Feldspar Dissolution Research Articles

Thermodynamic characteristics and mineral dissolution model of the H2O-CO2-CaCO3-Albite-SiO2 system in sedimentary basins

Diagenesis controls the formation, evolution, and distribution of deep-buried sandstone reservoirs in sedimentary basins. The essence of diagenesis is the transformation of substances between different phases (solid, gas and liquid phases) and the migration of materials transported by formation water. Fluids transport in deep-buried formations in sedimentary basins is generally slow, which lead the reaction system is in a near-equilibrium-to-equilibrium state. In this context, thermodynamics can be employed to calculate the solubility and characterize the occurrences of various minerals in different states, which can help reveal the genetic mechanism of secondary pores in the deep-buried rocks of sedimentary basins. In this study, we investigate the types and contents of particles in the aqueous solutions in the H2O-CO2-CaCO3-Albite-SiO2 system under different temperature and pressure conditions. Specifically, the Gibbs free energy of formation of minerals and gases are calculated based on the constant-pressure specific heat model; the apparent standard molal Gibbs free energy of different ions in fluids are computed using the HKF model; the equilibrium constants of different reactions are calculated according to the Gibbs function; the contents of different types of particles are computed based on the charge balance principle in the aqueous solution. The results show that the contents of various particles in the aqueous solution are mainly controlled by temperature and CO2 partial pressure, while they are rarely impacted by the total pressure. Different ions are demonstrated to have different responses to temperature changes. Specifically, types of Ca- and C-containing particles in the aqueous solution are closely related to temperature, while those of Al- and Si-rich particles are rarely changed as temperature varies. The CO2-rich fluid migration environment that results from hydrocarbon generation can be regarded as an open system for the dissolution of calcite, while it is a closed-to-semi-closed system for the dissolution of quartz and feldspar. The content of secondary pores is demonstrated to be determined by the solubility of various particles in the aqueous solution as well as the rate and duration of fluid migration, while the distribution patterns and ranges of secondary pores are controlled by responses of various particles in the solution to temperature and pressure changes.

Integrated sedimentological and petrophysical characterization of the Lower Cenomanian clastic Bahariya reservoir in Abu Gharadig Basin, Western Desert, Egypt

The Lower Cenomanian siliciclastic Bahariya Formation represents one of the main producing reservoirs in the north Western Egyptian Desert. A few previous subsurface studies exist that integrated core, petrographic, scanning electron microscope (SEM), and X-ray diffraction (XRD) analyses to study the reservoir quality of this formation. Consequently, the present study is carried out to fill this gap and outline the sedimentological, petrophysical, and digenetic characteristics of this siliciclastic reservoir in addition to the impact of these characteristics on reservoir quality. Detailed microscopic examination, XRD, SEM, and conventional core analyses were applied on the available cores. Five distinct microfacies types were petrographically identified, belonging to the arenite and wacke facies. These microfacies are represented by quartz arenite, subarkose, argillaceous quartz wacke, calcareous quartz wacke, and calcareous feldspathic greywacke. The formation was subjected to compaction and was affected by four types of cement; silica, calcite, kaolinite, and pyrite cementation. It has three types of porosities: primary intergranular and secondary porosity (microporosity and dissolution). The studied core samples of the Bahariya Formation are discriminated into two reservoir rock types (RRTs) and exhibit extreme heterogeneity. RRT1 comprises mainly quartz arenite, whereas RRT2 comprises quartz wacke. RRT1 has a reservoir quality of tight to poor due to porosity/permeability occluding by the different cementations.In contrast, RRT2 has a reservoir quality of tight to fair, despite the presence of the clay matrix. The tight to fair quality is possibly attributed to the dissolution of feldspars and authigenic clays. The Lower Cenomanian reservoir is considered a second cycle deposition and represents a tight to a fair quality reservoir in the studied wells.

Use of scratch tracking method to study the dissolution of alpine aggregates subject to alkali silica reaction

Alkali silica reaction (ASR) can significantly affect the service life of concrete. The dissolution of aggregates has a direct impact on gel formation and thus on the macroscopic expansion. The conventional expansion tests and other investigations confirmed ASR reactivity of three aggregates from different locations in Switzerland. The reactive minerals within alpine and composite aggregates were identified using an innovative scratch-tracking method. This method helps to study aggregate dissolution if measuring the amount of released Si is not enough, because: several minerals release Si or Al and/or new phases are probable to form during dissolution experiment. The scratch-tracking method on theses alpine aggregates showed faster dissolution of feldspars and quartz while muscovite was hardly affected. The dissolution of the aggregates in solution confirmed these differences between minerals.

