and overpressure-related fractures, have developed in the tight gas sandstones. The tectonic fractures include small faults, intraformational shear fractures and horizontal shear fractures, whereas the diagenetic fractures mainly include bed-parallel fractures. According to thin sections, the microfractures also include tectonic, diagenetic and overpressure-related microfractures. The diagenetic microfractures consist of transgranular, intragranular and grain-boundary fractures. Among these fractures, intraformational shear fractures, horizontal shear fractures and small faults are predominant and significant for fluid movement. Based on the Monte Carlo method, these intraformational shear fractures and horizontal shear fractures improve the reservoir porosity and permeability, thus serving as an important storage space and primary fluid-flow channels in the tight sandstones. The small faults may provide seepage channels in adjacent layers by cutting through layers. In addition, these intragranular and grain-boundary fractures increase the connectivity of the tight gas sandstones by linking tiny pores. The tectonic microfractures improve the seepage capability of the tight gas sandstones to some extent. Low-dip angle fractures are more abundant in the T3X3 member than in the T3X2 and T3X4 members. The fracture intensities of the sandstones in the T3X3 member are greater than those in the T3X2 and T3X4 members. The fracture intensities do not always decrease with increasing bed thickness for the tight sandstones. When the bed thickness of the tight sandstones is less than 1.0 m, the fracture intensities increase with increasing bed thickness in the T3X3 member. Fluid inclusion evidence and burial history analysis indicate that the tectonic fractures developed over three periods. The first period was at the end of the Triassic to the Early Jurassic. The tectonic fractures developed during oil generation but before the matrix's porosity and permeability reduced, which suggests that these tectonic fractures could provide seepage channels for oil migration and accumulation. The second period was at the end of the Cretaceous after the matrix's porosity and permeability reduced but during peak gas generation, which indicates that gas mainly migrated and accumulated in the tectonic fractures. The third period was at the end of the Eogene to the Early Neogene. The tectonic fractures could provide seepage channels for secondary gas migration and accumulation from the Upper Triassic Xujiahe Formation into the overlying Jurassic Formation. 相似文献
8.
《Marine and Petroleum Geology》2013,39(1):53-72
Evaluation of the reservoir quality of the Triassic Halfway–Montney–Doig hybrid gas shale/tight gas reservoir in the Groundbirch field in northeastern British Colombia requires an integration of unconventional and conventional methodologies. Reservoir evaluation includes reservoir thickness and structure, total porosity, TOC content, organic maturity, pore size distribution (micro- to macro-pore size fractions), surface area, mineralogy and pulse-decay permeability. Quartz (10–74%), carbonate (13–73%) and feldspar (0–42%) dominate the mineralogy of all formations with illite (0–32%) being locally important. The Tmax values range between 443 and 478 °C placing the reservoirs beyond the oil window. Pore size distribution by low-pressure gas adsorption analysis identifies a large variation between the contributions from the micro-, meso- and macro-pore size fractions. Matrix permeabilities range between 1.0E-3 and 6.5E-7 mD at an effective stress between 2400 and 3300 PSI (16.5–22.8 MPa).Changes in depositional environments and diagenetic processes manifest as differences in lithology and mineralogy within the Montney and Doig reservoirs which subsequently affect the fabric, texture and pore size distribution. Fabric, texture and pore size distribution contribute to the variation in the permeability and the proportions of free to sorbed gas within the reservoir. Quartz-rich, coarser-grained intervals (upper portions of Doig C, B and Halfway Formation) have lower surface area, greater porosities and a higher volume of macropores compared to the carbonate- and clay-rich finer-grained intervals (Doig A). Permeabilities do not vary according to lithology with higher permeabilities found within both fine-grained (Doig A) and coarser-grained (Halfway Formation) units. Permeability is controlled by pore size distribution. Higher permeability samples contain a balanced ratio between micro-, meso- and macro-porosity. The finer-grained intervals have higher sorbed gas capacity due to higher surface areas because of the higher volumes of finer mesopores and micropores than the coarser-grained units. However, porosity and permeability are low in some parts of the Doig A and fracture stimulation is necessary to achieve economic flow rates. 相似文献
9.
