Reservoir Quality Of Sandstones Research Articles

Petroleum reservoir quality prediction: overview and contrasting approaches from sandstone and carbonate communities

Abstract The porosity and permeability of sandstone and carbonate reservoirs (known as reservoir quality) are essential inputs for successful oil and gas resource exploration and exploitation. This chapter introduces basic concepts, analytical and modelling techniques and some of the key controversies to be discussed in 20 research papers that were initially presented at a Geological Society conference in 2014 titled ‘Reservoir Quality of Clastic and Carbonate Rocks: Analysis, Modelling and Prediction’. Reservoir quality in both sandstones and carbonates is studied using a wide range of techniques: log analysis and petrophysical core analysis, core description, routine petrographic tools and, ideally, less routine techniques such as stable isotope analysis, fluid inclusion analysis and other geochemical approaches. Sandstone and carbonate reservoirs both benefit from the study of modern analogues to constrain the primary character of sediment before they become a hydrocarbon reservoir. Prediction of sandstone and carbonate reservoir properties also benefits from running constrained experiments to simulate diagenetic processes during burial, compaction and heating. There are many common controls on sandstone and carbonate reservoir quality, including environment of deposition, rate of deposition and rate and magnitude of sea-level change, and many eogenetic processes. Compactional and mesogenetic processes tend to affect sandstone and carbonate somewhat differently but are both influenced by rate of burial, and the thermal and pressure history of a basin. Key differences in sandstone and carbonate reservoir quality include the specific influence of stratigraphic age on seawater composition (calcite v. aragonite oceans), the greater role of compaction in sandstones and the greater reactivity and geochemical openness of carbonate systems. Some of the key controversies in sandstone and carbonate reservoir quality focus on the role of petroleum emplacement on diagenesis and porosity loss, the role of effective stress in chemical compaction (pressure solution) and the degree of geochemical openness of reservoirs during diagenesis and cementation. This collection of papers contains case study-based examples of sandstone and carbonate reservoir quality prediction as well as modern analogue, outcrop analogue, modelling and advanced analytical approaches.

About this title ‐ Reservoir Quality of Clastic and Carbonate Rocks: Analysis, Modelling and Prediction

Reservoir quality is studied using a wide range of similar techniques in both sandstones and carbonates. Sandstone and carbonate reservoir quality both benefit from the study of modern analogues and experiments, but modelling approaches are currently quite different for these two types of reservoirs. There are many common controls on sandstone and carbonate reservoir quality, but also distinct differences due primarily to mineralogy. Numerous controversies remain including the question of oil inhibition, the key control on pressure solution and geochemical flux of material to or from reservoirs. This collection of papers contains case-study-based examples of sandstone and carbonate reservoir quality prediction as well as modern analogue, outcrop analogue, modelling and advanced analytical approaches.

The effect of oil emplacement on quartz cementation in a deeply buried sandstone reservoir

Quartz is an important, porosity-occluding cement in sandstone reservoirs that have been subjected to elevated temperature (>80°C to 100°C) for a substantial period of time. The effect of oil emplacement on quartz cementation in reservoir sandstones is controversial; some studies have concluded that early oil emplacement can inhibit quartz cementation, leading to the preservation of porosity, whereas other studies have concluded that quartz cementation appears largely unaffected by oil emplacement. Here we have studied shallow marine, Upper Jurassic sandstones from Ula field, Norwegian North Sea, with reservoir temperatures of approximately 150°C, to determine whether oil emplacement had a significant impact on diagenesis with particular attention to quartz cementation. Following sedimentological description of cores, samples above and below the oil–water contact have been collected, adjacent to core-analysis plug points. These samples then underwent a series of studies, including petrographic point counting with a transmitted light microscope, scanning electron microscopy (SEM), backscattered electron microscopy, SEM-cathodoluminescence microscopy, and fluid-inclusion studies. These data were integrated with routine core-analysis and petrophysical log data. Density and resistivity log data have been used to determine the precise oil saturation of each sample studied. The distributions of all potential controls on porosity and permeability, such as grain size, sorting, matrix clay content, and degree of bioturbation, the presence of grain coatings and dolomite cement, and the amount of quartz cement, have been assessed. The presence of primary oil inclusions within quartz cement shows that oil ingress into the Ula reservoir commenced prior to the onset of quartz cementation. Very fine–grained, matrix-rich, bioturbated, microquartz-cemented sandstones have uniformly low quartz-cement contents irrespective of oil saturation. Medium-grained, graded, matrix-poor, microquartz-poor sandstones have quartz cement ranging from 1% to greater than 17%, associated with core porosities of approximately 22% and 7%, respectively. Higher oil saturations equate to higher porosities and permeabilities in the medium-grained, graded, matrix-poor, microquartz-poor sandstones, which cannot be explained by any control other than the amount of quartz cement as a function of pore fluid type. Oil emplacement therefore appears to have inhibited quartz cementation at high oil saturations and can be viewed as an important control on reservoir quality. The significance of this study is that the presence of oil in a sandstone reservoir at the time that quartz cement was growing can have a considerable impact on reservoir quality. Models that seek to predict quartz cement and reservoir quality in sandstones need to account for the timing of oil emplacement compared with other diagenetic processes.