Reservoir quality and its controlling diagenetic factors in the Bentiu Formation, Northeastern Muglad Basin, Sudan

The Abu Gabra and Bentiu formations are widely distributed within the interior Muglad Basin. Recently, much attention has been paid to study, evaluate and characterize the Abu Gabra Formation as a proven reservoir in Muglad Basin. However, few studies have been documented on the Bentiu Formation which is the main oil/gas reservoir within the basin. Therefore, 33 core samples of the Great Moga and Keyi oilfields (NE Muglad Basin) were selected to characterize the Bentiu Formation reservoir using sedimentological and petrophysical analyses. The aim of the study is to de-risk exploration activities and improve success rate. Compositional and textural analyses revealed two main facies groups: coarse to-medium grained sandstone (braided channel deposits) and fine grained sandstone (floodplain and crevasse splay channel deposits). The coarse to-medium grained sandstone has porosity and permeability values within the range of 19.6% to 32.0% and 1825.6 mD to 8358.0 mD respectively. On the other hand, the fine grained clay-rich facies displays poor reservoir quality as indicated by porosity and permeability ranging from 1.0 to 6.0% and 2.5 to 10.0 mD respectively. A number of varied processes were identified controlling the reservoir quality of the studies samples. Porosity and permeability were enhanced by the dissolution of feldspars and micas, while presence of detrital clays, kaolinite precipitation, iron oxides precipitation, siderite, quartz overgrowths and pyrite cement played negative role on the reservoir quality. Intensity of the observed quartz overgrowth increases with burial depth. At great depths, a variability in grain contact types are recorded suggesting conditions of moderate to-high compactions. Furthermore, scanning electron microscopy revealed presence of micropores which have the tendency of affecting the fluid flow properties in the Bentiu Formation sandstone. These evidences indicate that the Bentiu Formation petroleum reservoir quality is primarily inhibited by grain size, total clay content, compaction and cementation. Thus, special attention should be paid to these inhibiting factors to reduce risk in petroleum exploration within the area.

Chemical characteristics of groundwater and source identification in a coastal city.

A coastal city is studied in this paper. Based on 42 groundwater sampling points, a Piper diagram, the Shukarev classification, the Pearson correlation analysis, Gibbs plots and the ion proportional coefficient method are used to analyze the chemical characteristics and material source. The results show that the groundwater quality in the study area varies greatly from north to south. In the northern inland area (AREA I), the main anions and cations are and Ca2+, and the hydrochemical characteristics are mainly HCO3 − Ca, HCO3 ⋅ SO4 − Ca and HCO3 − Mg. The ion concentration distribution is uniform, and the groundwater quality is good. By using Gibbs plots and the ion proportional coefficient method, the main source of ions is the dissolution of potassium feldspar, albite and carbonate rock. In contrast, in the southern coastal area (AREA II), the main anions and cations are Cl− and Na+, and the hydrochemical characteristics are mainly Cl − Na. The ion concentration distribution presents a strong spatial difference. The closer the groundwater sampling point is to seawater, the worse the overall groundwater quality. Evaporite dissolution, seawater intrusion, cation exchange effects and human activities are the main factors affecting the groundwater quality in this area. In conclusion, the groundwater quality in northern inland area (AREA I) is better, mainly controlled by the dissolution of rocks. The groundwater quality in southern coastal area (AREA II) changes greatly, mainly controlled by seawater.