Shuyun Xie Qiuming Cheng Qicong Ling Bing Li Zhengyu Bao Ping Fan 《Marine and Petroleum Geology》2010
The petrophysical evaluation of the reservoir capacity is of great importance in predicting the reserves and productivity of petroleum fields, which may directly affect petroleum exploration. In the past, such kind of evaluation was mainly based on the experimental measurements of the petrophysical porosity and permeability of reservoir rock samples. Assessing quantitatively the microstructures of carbonates, including irregularities of pore shapes and frequency distributions of pore sizes, is becoming one of the most challenging efforts in pore-scale analysis. Based on the digital analyses of the two-dimensional images from thin sections taken under the environmental scanning electron microscope (ESEM) at various magnification scales, the current paper tries to quantify the pore spaces of carbonate samples by fractal and multifractal methods, which have been demonstrated to be effective. The study area is located in the western Hubei and eastern Sichuan, China. As many as 25 carbonate samples from various members in five formations of the Permian-Triassic periods and 132 ESEM images were chosen in this study. All individual pores had been recognized, and their areas and perimeters had been calculated as well. The box-counting fractal dimensions and four major multifractal parameters associated with the multifractal spectra are used. The results show that the values of the petrophysical porosity and permeability are closely related to the box-counting dimensions and the multifractal parameters, which demonstrates that the textural arrangements of the pores control the porosity and permeability to a certain extent. There is also a link between the reservoiring capabilities of different formations and the fractal and multifractal parameters. The reservoiring capability assessment result is in agreement with the field research analysis. 相似文献
10.
Understanding the hydrocarbon accumulation pattern in unconventional tight reservoirs is crucial for hydrocarbon evaluation and oil/gas extraction from such reservoirs. Previous studies on tight oil accumulation are mostly concerned with self-generation or from source to reservoir rock over short distances. However, the Lucaogou tight oil in Jimusar Sag of Junggar Basin shows transitional feature in between. The Lucaogou Formation comprises fine-grain sedimentary rocks characterized by thin laminations and frequently alternating beds. The Lucaogou tight silt/fine sandstones are poorly sorted. Dissolved pores are the primary pore spaces, with average porosity of 9.20%. Although the TOC of most silt/fine sandstones after Soxhlet extraction is lower than that before extraction, they show that the Lucaogou siltstones in the area of study have fair to good hydrocarbon generation potential (average TOC of 1.19%, average S2 of 4.33 mg/g), while fine sandstones are relatively weak in terms of hydrocarbon generation (average TOC of 0.4%, average S2 of 0.78 mg/g). The hydrocarbon generation amount of siltstones, which was calculated according to basin modeling transformation ratio combined with original TOC based on source rock parameters, occupies 16%–72% of oil retention amount. Although siltstones cannot produce the entire oil reserve, they certainly provide part of them. Grain size is negatively correlated with organic matter content in the Lucaogou silt/fine sandstones. Fine grain sediments are characterized by lower deposition rate, stronger adsorption capacity and oxidation resistance, which are favorable for formation of high quality source rocks. Low energy depositional environment is the primary reason for the formation of siltstones containing organic matter. Positive correlation between organic matter content and clay content in Lucaogou siltstones supports this view point. Lucaogou siltstones appear to be effective reservoir rocks due to there relatively high porosity, and also act as source rocks due to the fair to good hydrocarbon generation capability. 相似文献
11.