Diagenesis and reservoir characteristics analysis of the Late Triassic Xujiahe Formation tight gas sandstone in the northern Sichuan Basin, China

The Late Triassic Xujiahe Formation is a key target for tight gas in the northern Sichuan Basin. Thin section, scanning electron microscopy, X-ray diffraction, porosity and permeability analyses have been performed to delineate the diagenesis and reservoir characteristics of Xujiahe sandstone. The results show that the Xujiahe Formation contains feldspathic litharenite, litharenite, sublitharenite and quartzarenite sandstone. Sandstones of the Xujiahe Formation are characterized by low feldspar content and both secondary and micro-fracture porosity. Porosity and permeability analyses of 185 core samples show a broad but low porosity range from 0.79 to 10.43% (average 4.55%) and wide but low permeability range (0.0021–26.001 mD, average 0.449 mD). The higher permeabilities result from micro-fracturing. Strong mechanical compaction plays a more important role in reducing primary porosity of sandstone than cementation during eodiagenesis. Carbonate cement is detrimental to reservoir porosity. Early carbonate cement precipitated from depositional water during eodiagenesis can block primary pores while late carbonate cement formed during mesodiagenesis can fill secondary pores. Quartz cement shows a slight relationship with porosity and permeability. There is a positive relationship between grain-coating chlorite and porosity and permeability. The effect of diagenesis on the reservoir quality of Xujiahe tight gas sandstone is greater that depositional environment during deep burial.

Diagenetic constraints on the heterogeneity of tight sandstone reservoirs: A case study on the Upper Triassic Xujiahe Formation in the Sichuan Basin, southwest China

Abstract Heterogeneity is an essential feature of tight sandstones because it is directly related to reservoir quality. The Upper Triassic Xujiahe Formation in the Sichuan Basin was used as a case study to analyse the diagenetic constraints on the heterogeneity of tight sandstone reservoirs. The three main diagenetic processes of interest are mechanical compaction, cementation, and dissolution. A dissolution facies, quartz cement facies, and carbonate cement facies present sequentially from the centre to the margin of sand bodies. Abundant feldspars and rock fragments were dissolved to form secondary porosity or filled by carbonate cement. Authigenic chlorite coatings, generated from eogenesis to the deep burial stage, are thickest in high-porosity-samples. The δ 13 C of carbonate cement ranges from −10.56‰ to 1.15‰ (PDB), suggesting multiple sources of carbon, including carbonate fragments, early inorganic carbonate cement, and organically derived CO 2 . Based on δ 18 O, carbonate cementation occurred from 33 °C to 110 °C. Microthermometric data of aqueous inclusions indicate that quartz cement precipitated at a temperature range of 120 °C–140 °C. A summary model of the diagenetic constraints on the heterogeneity of sandstones was constructed. The spatial distribution of digenetic facies is controlled by differences in fluid flow velocity and pH. Fluids, especially hydrocarbons, migrated preferentially within the centre of sand bodies, and caused dissolution. Dissolution generated secondary porosity and provided materials for authigenic mineral precipitation. Carbonate fragments were better preserved and superimposed with later carbonate cement along the sandstone-mudstone boundary. Quartz overgrowths formed after carbonate cementation, and developed in the transition zone between the intervals of carbonate cementation and dissolution. Consequently, the reservoir quality of the Xujiahe sandstones decreases gradually moving from the centre to the margin of the sand bodies.

PETROGRAPHY AND DIAGENETIC HISTORY OF NAGRI FORMATION SANDSTONE IN DISTRICT BAGH AND MUZAFFARABAD, PAKISTAN

The petrographic analysis of Nagri Formation sandstone based on outcrop study and interpretation of thin sections with special emphasis on the diagenetic history from widely separated areas was accomplished. The calcite concreations, hematite leaching, petrified wood fossils, spheroid weathering, quartz filled joints and the meso scale drag folding has few geological significances. Interpretation of thin sections revealed that the sandstone is lithic arenite and lithic graywackes. The concavo-convex, sutured contacts and muscovite deformations indicates that the compaction of sand under lithostatic stress during early diagenesis. The pore water has widened the intergranular distance in some rocks by dissolving the fractured surfaces of carbonates and other grains, enhancing the concentration of carbonates in water at high pH. On the other hand, the silica dust formation can be attributed to the abrasion of quartz grains during compaction, alteration of feldspar to sericite and overgrowth on quartz by calcite under low pH of solution and pressure solution. The leaching and precipitation of hematite along fractures and thin coating around the grains indicates iron oxides paragenesis from chlorite and biotite in the area. The clay mineral authigenesis includes replacement along the cleaved and fractured feldspar and sericitation. Further elaborations indicate plastic deformations of hydrolytically weak quartz grains and deformations by tectonic upliftment, enhancing the permeability and reservoir quality of sandstone.

