THE NATURE AND ORIGIN OF AUTHIGENIC CHLORITE AND RELATED CEMENTS IN OLIGO–MIOCENE RESERVOIR SANDSTONES,TAPTI GAS FIELDS,SURAT DEPRESSION,OFFSHORE WESTERN INDIA

Reservoir sandstones in the Mid‐ and South Tapti gas fields in the Surat Depression (Mumbai Offshore Basin, western India) have been investigated using a range of petrographic techniques, isotope geochemistry and basin modelling. Authigenic chlorite is abundant in the shallow‐marine sandstones of the Miocene Mahim Formation, a major reservoir rock in the Mid‐ and South Tapti fields, which are described here in terms of their quality and diagenetic characteristics. The sandstones are currently at burial depths of between ～1500 and 2800m. The authigenic chlorite has had a significant impact on the resulting reservoir quality of the sandstones and is interpreted to have originated as odinite clay of the verdine facies that replaced faecal or pseudo‐faecal pellets, together with volumetrically small but abundant grain coatings and grain rims, and formed at the site of major riverine iron influx onto the shallow‐marine shelf during periods of relatively low sea level. Pellets have been variably compacted to form pseudomatrix. Reservoir sandstones from similar depositional settings on the west coast of India or other sub‐tropical settings are likely to exhibit comparable diagenetic effects on reservoir quality. Compositionally, the chlorite is the iron‐rich form known as chamosite. The chemistry of all the chlorite morphologies is the same in all studied samples. Oxygen isotope analyses of carbonate cements in the Mahim Formation sandstones have provided an approximate temperature framework for diagenesis of the non‐carbonate cements. Oxygen isotope results for the chlorite, however, suggest much higher temperatures than its position in the paragenetic sequence would warrant. These results suggest that the clay formed first as 1:1 layer clays, in this case odinite, which were then transformed to Fe‐chlorite as burial depths and temperatures increased. Reservoirs in the Mahim, Daman and Mahuva Formation sandstones are thus greatly influenced by the diagenesis of authigenic chlorite and locally by the precipitation of carbonate cements. Reservoir quality is good where thick, continuous chlorite rim cements are present and where chlorite pellets are sufficiently indurated for them not to be compacted. Chlorite rim cements have reduced the extent of quartz overgrowth cementation in the sandstones.     

Petrophysical and capillary pressure properties of the upper Triassic Xujiahe Formation tight gas sandstones in western Sichuan, China

The tight sandstones of the Upper Triassic Xujiahe Formation（T₃x） constitute important gas reservoirs in western Sichuan.The Xujiahe sandstones are characterized by low to very low porosity （av.5.22%and 3.62%） for the T₃x⁴ and T₃x² sandstones,respectively),extremely low permeability（av. 0.060 mD and 0.058 mD for the T₃x⁴ and T₃x² sandstones,respectively）,strong heterogeneity,micronano pore throat,and poor pore throat sorting.As a result of complex pore structure and the occurrence of fractures,weak correlations exist between petrophysical properties and pore throat size,demonstrating that porosity or pore throat size alone does not serve as a good permeability predictor.Much improved correlations can be obtained between permeability and porosity when pore throat radii are incorporated. Correlations between porosity,permeability,and pore throat radii corresponding to different saturations of mercury were established,showing that the pore throat radius at 20%mercury saturation(R₂₀) is the best permeability predictor.Multivariate regression analysis and artificial neural network（ANN） methods were used to establish permeability prediction models and the unique characteristics of neural networks enable them to be more successful in predicting permeability than the multivariate regression model.In addition, four petrophysical rock types can be identified based on the distributions of R₂₀,each exhibiting distinct petrophysical properties and corresponding to different flow units.     

姬塬地区长2油层组储层岩石学特征研究

通过大量的岩心观察以及薄片鉴定,并以此为基础对该区储层岩石学特征进行了深入的研究。研究结果表明姬塬地区长2地层储层岩性以细粒长石砂岩和岩屑长石砂岩为主,储集砂岩的主要胶结物有高岭石、绿泥石、铁方解石及硅质,次为伊利石、铁白云石、方解石及长石质,姬塬地区长2砂岩分选中-好、次棱角状,以薄膜-孔隙及孔隙式胶结为主。     

各向异性多层砂岩油藏矢量化井网研究

基于同一层系内部不同方向性的纵向多层组合,将数值模拟技术与矢量化井网概念相结合,研究不同渗透率方向性组合下同一层系的五点法和反七点法的部署模式。结果表明,适当的井网方向性能够改善此类开发层系的注水开发效果。     