The geochemistry, origin and charge history of oils from the Yuqi area of Tarim Basin have been investigated, through GC, GC-MS and fluid inclusion microthermometry analysis. The Yuqi oils accumulated mainly in three intervals: (1) in the Lower-Middle Ordovician Yingshan Formation (O1-2y) carbonate reservoirs; (2) in the overlying Upper Triassic Halahatang Formation (T3h); and (3) in the Lower Cretaceous Yageliemu Formation (K1y) sandstones. Oils from different reservoirs have distinct physical properties, varying from extra-heavy (O1-2y), heavy (T3h), to light oils (T3h and K1y). However, their geochemical compositions show a high degree of similarity, which indicates that they derive from the same source rock. Abundant tricyclic terpanes, gammacerane, dibenzothiophene and C21C22steranes, together with a low level of diasteranes, indicate an anoxic marine source rock for oils in the Yuqi area. Oil-oil correlation shows that Yuqi oils derive from the same source bed as Tahe oils. The co-occurrence of intact n-alkanes and 25-norhopanes in all the samples supports the proposition that there is a mixture of an early filled severely biodegraded oil and a late filled fresh oil.In this study, charge history is examined on the basis of integration of fluid inclusion homogenization temperature data with 1D burial-thermal history models. Two episodes of oil charging are identified in the O1-2y reservoir (well YQX1-1) at around 436-420 Ma (Middle-Late Silurian) and 10-3 Ma (Miocene to Pliocene), respectively. For the samples from the T3h and K1y intervals, only one episode of oil charge is indicated by the homogenization temperatures of coexisting aqueous inclusions with an inferred timing around 10-3 Ma. The T3h heavy oil reservoir is assumed to be a secondary hydrocarbon pool, which accumulated by re-migration and re-distribution of hydrocarbons from O1-2y hydrocarbon pools. The few early biodegraded oils in the K1y light oils were probably picked up along the migration pathway during the late fresh oil charging. 相似文献
12.
Diagenesis is of decisive significance for the reservoir heterogeneity of most clastic reservoirs. Linking the distribution of diagenetic processes to the depositional facies and sequence stratigraphy has in recent years been discipline for predicting the distribution of diagenetic alterations and reservoir heterogeneity of clastic reservoirs. This study constructs a model of distribution of diagenetic alterations and reservoir heterogeneity within the depositional facies by linking diagenesis to lithofacies, sandstone architecture and porewater chemistry during burial. This would help to promote better understanding of the distribution of reservoir quality evolution and the intense heterogeneity of reservoirs. Based on an analogue of deltaic distributary channel belt sandstone in Upper Triassic Yanchang Formation, 83 sandstone plug samples were taken from 13 wells located along this channel belt. An integration of scanning electron microscopy, thin sections, electron microprobe analyses, rate-controlled porosimetry (RCP), gas-flow measurements of porosity and permeability, and nuclear magnetic resonance (NMR) experiments, together with published data, were analysed for the distribution, mineralogical and geochemical characteristics of detrital and diagenetic components and the distribution of reservoir quality within the distributary channel belt.Distribution of diagenetic alterations and reservoir heterogeneity within the distributary channel belt sandstones include (i) formation of high quality chlorite rims in the middle part of thick sandstones with coarser grain sizes and a lower content of ductile components resulted from the greater compaction resistance of these sandstones (providing larger pore spaces for chlorite growth), leading to formation of the intergranular pore – wide sheet-like throat and intergranular pore - intragranular pore – wide sheet-like throat (Φ>15%, k>1mD) in the middle part of thick sandstones; (ii) formation of thinner chlorite rims in the middle part of thinner sandstones is associated with the intergranular pore - intragranular pore – narrow sheet-like throat (9%<Φ<14%, 0.2mD<k<0.8mD); (iii) strong cementation by kaolinite in the more proximal sandstones of distributary channel owing to the strong feldspar dissolution by meteoric water, resulting in the intragranular pore - group of interstitial cement pores – narrow sheet-like throat/extremely narrow sheet-like throat (8%<Φ<11%, 0.1mD<k<0.3mD) due to the pore-filling kaolinite occluding porosity; (iv) formation of dense ferrocalcite zones (δ18OVPDB = −23.4‰ to −16.6‰; δ13 CVPDB = −4.0‰ to −2.3‰) favoured in the top and bottom of the channel sandstone which near the sandstone-mudstone bouding-surface, destroying pore space (Φ<8%, k<0.1mD); (v) strong compaction in sandstone of distributary channel edge laterally as a result of fine grain size and high content of ductile components in those sandstones, forming the group of interstitial cement pores – extremely narrow sheet-like throat with porosity values less than 8%. 相似文献
13.