REY Patterns and Their Natural Anomalies in Waters and Brines: The Correlation of Gd and Y Anomalies

Rare earths and yttrium (REY) distribution patterns of the hydrosphere reveal systematic correlations of Gd and Y anomalies besides the non-correlated redox-dependent Ce and Eu anomalies. Eu anomalies are inherited by dissolution of feldspars in igneous rocks, whereas Ce, Gd and Y anomalies develop in aqueous systems in contact with minerals and amorphous matter. Natural, positive Gd and Y anomalies in REY patterns characterize high-salinity fluids from the Dead Sea, Israel/Jordan, the Great Salt Lake, USA, the Aral Sea, Kazakhstan/Uzbekistan, ground- and surface water worldwide. Extreme Gd anomalies mostly originate from anthropogenic sources. The correlation of Gd and Y anomalies at low temperature in water bodies differ from geothermal ones. In nature, dynamic systems prevail in which either solids settle in water columns or water moves through permeable sediments or sedimentary rocks. In both cases, the anomalies in water develop due to repeated equilibration with solid matter. Thus, these anomalies provide information about the hydrological history of seawater, fresh groundwater and continental brines. When migrating, the interaction of aqueous phases with mineral surfaces leads to increasing anomalies because the more hydrophillic Gd and Y preferentially remain in the aqueous phase compared to their nearest neighbors. The correlation coefficients between Gd and Y anomalies in groundwater is 0.5–0.9. In lakes and oceans, it is about 0.1–0.8, under anomalous conditions it can increase to 1.

The role of the Mid-Cimmerian Unconformity on the quality of the underlying Skagerrak sandstone reservoir in the Kittiwake Field, central North Sea

The central aim of this paper is to address the role of unconformities in affecting reservoir quality. Do they facilitate diagenesis that leads to either enhanced or reduced porosity through dissolution or cementation? Or, do they have little effect? We have investigated the Late Triassic Skagerrak sandstone reservoir underlying the Mid-Cimmerian Unconformity in the Kittiwake Field, central North Sea. There is strong evidence for the development of secondary porosity through the dissolution of unstable silicate minerals, primarily feldspars. This includes the presence of oversized pores, partial dissolution of framework grains, and complete dissolution of grains leaving remnant grain margins and partially filled cores. This dissolution as a late-stage event is demonstrated by the complete lack of compaction effects on the secondary pores and diagenetic products despite present burial depths in excess of 3000 m. These observations, coupled with an absence of systematic trends linked to the unconformity surface in respects of reservoir porosity, feldspar amount and dissolution, and kaolinization, lead to the conclusion that there has been no effect of the Mid-Cimmerian Unconformity on reservoir quality in the Kittiwake Field. There is no evidence for leaching or cementation linked to meteoric water influx either shortly after deposition or following the uplift and exposure, which led to development of the Mid-Cimmerian Unconformity. Instead, we propose that the late-stage dissolution of feldspar and generation of secondary porosity are most likely related to the influx of organic acids and carbon dioxide generated either from thermogenic maturation of the source rock or from biodegradation of oil within the reservoir near the oil-water contact (OWC) transition zone.

Impact of diagenesis on the reservoir rock quality of the Cachiri Group tight sandstones in Cesar sub basin (Colombia): A case of study from ANH-CR-MONTECARLO 1X well

Basal sandstones of the studied interval in the Cesar Sub-basin (Colombia), have reported manifestations of hydrocarbons in the ANH CR MONTECARLO 1X well, so they have been studied as a possible unconventional reserve rock. Diagenesis plays an important role in assessing the quality of a reservoir rock, so this study presents an analysis of the diagenetic evolution in basal sandstones of the Cachiri Group in Cesar Sub-basin. Based on the petrographic and core data, diagenetic products have been determined, and how these have intervening in the quality as a possible reservoir rock. These sandstones with fine to medium grain sizes, poor to the moderate selection, are classified as arches and lithic arches. Core data porosity reveals a range between 0.06 and 2.1% and a permeability of 0.02–0.049 millidarcys (mD). These low porosity and permeability values are mainly controlled by the mechanical compaction process. Cement precipitation (carbonate, silica) also leads to a reduction in the porosity and permeability of these rocks. Other diagenetic products that can be evidenced in these sandstones are related to the metasomatism of feldspar grains by carbonate and ferrous carbonate, and dissolution of feldspar and lithic fragments.