Reservoir quality, natural fractures, and gas productivity of upper Triassic Xujiahe tight gas sandstones in western Sichuan Basin, China

The main target for hydrocarbon exploration in the western Sichuan Basin in China is the tight gas sandstone reservoir of the Upper Triassic Xujiahe Formation. Sandstones of the Xujiahe Formation are characterized as tight with ultralow porosity, ultralow permeability, and intensive heterogeneity. In this study, various techniques, such as scanning electron microscopy, X-ray diffraction, cathodoluminescence microscopy, casting thin-section, and fluid inclusion thermometry, were employed to investigate the composition, sedimentary facies, diagenesis history, diagenetic intensity, natural fracture characteristics, and their impact on reservoir quality. The results showed that subaqueous distributary channels and mouth bars with low rock fragment content are favorable for pore preservation and secondary pore development. Except for the medium to strong dissolution intensity, chlorite rim growth is also important for the development of high quality reservoirs. Intraformational shear fractures and horizontal shear fractures associated with tectonic movement increase pore space and improve the capability of transmitting fluids. Differences in gas productivity could be attributed to differences in reservoir quality, which were controlled by the sedimentary environment, diagenetic intensity, and fracture characteristics. A significantly positive correlation was found between total porosity and gas productivity of the tight sandstones. The high density fracture distribution was found owing to the fault system and structural deformation zone, which resulted in high gas productivity. The research results were successfully applied to improve production efficiency in the Xujiahe tight gas sandstones, and could be applicable to other similar fields involving tight gas.

Diagenetic history and reservoir quality of tight sandstones: A case study from Shiqianfeng sandstones in upper Permian of Dongpu Depression, Bohai Bay Basin, eastern China

The upper Permian Shiqianfeng sandstones, located in the Dongpu Depression, Bohai Bay Basin, China, are fluvio-lacustrine deposits and have high content of pore-filling volcanic dust (average 7.93 vol %). This study focuses on diagenetic processes and reservoir quality of the tight sandstones based on different lithofacies. An integrated approach, such as core observation, X-ray diffraction, scanning electron microscopy, cathode luminescence, stable isotope analysis of carbon and oxygen compositions, electron microprobe analysis and fluid inclusion analysis, were utilized. The tight sandstones consist of subarkose and lithic subarkose, and have undergone significant diagenetic events, including compaction, quartz cementation, carbonate cementation (mainly calcite and ferrocalcite) and formation of authigenic clay minerals (i.e., chlorite rims, kaolinite and mixed-layer illite/smectite). The volcanic dust altered with increase of burial depth, resulting in the production of abundant silicic materials and depletion of metallic ions (i.e., Fe2+, Mg2+, Ca2+ and Mn2+). This process formed subhedral micro-quartz, pore-filling authigenic quartz, smectite and chlorite rims during the early diagenetic stage. Early-phase carbonate cements (calcite/ferrocalcite) occurred in several samples. They were also influenced by volcanic dust alteration, resulting in intrusive of Fe2+ and high contents of Mn2+ (average 12.5 mol %).Further alteration of volcanic dust at the mesogenetic stage can result in cementation of kaolinite and euhedral micro-quartz. Quartz overgrowth developed because of smectite-to-illite reactions and the alteration of volcanic dust. Late-phase carbonate cements (dolomite and ankerite) are rare. The present low porosity (average 6.17 vol %) and permeability (average 0.198 mD) of the Shiqianfeng sandstones mainly resulted from intense compaction, diverse cementation and pore-filling of volcanic dust. As strong hydrodynamic conditions of pore water, modification of reservoir quality in the conglomeratic sandstone and gritstone lithofacies (mainly distribute in braided channel) occurred by alteration of volcanic dust. Thick braided channel at the high structural position should be the focal point for the future exploration.