This article proposes a predictive method for identifying the range of sea-states considered safe for the installation of offshore structures. A finite element dynamic analysis of the system for various sea-states characterized by significant wave heights and mean zero-up-crossing wave periods and modeled as a combination of several wave components has been performed. Using this procedure a table of safe and unsafe sea-states is generated. The significant wave height (Hs) and mean zero-up-crossing wave period (Tz) of a future sea-state in a location in the north east Pacific were predicted from the distributions whose parameters were estimated using the artificial neural networks (ANNs) trained for this purpose. The location of US National Oceanographic Data Center (NODC) Buoy 46005 is used in this study.The Hs and Tz of some future sea-states were predicted from their corresponding conditional 7-parameter distribution given some information including a number of previously measured Hs’s and Tz’s. This gives a predicted sea-state for a specific time in future. The parameters of the distributions have been estimated from the outputs of two different 7-network sets of trained ANNs. A pile-driving operation is used as a case study in which the pile configuration, including the non-linear foundation and the gap between the pile and the pile sleeve shims, has been modeled by the finite elements method and the range of sea-states suitable for safe pile-driving operation was identified. 相似文献
14.
Understanding the oil distribution characteristics in unconventional tight reservoirs is crucial for hydrocarbon evaluation and oil/gas extraction from such reservoirs. Previous studies on tight oil distribution characteristics are mostly concerned with the basin scale. Based on Lucaogou core samples, geochemical approaches including Soxhlet extraction, total organic carbon (TOC), and Rock-Eval are combined with reservoir physical approaches including mercury injection capillary pressure (MICP) and porosity-permeability analysis, to quantitatively evaluate oil distribution of tight reservoirs on micro scale. The emphasis is to identify the key geological control factors of micro oil distribution in such tight reservoirs. Dolomicrites and non-detrital mudstones have excellent hydrocarbon generation capacity while detritus-containing dolomites, siltstones, and silty mudstones have higher porosity and oil content, and coarser pore throat radius. Oil content is mainly controlled by porosity, pore throat radius, and hydrocarbon generation capacity. Porosity is positively correlated with oil content in almost all samples including various lithologies, indicating that it is a primary constraint for providing storage space. Pore throat radius is also an important factor, as oil migration is inhibited by the capillary pressure which must be overcome. If the reservoir rock with suitable porosity has no hydrocarbon generation capacity, pore throat radius will be decisive. As tight reservoirs are generally characterized by widely distributed nanoscale pore throats and high capillary pressure, hydrocarbon generation capacity plays an important role in reservoir rocks with suitable porosity and fine pore throats. Because such reservoir rocks cannot be charged completely. The positive correlation between hydrocarbon generation capacity and oil content in three types of high porosity lithologies (detritus-containing dolomites, siltstones, and silty mudstones) supports this assertion. 相似文献
15.
Permeability characterisation of low permeability, clay-rich gas sandstones is part of production forecasting and reservoir management. The physically based Kozeny (1927) equation linking permeability with porosity and pore size is derived for a porous medium with a homogeneous pore size, whereas the pore sizes in tight sandstones can range from nm to μm. Nuclear magnetic resonance (NMR) transverse relaxation was used to estimate a pore size distribution for 63 samples of Rotliegend sandstone. The surface relaxation parameter required to relate NMR to pore size is estimated by combination of NMR and mercury injection data. To estimate which pores control permeability to gas, gas permeability was calculated for each pore size increment by using the Kozeny equation. Permeability to brine is modelled by assuming a bound water layer on the mineral pore interface. The measured brine permeabilities are lower than predicted based on bound water alone for these illite rich samples. Based on the fibrous textures of illite as visible in electron microscopy we speculate that these may contribute to a lower brine permeability. 相似文献
16.