The Origin of Quartz Cement in the Upper Triassic Second Member of the Xujiahe Formation Sandstones, Western Sichuan Basin, China

High-precision in situ δ18O values obtained using secondary ion mass spectrometry (SIMS) for μm-size quartz cement are applied to constrain the origin of the silica in the deep-buried Upper Triassic second member of Xujiahe Formation tight sandstones, western Sichuan Basin, China. Petrographic, cathodoluminescence (CL), and fluid inclusion data from the quartz cements in the Xu2 sandstones indicate three distinct, separate quartz precipitation phases (referred to as Q1, Q2, and Q3). The Q1 quartz cement was formed at temperatures of approximately 56–85 °C and attained the highest δ18O values (ranging from 18.3 to 19.05‰ Vienna Standard Mean Ocean Water (VSMOW)). The Q2 quartz cement was generated at temperatures of approximately 90–125 °C, accompanying the main phase of hydrocarbon fluid inclusions, with the highest Al2O3 content and high δ18O values (ranging from 15 to 17.99‰ VSMOW). The Q3 quartz cement was formed at temperatures of approximately 130–175 °C, with the lowest δ18O values (ranging from 12.79 to 15.47‰ VSMOW). A portion of the Q2 and Q3 quartz cement has a relatively high K2O content. The dissolution of feldspar and volcanic rock fragments was likely the most important source of silica for the Q1 quartz cement. The variations in δ18O(water) and trace element composition from the Q2 quartz cement to the Q3 quartz cement suggest that hydrocarbon emplacement and water-rock interactions greatly altered the chemistry of the pore fluid. Feldspar dissolution by organic acids, clay mineral reactions (illitization and chloritization of smectite), and pressure dissolution were the main sources of silica for the Q2 and Q3 quartz cements, while transformation of the clay minerals in the external shale unit was a limited silica source.

Diagenetic Control on the Distribution of Porosity within the Depositional Facies of Proterozoic Rajgarh Formation, Alwar Sub-basin, Northeastern Rajasthan

Abstract The sandstones of the Proterozoic Rajgarh Formation are texturally immature and compositionally sub-mature quartz arenite to arkose in composition. The reservoir quality of sandstones is strongly influenced by depositional facies and various types of diagenetic modifications. A significant reduction in primary porosity in the studied sandstone is mainly due to high mechanical compaction followed by chemical compaction rather than the cementation process. Arkose from the river-dominated estuary facies show infiltrated clay coating, feldspar dissolution, iron-oxide cementation, leaching of detrital by iron-oxide cement, kaolinization of feldspar, the fracturing of detrital, partial albitization and folding of mica. The pore-lining clay has helped in retaining primary porosity, and leaching and dissolution processes were the main process generating secondary porosity in this facies. Tidal flat sub-arkose petrofacies display compaction of micas and unstable rock fragments into the pseudomatrix, expansion of muscovite by kaolinite, and pore-filling silty matrix that occupied intergranular spaces. Quartz-arenite petrofacies from shallow marine deposit show grain replacive kaolinite, pyrite precipitation, glauconite authigenesis, muscovite bending, albitization of plagioclase, feldspar overgrowths, dissolution, and grain fracturing. Pyrite plays a significant role in the reduction of both primary and secondary porosity by precipitating in intergranular spaces and in dissolution voids of feldspar. Moreover, fractures in detrital act as a second cycle porosity generation process in the shallow marine petrofacies. The linking between the diagenetic processes and depositional facies provides a geologic model for hydrocarbon exploration through reservoir quality prediction. Therefore, the petrographic observations indicate quartz-arenite (shallow marine facies) and sub-arkosic sandstones (tidal flat facies) are the least suitable latent reservoir because of their lowest primary and secondary porosity and unconnected pore spaces. Arkosic (river-dominated estuary facies) compositions are considered to be appropriate frameworks for potential reservoir rocks. This study reveals that the depositional environment largely controls the diagenetic pathways and hence, influences the reservoir quality.