One-Trip Multizone Sand-Control-Completion System in the Gulf of Mexico Lower Tertiary

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27183, “Current State of the One-Trip Multizone Sand-Control-Completion System and the Conundrum Faced in the Gulf of Mexico Lower Tertiary,” by Bruce Techentien, Tommy Grigsby, and Thomas Frosell, Halliburton, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission. This paper provides perspective on the current state of multizone completion technology and issues encountered in the industry with developing a system that offers increased capabilities to meet the increasing challenges presented by the Lower Tertiary in the Gulf of Mexico (GOM). The multizone technology has proved to be an enabler for cost-efficient completions in the shallow-well environment and in the high-cost ultradeepwater environment requiring high-rate fracture-stimulation treatments. Lower Tertiary GOM The Lower Tertiary play is south and west of the Miocene area in the GOM and is, consequently, in deeper water. The Lower Tertiary is located approximately 175 miles offshore and is estimated at 80 miles wide and up to 300 miles long. Water depths are from 5,000 to 10,000 ft. Production targets are at depths of 10,000 to 30,000 ft subsea. The Tertiary trend is from 66 million to 38 million years old. Within the Lower Tertiary, the Lower Wilcox portion presents sheet to amalgamated-sheet sands considered to be part of a regional basin floor fan system. The Late Paleocene to Early Eocene (Wilcox equivalent) reservoirs are considered to be laterally extensive sheet sands that were deposited in deep water. These reservoirs are distributed across an area largely covered by the allochthonous Sigsbee salt canopy. It is this canopy that causes additional problems beyond merely the water depth and the well depth required to reach the reservoirs. These exploration plays depend on understanding the updip fluvial/deltaic stratigraphic architecture and the potential for partitioning of reservoir-quality sandstones across the depositional shelf into the slope and basin floor environments. The Lower Tertiary is estimated to contain up to 15 billion bbl of oil. Current State of Multizone Technology The Generation IV multizone system has been deployed successfully in the Lower Tertiary by multiple operators. To the authors’ knowledge, the multistage completion system and enhanced single-trip multizone fracturing systems had been installed in 10 wells as of the summer of 2015, with additional well installations planned. These systems are rated to 10,000 psi, and the enhanced single-trip multizone tool system offering an open-hole variant was installed in one five-zone completion.

Reservoir Characterization of Tight Sandstones Using Nuclear Magnetic Resonance and Incremental Pressure Mercury Injection Experiments: Implication for Tight Sand Gas Reservoir Quality

A series of experiments including porosity and permeability measurements, thin section and scanning electron microscopy (SEM) observations, incremental pressure mercury injection (IPMI), and nuclear magnetic resonance (NMR) were conducted to systematically characterize the pore structure of tight sandstone from the Lower Shihezi Formation of Permian (P2x) in the northeastern Ordos Basin, China. The influences of pore types, pore size distribution, and fractal characteristics on reservoir quality of tight sandstones are also investigated. Results show that the studied tight sandstones generally possess poor quality and complex pore structure. The porosity and permeability range from 4.08% to 17.56% (average 9.22%) and from 0.05 to 16.66 mD (average 2.49 mD), respectively. Five pore types were observed in thin section and SEM images: primary intergranular pores, intergranular dissolution pores, intragranular dissolution pores, micropores within clay aggregates, and microfractures. The pore throats are mainly hairy/fibrous, inhibiting the connectivity between pores. Three types of pore structures were identified in the mercury-injection curves and pore size distribution curves from the IPMI experiment and in the T2 relaxation time spectrum obtained by NMR. Both experiments yielded consistent classifications, and their combination was necessary to analyze the pore structure effectively. In general, permeability and porosity are positively related and depend on pore types. Large numbers of small pores confer high storage capacity, whereas small numbers of larger pores improve the flow capability. In the high porosity–permeability zone, larger pores also determine the storage capacity. The P2x tight sandstone is fractal, and macropores are more heterogeneous while micropores are more homogeneous. The fractal dimensions of macropores are good indicators of the reservoir quality of the P2x tight sandstone as larger fractal dimension values of macropores reflect poor reservoir quality.

Controlling factor analysis and prediction of the quality of tight sandstone reservoirs: A case study of the He8 Member in the eastern Sulige Gas Field, Ordos Basin, China