This study presents approaches for evaluating hybrid source rock/reservoirs within tight-rock petroleum systems. The emerging hybrid source rock/reservoir shale play in the Upper Cretaceous Second White Specks and Belle Fourche formations in central Alberta, Canada is used as an example to evaluate organic and inorganic compositions and their relationships to pore characteristics. Nineteen samples from a 77.5 m-long core were analyzed using organic petrography, organic geochemistry, several methods of pore characterization, and X-ray powder diffraction (XRD). The lower part of the studied section includes quartz- and clay-rich mudrocks of the Belle Fourche Formation with low carbonate content, whereas the upper portion contains calcareous mudrocks of the Second White Specks Formation. Strata are mineralogically composed of quartz plus albite (18–56 wt. %), carbonates (calcite, dolomite, ankerite; 1–65 wt. %), clays (illite, kaolinite, chlorite; 15–46 wt. %), and pyrite (2–12 wt. %). Petrographic examinations document that organic matter represents marine Type II kerogen partly biodegraded with limited terrestrial input. Vitrinite reflectance Ro (0.74–0.87%), Tmax values (438–446 °C) and biomarkers indicate mid-maturity within the oil window. The relatively poor remaining hydrocarbon potential, expressed as an S2 value between 2.1 and 6.5 mg HC/g rock, may result from an estimated 60–83% of the original kerogen having been converted to hydrocarbons, with the bulk having migrated to adjacent sandstone reservoirs. However, the present-day remaining total organic carbon TOCpd content remains relatively high (1.7–3.6 wt. %), compared with the estimated original TOCo of 2.4–5.0 wt. %. The calculated transformation ratio of 60–83% suggests that the remaining 17–40 wt. % of kerogen is able to generate more hydrocarbons. The studied section is a tight reservoir with an average Swanson permeability of 3.37·10−5 mD (measured on two samples) and total porosity between 1.7 and 5.0 vol. % (3 vol. % on average). The upper part of the sandy Belle Fourche Formation, with slightly elevated porosity values (3.5–5 vol. %), likely represents the interval with the best reservoir properties in the studied core interval. Total pore volume ranges between 0.0065 and 0.0200 cm3/g (measured by a combination of helium pycnometry and mercury immersion). Mesopores (2–50 nm ∅) are the most abundant pores and occupy 34–67% of total porosity or a volume of 0.0030–0.0081 cm3/g. In comparison, micropores (<2 nm ∅) cover a wide range from 6 to 60% (volume 0.0007–0.0053 cm3/g), and macropores (>50 nm ∅) reach up to 57% with the exception of some samples failing to indicate the presence of this pore fraction (volume 0.0000–0.0107 cm3/g). Macroporosity is mostly responsible for variations in total porosity, as suggested by macroporosity's strongest correlation with total porosity within the section. The relatively narrow ranges of TOC and minerals contents among measured samples limit our ability to further deconvolute factors that influence changes in total porosity and pore size distribution. 相似文献
17.
《Ocean Modelling》2003,5(1):77-89
Proposed is a method of finding unstable steady solutions based on relaxation to a running mean. It works for moderate supercriticality, when the growth rates of the instabilities do not exceed their frequencies. To calculate the running mean one should use the decaying exponential function as a kernel in the convolution formula, it offers a combination of necessary stabilization properties with the efficiency of numerical implementation. The method requires specification of the relaxation TR and averaging TA time scales, such that in the transformed eigenspectrum frequencies above the cutoff 1/TA experience additional damping with 1/TR rate. All originally decaying modes remain decaying. The zero frequency remains unchanged, which implies that the steady states are invariant under the transformation. The acceptable values for TR and TA can be obtained from an estimate of the frequencies and growth rates of the modes leading to instability. For faster convergence to the steady state TR should be set as large as possible, provided it causes sufficient damping of the instability. The numerical implementation of this method requires only very simple modifications to the program used for time integration of the original system. 相似文献
18.