Evolution Mechanism of Differential Diagenesis Combination and Its Effect on the Reservoir Quality in the Tight Sandstone: A Case from the Lower Shihezi Formation in the Hangjinqi Area of Ordos Basin, China

Abstract The physical property heterogeneity of tight sandstones was mainly caused by complex alteration of various diagenesis combinations during burial process. However, diagenetic evolution of different diagenesis combinations which generally result in the strong difference and heterogeneity of physical property and pore structure is rarely well understood. The Middle Permian lower Shihezi Formation is one of the most important tight gas sandstone reservoirs in the Hangjinqi area of Ordos Basin, China. The reservoir heterogeneity of lower Shihezi Formation, which was caused by the differential diagenesis combination, is crucial to efficient exploration and development. Evolution mechanism of differential diagenesis combination and its effect on the reservoir quality in the tight lower Shihezi Formation sandstone in the Hangjinqi area of Ordos Basin was investigated by means of thin-section description, cathodoluminescence (CL) imaging, X-ray diffraction (XRD), scanning electron microscopy (SEM), and homogenization temperature of fluid inclusions. The lower Shihezi Formation sandstones can be divided into four diagenesis combination types according to the reservoir characteristics and diagenetic relationship. The main diagenetic sequence was mechanical compaction-chlorite rim-early pore-filling calcite cementation-dissolution-authigenic kaolinite-quartz cementation-late calcite cementation. Differential diagenesis combination was mainly controlled by the petrological characteristics, microfacies, and fault. Low content of rock fragment and high content of detrital quartz were beneficial to the compaction resistance and cementation. The moderate content of pore-filling calcite was conducive to pore space protection and feldspar dissolution. The faults control dissolution and differential diagenesis combination by influencing the migration of acid fluids. Moderate compaction-moderate cementation-moderate dissolution type (BBB type) and weak compaction-moderate cementation-strong dissolution type (CBA type) were in favour of high-quality reservoir development.

Oilfield Water and Favorable Petroleum Exploration Targets for the Triassic Baikouquan Formation in the Slope of Mahu Depression, Junggar Basin

In this paper, we attempt to clarify the relationships between oilfield water and hydrocarbon distribution of the Triassic Baikouquan Formation, in the slope zone of Mahu depression, Junggar Basin, NW China, based on oilfield water mineralization degrees, diagenesis analysis, formation pressure coefficients, burial history, and thermal evolution processes. The results show that the study area can be divided into four zones according to the mineralization degrees, that is, (1) zone I: NaHCO3 + Na2SO4 type water with residual intergranular pores, porosity usually higher than 10%. The strata of zone I are generally buried shallow and influenced by leaching from atmospheric precipitation. This area contains normal edge and bottom water and has normal formation pressure coefficients (average 1.12); (2) zone II: CaCl2 type water with mainly compaction diagenesis, porosity usually less than 7% and high formation pressure coefficients (average 1.41); (3) zone III: NaHCO3 + CaCl2 type oilfield water with mainly feldspar dissolution diagenesis, porosity usually greater than 9% and high formation pressure coefficients (average 1.53); and (4) zone IV: CaCl2 type water, mainly compacted diagenesis with a few intergranular and feldspar dissolved pores, and high formation pressure coefficients (average 1.58). The mineralization degrees of the oilfield water in zone II, III, and IV are relatively high. The appearance of NaHCO3 type water in the deeply buried areas is usually related to oil and gas charging. Therefore, within the strata, deeply-buried areas (e.g., zone III), where NaHCO3 type water has been developed, are favorable targets for oil and gas exploration.

Sedimentary environment constraints on the diagenetic evolution of clastic reservoirs: Examples from the Eocene “red-bed” and “gray-bed” in the Dongying Depression, China

The diagenetic characteristics and differences between the Eocene red-bed sandstone deposited in an arid environment and gray-bed sandstone deposited in a relatively humid environment were investigated systematically by an integrated analysis of petrography, X-ray diffraction, carbon and oxygen stable isotopes and fluid inclusion microthermometry. Strong eodiagenetic calcite and gypsum/anhydrite cementation occurred at the boundary of the Eocene red-bed sandstone, while the centre of the red-bed sandstone was characterized by relatively strong quartz dissolution and weak mesodiagenetic feldspar dissolution and ferro-carbonate cementation. Eodiagenetic calcite cementation at the boundary of the gray-bed sandstone and quartz dissolution were relatively weak, while the carbonate cemented zone at the boundary of the gray-bed sandstone was strengthened by mesodiagenetic ferro-carbonate cement. Relatively strong feldspar dissolution and ferro-carbonate cementation occurred in the centre of gray-bed sandstone beds. By comparing the diagenetic differences between the red-bed sandstones and gray-bed sandstones, it is shown that sedimentary environment had an obvious influence on reservoir diagenetic evolution and reservoir properties through influencing the chemical properties of connate water, the transformation rate and degree of clay minerals in interbedded mudstone, and the properties of diagenetic fluids during burial process.