The He8 Member is the main producing zone in the Permian rocks of the eastern Sulige Gas Field in the Ordos Basin. It is characterized by low(10%≤Φ<15%) to ultralow(<10%) porosity and ultralow permeability(K < 1mD). To realize efficient exploration and development in this gas field, it is necessary to study the genesis of tight sandstone reservoirs and clarify the factors controlling reservoir development, in order to establish effective methods for reservoir quality prediction. The composition, pore structure, diagenetic type and strength of sandstone reservoirs, as well as their authigenic mineral contents and types, were analyzed. The techniques including casting thin sections, SEM, X-ray diffraction, high-pressure mercury intrusion, porosity-permeability tests and fluid inclusion homogenization temperature tests were used, in order to reconstruct the diagenetic and pore evolution history of the sandstone reservoirs. The effects of 12 sedimentary and diagenetic factors on porosity and permeability were analyzed using the stepwise multiple linear regression method, and a prediction model of reservoir quality (including both porosity and permeability) was constructed. The results show that the reservoir rock is dominated by litharenite, which accounts for 69.76%, followed by sublitharenite, which accounts for 26.15%. The reservoirs are characterized by low to ultralow porosity (porosity ranges from 0.29 to 16.6%, with an average of 7.51%), ultralow permeability (horizontal permeability ranges from 0.0065 mD to 5.21 mD, with most values being less than 0.4 mD). Displacement pressure is high (which ranges from 0.48 to 4.2 MPa, with an average of 1.48 MPa). Sandstone reservoirs are reformed by moderate compaction, moderate to strong cementation and weak dissolution. Cementation mainly occurs as quartz overgrowths, authigenic quartz, ferrocalcite, nonferrous calcite and clay minerals. Clay minerals are dominated by grain-coating chlorite, kaolinite and illite. Dissolution has little influence on reservoir quality. Reservoir porosity is mainly controlled by the contents of kaolinite, siliceous cement, illite, chlorite, and feldspar, as well as the degree of compaction. On the other hand, reservoir permeability is mainly controlled by the amount of siliceous cement, quartz, illite, and kaolinite, as well as the degree of compaction. The porosity and permeability were predicted using the equation established by multiple linear stepwise regression analysis, and good results were achieved. In this paper, the factors that influence the quality of the sandstone reservoir of the He8 Member in the eastern Sulige Gas Field were clarified, and a corresponding prediction model of reservoir quality was constructed. This model provides a new concept and method for quantitatively predicting the quality of tight sandstone reservoirs in other areas.

Quality grading system for tight sandstone reservoirs in the Quantou 4 Member, southern Songliao Basin, Northeast China

A grading system for tight sandstone reservoir quality is needed to predict tight oil enrichment areas and assess the resources. To explore the establishment of the grading system, a variety of research methods, such as rate-controlled mercury injection, conventional mercury injection, contact angle measurement, and the mechanical equilibrium principle, are integrated to determine the upper and lower limits of the porosity, permeability, and pore-throat radius of tight sandstones and to establish a quality grading system. Based on the porosity [Formula: see text], permeability [Formula: see text], and pore-throat size [Formula: see text] properties of the studied samples from the [Formula: see text] Member, five sandstone classes have been identified. Three of these classes are tight sandstone reservoirs and include (1) high-quality tight sandstone reservoirs ([Formula: see text], [Formula: see text], and [Formula: see text]), (2) effective tight sandstone reservoirs ([Formula: see text], [Formula: see text], and [Formula: see text]), and (3) low-quality tight sandstone reservoirs ([Formula: see text], [Formula: see text], and [Formula: see text]). Sandstones with [Formula: see text], [Formula: see text], and [Formula: see text] parameters higher than the high-quality tight reservoirs are deemed to be conventional reservoirs, whereas those with parameters lower than the low-quality tight sandstone reservoirs are considered as nonreservoir sandstones. It is also noted that oil saturation of the tight sandstone reservoirs correlates positively with the throat radius rather than with the pore size. High-quality tight sandstone reservoirs are usually developed in the distributary channel sand bodies near faults and/or fractures, and they are capable of producing more petroleum.

Generic hierarchy of sandstone facies quality and static connectivity: an example from the Middle-Late Miocene Miri Formation, Sarawak Basin, Borneo

A significant percentage of the world’s hydrocarbon reserves are found in shallow marine sandstone rocks. Understanding reservoir connectivity and quality of shallow-marine sandstones from outcrop analysis and facies characteristics is a challenging task. Here, we analyze well-exposed outcrops of the Miri Formation, Sarawak Basin, Borneo, to characterize reservoir properties (grain-size, petrography, pore-perm, and static connectivity) of different sandstone facies and to construct a 2D intermediate-scale model of sandstone distribution and connectivity. The outcrops, with lateral extent of ∼200–500 m, consist of mostly sandstone with mud-rich deposits including some isolated sand bodies. Field description in terms of facies distribution and dimensions of sand bodies and rock sampling for grain-size (Folk and Ward methods), petrographic (point count method for porosity, sorting, grain-size, and sand-mud %), and poro-perm (for porosity and permeability) analyses were performed to quantify and examine seven different types of sandstones facies, i.e., (i) hummocky cross-stratified sandstones (HCSS, ∼0.5–4 m thick), (ii) herringbone cross-bedded (HBCBS, ∼0.5–3 m thick), (iii) trough cross-bedded sandstones (TCBS, ∼0.5–2 m thick), (iv) wavy- to flaser-bedded (W-FBS, ∼1–3 m thick), (v) cross-bedded sandstone (CS), ∼0.5–3 m thick), (vi) bioturbated sandstone (BS, ∼1–5 m thick), and (vii) massive sandstone (MS, ∼0.5–2 m thick). Our results show that compared to other sandstone facies, sandstones of HCSS and HBCBS are better sorted, have minimal mud content, and display increasing vertical and lateral connectivity due to depositional patterns even in bioturbated rich sand. Sandstones of BS and CB are of poor quality in terms of grain sorting and poro-perm, while TCB and MS sandstone facies are of less lateral and vertical extent. On the basis of these results, a 2-D outcrop-based model is constructed that provide additional insights into the significance of small-scale heterogeneity and static connectivity of shallow marine sandstone deposits which can be an analogue for subsurface reservoir quality analysis.