东营凹陷西部沙四上亚段超压成因及增压模式

滩坝砂岩是东营凹陷西部沙四上亚段的重要沉积储层,超压对滩坝砂岩油气成藏具有明显的控制作用。利用测井参数对超压的响应特征建立了超压成因的判别方法并对超压成因进行了分析,认为东营凹陷沙四上亚段深湖相沉积物的快速沉积埋藏使得欠压实成为超压形成重要因素;沙四上亚段优质烃源岩的广泛发育及热演化使得生烃增压成为超压形成的另一个重要原因。建立了东营凹陷西部增压模式,将超压的演化分为正常压实阶段、欠压实及早期生烃增压阶段以及大量生、排烃增压三个阶段,在超压发育的不同阶段,欠压实与生烃增压先后成为最重要的因素。     

Permeability variations in Berea and Vosges sandstone submitted to cyclic temperature percolation of saline fluids

The behaviour has been examined of two samples of Berea and Vosges sandstones submitted to the circulation of solutions of different natures, at different temperatures. Solutions of CaCl₂ and NaCl at ionic strenghts I = 0.01, I = 0.1 and I = 1, taken in the increasing and then decreasing directions, were heated to temperatures of 20, 30, 40, 50, 60, 70, 80 and 90°C. These temperatures were taken in the increasing and then decreasing directions.For the two sandstones, each temperature variation in the percolating solution was accompanied by a sharp variation in permeability, in the opposite direction to the temperature variation. The permeability versus temperature variation describes hysteresis loops whose area is greater when hot than when cold. These curves are typical of two types of behaviour. The first is obtained with diluted solutions (I = 0.01 and I = 0.1), and is characterized by a greater permeability during the rising temperature cycle than during the decreasing temperature cycle. The second, obtained with concentrated solutions, is characterized by an inverse variation: the permeability is greater during the decreasing temperature cycle than during the rising cycle.These different behaviours are interpreted in terms of flocculation-deflocculation of the clays contained in the porous media.     

Pore microgeometry analysis in low-resistivity sandstone reservoirs

The objective of this work is to analyse the pore microgeometry and its effect on petrophysical properties in six low-resistivity sandstone reservoirs by combining a 2D quantitative petrographic image analysis (PIA) and 3D petrophysical tools. The classic petrophysical tools enable the measurement of different classic reservoir properties such as specific surface area, average pore diameter, pore size distribution, macroporosity and microporosity, capillary pressure versus saturation, pore chamber–pore throat diameter ratio, electrical properties and permeability. The petrographic image analysis quantifies pore microgeometry in more than four orders of magnitude, from submicron to millimeter scale. Chloritic low-resistivity sandstones show dual porosity structure defined as chloritic texture. The pore microgeometrical parameters measured by petrographic image analysis allow one to model different reservoir properties such as capillary pressure, permeability and electrical behaviour. The results obtained in these models show that pore microgeometry plays an important role in the physical properties of low-resistivity sandstone reservoirs.     

DIAGENETIC CONTROLS ON THE RESERVOIR QUALITY OF TIGHT OIL-BEARING SANDSTONES IN THE UPPER TRIASSIC YANCHANG FORMATION,ORDOS BASIN,NORTH-CENTRAL CHINA

Tight oil-bearing sandstones in the Chang 4+5, 6 and 7 Members of the Upper Triassic Yanchang Formation in the Ordos Basin, north-central China, in general consist of fine-grained, moderately- to poorly-sorted lithic arkoses (average Q₅₃F₃₀R₁₇) deposited in a fluvial-dominated lacustrine-deltaic environment. Diagenetic modifications to the sandstones include compaction and cementation by calcite, dolomite, ankerite, quartz, chlorite, kaolinite and illite, as well as partial dissolution of feldspars and minor rock fragments. Porosity ranges up to ~7% of the rock volume and was reduced more by cementation than by compaction. Fractures (tectonic macrofractures and diagenetic microfractures) provide important oil migration pathways and enhance the sandstones' storage potential. The pore network is heterogeneous due to processes related to deposition and diagenesis, and there are considerable spatial variations in porosity and pore connectivity. The pore system includes both macropores and micropores, and pore network variations depend on the type and distribution of authigenic cements. An analysis of the diagenetic and porosity characteristics of core samples of the Yanchang Formation sandstones from wells in the Youfangzhuang oilfield resulted in the recognition of six petrofacies (A-F) whose characteristics allow reservoir quality to be predicted. Fluid performance analysis for selected sandstone samples using nuclear magnetic resonance combined with helium porosity and air permeability shows that high permeability and large pore throats together result in high movable fluid saturation potential, and that effective pore spaces and throats are beneficial for hydrocarbon storage and flow. Relatively higher porosity and permeability tend to occur in petrofacies B sandstones containing abundant pore-lining chlorite with lesser kaolinite and minor carbonate cements, and in petrofacies C sandstones with abundant pore-filling kaolinite cement but little chlorite and carbonate cements. These petrofacies represent the best reservoir-quality intervals. A reservoir quality prediction model is proposed combined with the petrofacies classification framework. This model will assist future development of tight sandstone reservoirs both in the Upper Triassic Yanchang Formation in the Ordos Basin and elsewhere.     