Sedimentology, petrography, hydraulic flow units, and reservoir quality of the bayhead delta reservoirs: Late Messinian Qawasim formation, Nile Delta, Egypt

Bayhead sandstone reservoirs are challenging due to their complexities and limited examples. This paper focused on the characteristics of the bayhead sandstone reservoirs and their heterogeneities based on an integrated sedimentological, petrographical, and petrophysical aspects that controls the exploration and development for these reservoirs. This study uses an example from Manzala Gas Field (Eastern Nile Delta). In this study, the sedimentological and petrographical analyses are employed to understand the internal textures and architecture as well as meso- and microscopic heterogeneities of the bayhead delta reservoirs. This is integrated with the petrophysical characteristics and neural network techniques to characterize hydraulic flow units of bayhead delta reservoir using core, borehole image, and log data. The bayhead delta (bay fill) reservoir consists of five main sedimentary sub-environments include main distributary channel, proximal and distal crevasse splays, and crevasse channels, as well as bayhead delta lobes. The distributary channel represents the highest reservoir quality (units 3 and 4), followed by crevasse channel (unit 3 and 2); bayhead delta front lobes (units 2 and 1), and the lowest quality crevasse splays (unit 1). On microscale, the bayhead delta reservoir is characterized by wide spectrum of lithofacies from quartz arenite to feldspathic wacke. The depositional setting is important controlling factor on the reservoir quality that altered by the diagenetic processes. They include the anhydrite, quartz, carbonate, and chlorite, and kaolinite cements as well as dissolution of quartz, feldspar, bioclast, and carbonate grains. This study enhances the understanding of the of the bayhead distributive system heterogeneities and prediction of bay fill facies reservoirs to improve the exploration and development of that targets.

Geochemical reactions and alteration of pore architecture in saturated shale after injection of stimulation fluid

Pore architecture regulates fluid flow between unconventional shale reservoir and hydraulically-induced fractures. Imbibition of stimulation fluid may change this architecture and alter hydrocarbon flow. Hydrothermal experiments were conducted at reservoir conditions (125 °C, 45 MPa) to test two hypotheses: 1) Shale, not stimulation fluid, dominates the geochemistry of an unconventional reservoir containing formation water; and 2) Mineral dissolution and precipitation induced by stimulation fluid is transient and manifests across micro-, meso-, and macro-scales of pore architecture. Experiments replicated a shut-in well in the Cretaceous Baxter Shale, Green River Basin, Wyoming USA. Stimulation fluid was injected into one experiment after formation water (I = 0.35 mol/kg, pH = 6.4) and core reacted for 48 days. This novel approach equilibrated rock and formation water and saturated pores with formation water before introducing stimulation fluid. The second experiment served as a control. Trends of aqueous calcium, silica and aluminum in the injection experiment suggest transient dissolution of calcite and feldspar and/or quartz as well as clay and barite precipitation; mineralogic evidence was limited to calcite dissolution and barite precipitation. The rock maintained reducing conditions (Eh = +0.08 to −0.16 V) despite injection of oxidizing stimulation fluid (Eh = 1.1 V). pH of the stimulation fluid-formation water mixture evolved from 2.3 to pre-injection values (~6) within 24 h. Results indicate that mineral dissolution and precipitation manifest in macropores with barely detectable alteration to micro- and mesopores. Formation water or organic matter in pores may have inhibited access of stimulation fluid to micro- and mesopores

Impact of Diagenesis on the Low Permeability Sandstone Reservoir: Case Study of the Lower Jurassic Reservoir in the Niudong Area, Northern Margin of Qaidam Basin