The influence of climate on early and burial diagenesis of Triassic and Jurassic sandstones from the Norwegian–Danish Basin

AbstractClimate changes preserved in sandstones are documented by comparing the sediment composition and early diagenetic changes in sandstones deposited during arid to semi‐arid conditions, the Skagerrak Formation, with sandstones of the Gassum Formation deposited in a humid well‐vegetated environment. The study area covers the easternmost part of the Norwegian–Danish Basin, for which the Fennoscandian Shield functioned as sediment source area. The depositional environments of the formations, their distribution and burial depths are well‐constrained, facilitating a comprehensive petrographical and geochemical study complemented by porosity and permeability measurements of cores widely distributed in the basin (1700 to 5900 m burial depth). The Skagerrak Formation had an immature composition with more abundant feldspar, rock fragments and a larger variability in the heavy mineral assemblage when compared to the Gassum Formation, which was characterized by quartz and more stable heavy minerals. The arid to semi‐arid climate led to early oxidizing conditions under which abundant iron‐oxide/hydroxide coatings formed, while the evaporative processes occasionally resulted in caliche and gypsum precipitation. Under the humid climate, kaolinite precipitated due to leaching of feldspar and mica, and the abundant organic matter caused reducing conditions, which led to other Fe‐rich phases, i.e. pyrite, Fe‐chlorite and siderite. The inherited early diagenetic pore fluids and mineral assemblage also affect the mineral changes occurring during deeper burial, so dolomite preferentially formed in the sandstones deposited in an arid environment, while ankerite characterizes sandstones deposited under humid conditions. In addition to climate‐induced burial diagenetic changes, there are also temperature‐dependent phases, such as illite and quartz cement. Despite the same sediment source area remaining active during the entire period, the sediments that reached the Norwegian–Danish Basin were immature during the arid interval, although mature during the humid period. This has implications for provenance investigations as well as diagenetic investigations of sandstone reservoir quality.

Origins of authigenic minerals and their impacts on reservoir quality of tight sandstones: Upper Triassic Chang-7 Member, Yanchang Formation, Ordos Basin, China

ABSTRACTReservoir quality is critical for sweet-spot evaluation in tight sandstone plays, but few studies have focused on the origin of authigenic minerals in tight sandstones and their impact on reservoir quality. This study integrates petrographic analysis, carbon and oxygen isotopic data and mercury injection capillary pressure data of the Upper Triassic Chang-7 tight sand reservoir samples in the Ordos Basin, China to understand the origin of authigenic minerals and the impact of authigenic minerals on reservoir quality. Carbonate minerals, including calcite, ferroan calcite and dolomite, and kaolinite, are the major authigenic minerals in the Chang-7 sandstone. They were derived from the chemical diagenetic alteration of detrital feldspar and biotite, with the involvement of ions that are believed to be primarily from the connate water in interstitial pore space of the interbedded mudstones. Meteoric water and organic fluids from hydrocarbon generation may also have been involved in the alteration processes of the minerals in the Chang-7 tight sandstone. The origin of kaolinite indicates that the porosity was increased by dissolution of detrital grains, offsetting the porosity loss from burial compaction. Authigenic minerals appear to have a weak correlation with pore structure, suggesting that the pore structure of the Chang-7 tight sandstone is not only controlled by major authigenic minerals but also affected by other geological factors.

Diagenesis and reservoir quality in tight gas sandstones: The fourth member of the Upper Triassic Xujiahe Formation, Central Sichuan Basin, Southwest China