R. Mourgues J.B. GressierL. Bodet D. BureauA. Gay 《Marine and Petroleum Geology》2011,28(5):1111-1121
In petroleum industry, the difference between pore pressure (Pp) and minimum horizontal stress Sh (termed the seal or retention capacity) is of major consideration because it is often assumed to represent how close a system is to hydraulic failure and thus the maximum hydrocarbon column height that can be maintained. While Sh and Pp are often considered to be independent parameters, several studies in the last decade have demonstrated that Sh and Pp are in fact coupled. However, the nature of this coupling relationship remains poorly understood. In this paper, we explore the influences of the spatial pore pressure distribution on Sh/Pp coupling and then on failure pressure predictions and trap integrity evaluation. With analytical models, we predict the fluid pressure sustainable within a reservoir before failure of its overpressured shale cover. We verify our analytical predictions with experiments involving analogue materials and fluids. We show that hydraulic fracturing and seal breach occur for fluid pressure greater than it would be expected from conventional retention capacity. This can be explained by the impact of the fluid overpressure field in the overburden and the pressure diffusion around the reservoir on the principal stresses. We calculate that supralithostatic pressure could locally be reached in overpressured covers. We also define the retention capacity of a cover (RC) surrounding a fluid source or reservoir as the difference between the failure pressure and the fluid overpressure prevailing in shale at the same depth. In response to a localized fluid pressure rise, we show that the retention capacity does not only depend on the pore fluid overpressure of the overburden but also on the tensile strength of the cover, its Poisson’s ratio, and the depth and width of the fluid source. 相似文献
19.
The geochemical and petrographic characteristics of saline lacustrine shales from the Qianjiang Formation, Jianghan Basin were investigated by organic geochemical analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM) and low pressure nitrogen adsorption analysis. The results indicate that: the saline lacustrine shales of Eq3 member with high oil content are characterized by type I and type II oil-prone kerogen, variable TOC contents (1.0–10.0 wt%) and an early-maturity stage (Ro ranges between 0.41 and 0.76%). The mineral compositions of Eq3 saline shale show strong heterogeneity: brittle intervals with high contents of quartz and carbonate are frequently alternated with ductile intervals with high glauberite and clay contents. This combination might be beneficial for oil accumulation, but may cause significant challenges for the hydraulic stimulation strategy and long-term production of shale oil. The interparticle pores and intraparticle pores dominate the pore system of Eq3 shale, and organic matter hosted pores are absent. Widely distributed fractures, especially tectonic fractures, might play a key role in hydrocarbon migration and accumulation. The pore network is contributed to by both large size inorganic pores and abundant micro-factures, leading to a relatively high porosity (2.8–30.6%) and permeability (0.045–6.27 md) within the saline shale reservoir, which could enhance the flow ability and storage capacity of oil. The oil content (S1 × 100/TOC, mg HC/g TOC and S1, mg HC/g rock) and brittleness data demonstrate that the Eq33x section has both great potential for being a producible oil resource and hydraulic fracturing. Considering the hydrocarbon generation efficiency and properties of oil, the mature shale of Eq3 in the subsidence center of the Qianjiang Depression would be the most favorable zone for shale oil exploitation. 相似文献
20.
As shale oil occurs primarily in micro–nano pores and fractures, research about the effect of pore structure on shale oil accumulation has great significance for shale oil exploration and development. The effect of pore structure on shale oil accumulation in the lower third member of the Shahejie formation (Es3l), Zhanhua Sag, eastern China was investigated using gas adsorption, soxhlet extraction, nuclear magnetic resonance (NMR) analysis, and field emission scanning electron microscope (FE-SEM) observation. The results indicated that the samples contained a larger amount of ink-bottle-shaped and slit-shaped pores after extraction than before extraction. The pore volume and specific surface area of the samples were approximately 2.5 times larger after extraction than before extraction. Residual hydrocarbon occurred primarily in the free-state form in pores with diameters of 10–1000 nm, which can provide sufficient pore volume for free hydrocarbon accumulation. Therefore, pores with diameters of 10–1000 nm were regarded as “oil-enriched pores”, which are effective pores for shale oil exploration, whereas pores with diameters smaller than 10 nm were regarded as “oil-ineffective pores”. Samples with only well-developed small pores with diameters smaller than 1000 nm showed high oil saturation, whereas samples with both small pores and also relatively large pores and micro-fractures presented low oil saturation. As the minimum pore size allowing fluid expulsion is 1000 nm, pores with diameters greater than 1000 nm were considered as “oil-percolated pores”. Large pores and micro-fractures are generally interconnected and may even form a complex fracture mesh, which greatly improves the permeability of shale reservoirs and is beneficial to fluid discharge. 相似文献