The Lower Jurassic reservoir in the Niudong area of the northern margin of Qaidam Basin is a typical low permeability sandstone reservoir and an important target for oil and gas exploration in the northern margin of the Qaidam Basin. In this paper, casting thin section analysis, scanning electron microscopy, X-ray diffraction, and stable isotope analysis among other methods were used to identify the diagenetic characteristics and evolution as well as the main factors influencing reservoir quality in the study area. The predominant types of sandstone in the study area are mainly feldspathic lithic sandstone and lithic arkose, followed by feldspathic sandstone and lithic sandstone. Reservoir porosity ranges from 0.01% to 19.5% (average of 9.9%), and permeability ranges from 0.01 to 32.4 mD (average of 3.8 mD). The reservoir exhibits robust heterogeneity and its quality is mainly influenced by diagenesis. The Lower Jurassic reservoir in the study area has undergone complex diagenesis and reached the middle diagenesis stage (A–B). The quantitative analysis of pore evolution showed that the porosity loss rate caused by compaction and cementation was 69.0% and 25.7% on average, and the porosity increase via dissolution was 4.8% on average. Compaction was the main cause of the reduction in the physical property of the reservoir in the study area, while cementation and dissolution were the main causes of reservoir heterogeneity. Cementation can reduce reservoir space by filling primary intergranular pores and secondary dissolved pores via cementation such as a calcite and illite/smectite mixed layer, whereas high cement content increased the compaction resistance of particles to preserve certain primary pores. δ13C and δ18O isotopes showed that the carbonate cement in the study area was the product of hydrocarbon generation by organic matter. The study area has conditions that are conductive to strong dissolution and mainly occur in feldspar dissolution, which produces a large number of secondary pores. It is important to improve the physical properties of the reservoir. Structurally, the Niudong area is a large nose uplift structure with developed fractures, which can be used as an effective oil and gas reservoir space and migration channel. In addition, the existence of fractures provides favorable conditions for the uninterrupted entry of acid fluid into the reservoir, promoting the occurrence of dissolution, and ultimately improves the physical properties of reservoirs, which is mainly manifested in improving the reservoir permeability.

Water-rock interactions and origin of formation water in the Bohai Bay Basin: A case study of the Cenozoic Formation in Bonan Sag

The faulted lacustrine Bohai Basin in eastern China contains abundant hydrocarbon resources. In these reservoirs, understanding the sandstone diagenesis and the resulting formation water provides a means to unravel the evolution processes in the basin. In most cases, the lack of isotopic and trace element analysis tests in this type of basin limits the research on the origin and evolution of formation water in this area. We have used multivariate statistical methods to classify the geochemical characteristics of the formation water for the Cenozoic Formation of Bonan Sag in the Bohai Bay Basin. Analysis of correlations among the evolution processes of different ions in different types of formation water provides an understanding of the primary factors influencing the ion content. We also evaluate the water-rock interactions of different types of formation water to evaluate their geologic significance, and we find three types. Type I formation water includes a mixture of river water, lake water, and atmospheric precipitation and exhibits weak water-rock interactions. Type II formation water contains primitive freshwater and brackish lake water that has undergone an evolution process similar to that of type I formation water, but that was followed by evaporation and concentration, the dissolution and precipitation of calcite and iron calcite, and feldspar dissolution. Type III formation water, which is a product of rock reconstruction, originates from saline lake sediment water. After undergoing evolution processes similar to those of types I and II, type III formation water is also affected by dissolution of evaporite, albite, dolomite, and iron dolomite. Thus, type III formation water is the product of water-rock interactions such as precipitation, SO42− reduction, and pyrite precipitation in which the water-rock reaction controls the development mechanism and characteristics of the reservoir space.

The influence of magmatic-hydrothermal activities on porosity and permeability of sandstone reservoirs in the Linxing area, Ordos Basin, Northern China

The eastern margin of the Ordos Basin in the Linxing area has great potential for exploration of natural gas. However, the intrusion of the Zijinshan igneous pluton and associated hydrothermal activities have affected the sandstone reservoirs. Through the data analyses of rock thin sections, cathodoluminescence, X-ray diffraction, vitrinite reflectance, fluid inclusions, and reservoir physical property, this paper aims to clarify the influences of magmatic-hydrothermal activity and to explore the response characteristics of reservoir porosity and permeability. From the outer zone to the inner zone, the closer to the pluton, the closer the contact between the reservoir clastic particles, which confirms the compression caused by magma intrusion. The differences in feldspar dissolution and alteration, siliceous cementation, clay mineral content, vitrinite reflectivity, homogenization temperature and salinity of fluid inclusions, confirmed that magmatic-hydrothermal activity affected fluid properties and evolution of strata temperature. Combined with the vertical distribution characteristics of feldspar dissolution-alteration and the abnormal conversion of clay minerals, it is considered that the influence of hydrothermal fluid was limited to the reservoir under the thick mudstone of the Xiashihezi Formation. Magma intrusion causes the development of reservoir fractures, thus the permeability of the reservoir decreases from the inner zone to the outer zone, and the porosity presents the distribution pattern of “high-low-slightly high”. The reservoir porosity and permeability genetic model was established to provide references about favorable areas for oil and gas exploration and development in the Linxing area and areas with similar geological history.