Mineralogical, petrographic, and geochemical analyses were performed to investigate the sandstone composition and texture, pore system, and diagenetic minerals of Upper Triassic sandstones in the Central Sichuan Basin, Southwest China. The results show that authigenic quartz, clay minerals, and carbonates are the main pore‐filling constituents. The pore systems consist of intergranular porosity, secondary porosity, microporosity, and microfractures. Loss of depositional porosity is greater due to compaction than to cementation. Eodiagenesis includes mechanical compaction, precipitation of early calcite cements, kaolinite, and smectite, and leaching of feldspars by meteoric water. Mesodiagenesis consists of compaction, framework grain dissolution, and subsequent precipitation of illite, quartz, and late carbonate cements. Six lithofacies were identified on the basis of petrographic analyses, namely, (a) argillaceous sandstones; (b) poorly sorted sandstones; (c) quartz‐cemented sandstones; (d) carbonate‐cemented sandstones; (e) clay‐mineral‐cemented sandstones, and (f) clean sandstones with abundant secondary porosity. The best reservoir‐quality rocks have high percentages of detrital quartz but low percentages of matrix, quartz, and carbonate cement. Differences in textural and compositional attributes of various lithofacies significantly affect porosity‐depth trends. The diagenetic evolution pathways and reservoir‐quality prediction models of various lithofacies are reconstructed by integrated petrographic data. This work provides insights into describing the different lithofacies by petrographic analysis and helps to investigate how detrital composition and texture influence the diagenesis and reservoir quality evolution in tight gas sandstones.

An interdisciplinary approach to reservoir characterisation; an example from the early to middle Eocene Kaimiro Formation, Taranaki Basin, New Zealand

The Kaimiro Formation is an early to middle Eocene, NE-SW trending reservoir fairway in Taranaki Basin, and comprises a range of coastal plain through to shallow marine facies. A time of regional transgression is observed across the Paleocene–Eocene transition, which is linked to a general global warming trend and to regional thermal relaxation-related subsidence in New Zealand. The earliest Eocene transgressive deposits pass upwards into a series of cyclically stacked packages, interpreted as 3rd and 4th order sequences. Maximum regression occurred within the early Eocene and was followed by punctuated retrogradational stacking patterns associated with shoreline retreat and subsequent regional transgression in the middle Eocene.The Kaimiro Formation is considered a good reservoir target along most of the reservoir fairway, which can largely be attributed to a consistently quartz-rich, lithic-poor composition and reasonably coarse sand grain size. Correlations demonstrate that within the early Eocene the main reservoir facies are channel-fill sandstones overlying candidate sequence boundaries in paleoenvironmentally landward (proximal) settings, and upper shoreface/shoreline sandstones in relatively basinward (distal) settings. Middle Eocene reservoir facies are not represented in distal wells due to overall transgression at this time, yet they form a significant target in more proximal well locations, particularly on the Taranaki Peninsula.Depositional facies is one of the principal controls on sandstone reservoir quality. However, while reservoir facies have been proven along the length of the reservoir fairway, it is evident that diagenesis has significantly impacted sandstone quality. Relatively poor reservoir properties are predicted for deeply buried parts of the basin (maximum burial >4.5 km) due to severe compaction and relatively abundant authigenic quartz and illite. In contrast, good reservoir properties are locally represented in reservoir facies where present-day burial depths are <4 km due to less severe compaction, cementation and illitisation. Within these beds (<4 km) the presence of locally occurring authigenic grain-coating chlorite (shallow marine facies) and/or well-developed secondary porosity are both favourable to reservoir quality, while pervasive kaolinite and/or carbonate are both detrimental to reservoir quality.These results illustrate how an interdisciplinary approach to regional reservoir characterisation are used to help reduce risk during prospect evaluation. Assessment of both reservoir distribution and quality is necessary and can be undertaken through integrated studies of facies, sequence stratigraphy, burial modelling and petrography.

Kilometer-scale fault-related thermal anomalies in tight gas sandstones

Upper Carboniferous sandstones make one of the most important tight gas reservoirs in Central Europe. This study integrates a variety of geothermometers (chlorite thermometry, fluid inclusion microthermometry and vitrinite reflection measurements) to characterize a thermal anomaly in a reservoir outcrop analog (Piesberg quarry, Lower Saxony Basin), which is assumed responsible for high temperatures of circa 300 °C, deteriorating reservoir quality entirely. The tight gas siliciclastics were overprinted with temperatures approximately 90–120 °C higher compared to outcropping rocks of a similar stratigraphic position some 15 km to the west. The local temperature increase can be explained by circulating hydrothermal fluids along the fault damage zone of a large NNW-SSE striking fault with a displacement of up to 600 m in the east of the quarry, laterally heating up the entire exposed tight gas sandstones. The km-scale lateral extent of this fault-bound thermal anomaly is evidenced by vitrinite reflectance measurements of meta-anthracite coals (VRrot ∼ 4.66) and the temperature-related diagenetic overprint. Data suggest that this thermal event and the associated highest coalification was reached prior to peak subsidence during Late Jurassic rifting (162 Ma) based on K-Ar dating of the <2 μm fraction of the tight gas sandstones. Associated stable isotope data from fluid inclusions, hosted in a first fracture filling quartz generation (T ∼ 250 °C) close to lithostatic fluid pressure (P ∼ 1000 bars), together with authigenic chlorite growth in mineralized extension fractures, demonstrate that coalification was not subject to significant changes during ongoing burial. This is further evidenced by the biaxial reflectance anisotropy of meta-anthracite coals. A second event of quartz vein formation occurred at lower temperatures (T ∼ 180 °C) and lower (hydrostatic) pressure conditions (P ∼ 400 bars) and can be related to basin inversion. This second quartz generation might be associated with a second event of illite growth and K-Ar ages of 96.5–106.7 Ma derived from the <0.2 μm fraction of the tight gas sandstones.This study demonstrates the exploration risk of fault-bound thermal anomalies by deteriorating entirely the reservoir quality of tight gas sandstones with respect to porosity and permeability due to the cementation with temperature-related authigenic cements. It documents that peak temperatures are not necessarily associated with peak subsidence. Consequently, these phenomena need to be considered in petroleum system models to avoid, for example, overestimates of burial depth and reservoir quality.