PETROLEUM SYSTEMS MODELLING IN A FOLD‐AND‐THRUST BELT SETTING: THE INVERTED CAMEROS BASIN,NORTH‐CENTRAL SPAIN

The Mesozoic Cameros Basin, northern Spain, was inverted during the Cenozoic Alpine orogeny when the Tithonian – Upper Cretaceous sedimentary fill was uplifted and partially eroded. Tar sandstones outcropping in the southern part of the basin and pyrobitumen particles trapped in potential source rocks suggest that hydrocarbons have been generated in the basin and subsequently migrated. However, no economic accumulations of oil or gas have yet been found. This study reconstructs the evolution of possible petroleum systems in the basin from initial extension through to the inversion phase, and is based on structural, stratigraphic and sedimentological data integrated with petrographic and geochemical observations. Petroleum systems modelling was used to investigate the timing of source rock maturation and hydrocarbon generation, and to reconstruct possible hydrocarbon migration pathways and accumulations. In the northern part of the basin, modelling results indicate that the generation of hydrocarbons began in the Early Berriasian and reached a peak in the Late Barremian – Early Albian. The absence of traps during peak generation prevented the formation of significant hydrocarbon accumulations. Some accumulations formed after the deposition of post‐extensional units (Late Cretaceous in age) which acted as seals. However, during subsequent inversion, these reservoir units were uplifted and eroded. In the southern sector of the basin, hydrocarbon generation did not begin until the Late Cretaceous due to the lower rates of subsidence and burial, and migration and accumulation may have taken place until the initial phases of inversion. Sandstones impregnated with bitumen (tar sandstones) observed at the present day in the crests of surface anticlines in the south of the basin are interpreted to represent the relics of these palaeo‐accumulations. Despite a number of uncertainties which are inherent to modelling the petroleum systems evolution of an inverted and overmature basin, this study demonstrates the importance of integrating multidisciplinary and multi‐scale data to the resource assessment of a complex fold‐and‐thrust belt.     

A New Approach for Predrilling the Unconfined Rock Compressive Strength Prediction

Abstract

A reasonable knowledge of rock's physical and mechanical properties could save the cost of drilling and production of a reservoir to a large extent by selection of proper operating parameters. In addition, a master development plan (MDP) for each oilfield may contain many enhanced oil recovery procedures that take advantage of rock mechanical data and principles. Thus, an integrated rock mechanical study can be considered an investment in field development.

The unconfined compressive strength (UCS) of rocks is the important rock mechanical parameter and plays a crucial role when drilling an oil or gas well. A drilling operation is an interaction between the rock and the bit and the rock will fail when the resultant stress is greater than the rock strength. UCS is actually the stress level at which rock is broken down when it is under a uniaxial stress. It can be used for bit selection, real-time wellbore stability analysis, estimation an optimized time for pulling up the bit, design of enhanced oil recovery (EOR) procedures, and reservoir subsidence studies.

Rock strength can be estimated along a drilled wellbore using different approaches, including laboratory tests, core–log relationships, and penetration model approaches. Although this rock strength profile can be used for future investigation of formations around the wellbore, they are actually dead information. Dead rock strength data may not be useful for designing a well in a blind location (infill drilling). Rock strength should be predicted prior to drilling operations. These sort of data are helpful in proposing a drilling program for a new well.

In this research, new equations for estimation of rock strength in Ahwaz oilfield are formulated based on statistical analysis. Then, they are utilized for estimation of the rock strength profile of 36 wells in a Middle Eastern oilfield. An artificial neural network is then utilized for prediction of UCS in any predefined well trajectory. Cross-validation tests showed that the results of the network were compatible with reality. This approach has proven to be useful for estimation of any designed well trajectory prior to drilling.