The complex effect of organic acids on the dissolution of feldspar at high temperature

To understand the effect of organic acid on the solubility of feldspar under high temperature conditions, feldspar dissolution experiments in oxalic acid and in acetic acid were conducted at 130 °C. And the Gaussian simulation software was used to calculate the binding energy of the complex reaction from the perspective of quantum chemistry to analyze the relationship between the binding energy and the corrosion amount. The results showed that the dissolution of feldspar in oxalic acid was obviously more intense than that in acetic acid at the same temperature. The average dissolution rates in oxalic acid and in acetic acid were 4.30 × 10−10 mol m−2 s−1 and 3.04 × 10−10 mol m−2 s−1, respectively. SEM and EDS results showed that the phenomenon of oxalic acid corroding feldspar is more obvious than that of acetic acid corroding feldspar, and the secondary minerals produced were also different. The Gaussian calculation results indicated that oxalic acid was more easily complexed with silicon ions and aluminum ions than acetic acid, which was consistent with the experimental results that oxalic acid had better corrosion ability to feldspar than acetic acid.

Petrographic features and diagenetic alteration in the shale strata of the Permian Lucaogou Formation, Jimusar sag, Junggar Basin

Reservoir quality is the key parameter controlling shale oil enrichment. However, the complicated lithofacies, which control diagenesis, result in reservoir heterogeneity in the shale strata, creating challenges for reservoir prediction. Combining with the detail analysis of inorganic and organic geochemistry, characteristics of the main lithofacies and diagenetic alteration were investigated in Permian Lucaogou Formation, Jimusar sag, Junggar Basin. Laminated rocks with laminae combinations containing pyroclastic and terrigenous clastic laminae, terrigenous clastic and dolomite laminae, and pyroclastic and carbonate laminae were identified. Massive rocks mainly includes dolomicrite, dolomitic tuff, silt dolostone, dolomitic siltstone, and tuffaceous siltstone. Feldspar dissolution and carbonate cementation were the two dominant diagenetic types, further causing heterogeneity of the shale oil reservoirs. Feldspar dissolution generally occurred in laminated rocks containing pyroclastic laminae with low content of carbonate minerals (PL1), as well as in their adjacent interbedded siltstones. Carbonate cementation generally occurred in laminated rocks containing carbonate laminae, as well as in their adjacent interbedded siltstones. Whether in laminated and massive rocks, sparry carbonate crystals were also precipitated adjacent to organic matter and in microfractures. In the burial processes, enriched transition metal elements of V and Ti in pyroclastic laminae promote catalytic pyrolysis of organic matter. Abundant CO 2 produced during the catalytic pyrolysis promoted feldspar dissolution. Dissolution of sedimentary carbonate minerals by organic acids and CO 2 provided the material sources for secondary carbonate cements. It promoted the recrystallization and re-precipitation of sparry carbonate crystals adjacent to organic matter and in the terrigenous clastic laminae or interbedded siltstones. Ca 2+ , Mg 2+ Sr 2+ , Fe 2+ , and Mn 2+ produced by the transformation of smectite to illite in the pyroclastic laminae also provided Ca source for secondary carbonate cements. External diagenetic fluids providing materials along microfractures is another genesis of carbonate cements in the Permian Lucaogou Formation. • Petrographic features in the shale strata in Permian Lucaogou Formation were identified based on in situ analytical method. • Differential feldspar dissolution and carbonate precipitation generally occurred in different lithofacies. • Catalytic pyrolysis of organic matter in presence of transition metal elements in pyroclastic laminae promoted dissolution. • Development of carbonate cements in the shale strata were mainly provided by three material sources.