Feldspar alteration and Fe minerals: origin, distribution and implications for sandstone reservoir quality in estuarine sediments

Abstract The occurrence and distribution of minerals in modern sedimentary systems hold many clues to help unravel the origin and distribution of reservoir quality-controlling minerals in ancient and deeply buried sandstones, but few quantitative studies have been undertaken. Here we have used a range of techniques including X-ray diffraction, scanning electron microscopy and fully automated mineralogical QEMSCAN analysis to provide a comprehensive understanding of mineral composition and distribution within the post-glacial, clastic sediments of the Ravenglass Estuary, NW England. The Ravenglass Estuary is fed by two main rivers: one drains a granite-dominated hinterland, the other drains a hinterland that contains andesite and Triassic red bed sandstones. The granite-supplied arm has slightly more quartz-rich and Fe mineral-poor sediment than the andesite- and red bed-supplied sediment. The provenance signals are muted for feldspar and mica minerals heavy-mineral garnet populations seem to be sensitive to provenance. Detrital K-feldspar grains are preferentially associated with illite-dominated clay mineral coats, whereas all plagioclase mineral grains are preferentially associated with kaolinite-dominated clay mineral coats. This can be explained by rapid early diagenesis in the sediment with K-feldspar grain surfaces replaced by illite and plagioclase grain surfaces replaced by kaolinite. The andesite- and red bed-supplied sediment contains twice the amount of Fe minerals, which are dominated by chlorite, than the granite-supplied sediment. Chlorite rarely is associated with grain coatings on feldspar grains, possibly because it is predominantly a detrital mineral. Detrital Fe minerals seem to be locally replaced by pyrite due to bacterial sulphate reduction, suggesting that some early diagenetic processes may serve to lock away iron and prevent it from creating Fe-rich clay minerals.

Impact of diagenesis on reservoir quality and heterogeneity of the Upper Triassic Chang 8 tight oil sandstones in the Zhenjing area, Ordos Basin, China

Reservoir quality and heterogeneity are critical risk factors in tight oil exploration. The integrated, analysis of the petrographic characteristics and the types and distribution of diagenetic alterations in the Chang 8 sandstones from the Zhenjing area using core, log, thin-section, SEM, petrophysical and stable isotopic data provides insight into the factors responsible for variations in porosity and permeability in tight sandstones. The results indicate that the Chang 8 sandstones mainly from subaqueous distributary channel facies are mostly moderately well to well sorted fine-grained feldspathic litharenites and lithic arkose. The sandstones have ultra-low permeabilities that are commonly less than 1 mD, a wide range of porosities from 0.3 to 18.1%, and two distinct porosity-permeability trends with a boundary of approximately 10% porosity. These petrophysical features are closely related to the types and distribution of the diagenetic alterations. Compaction is a regional porosity-reducing process that was responsible for a loss of more than half of the original porosity in nearly all of the samples. The wide range of porosity is attributed to variations in calcite cementation and chlorite coatings. The relatively high-porosity reservoirs formed due to preservation of the primary intergranular pores by chlorite coatings rather than burial dissolution; however, the chlorites also obstruct pore throats, which lead to the development of reservoirs with high porosity but low permeability. In contrast, calcite cementation is the dominant factor in the formation of low-porosity, ultra-low-permeability reservoirs by filling both the primary pores and the pore throats in the sandstones. The eogenetic calcites are commonly concentrated in tightly cemented concretions or layers adjacent to sandstone-mudstone contacts, while the mesogenetic calcites were deposited in all of the intervals and led to further heterogeneity. This study can be used as an analogue to understand the variations in the pathways of diagenetic evolution and their impacts on the reservoir quality and heterogeneity of sandstones and is useful for predicting the distribution of potential high-quality reservoirs in similar geological settings.