Dolomite Reservoir Research Articles

Origin and characteristics of grain dolomite of Ordovician Ma55 Member in the northwest of Ordos Basin, NW China

The origin of grain dolomite in M55 Member of Ordovician Majiagou Formation in northwestern Ordos Basin was studied by geochemical and petrological tests on core samples. Observation of cores, thin sections and casting thin sections, analysis of cathodoluminescence, X-ray diffraction, microscopic sampling of trace elements, laser sampling δ18O and δ13C, and fluid inclusion homogenization temperature were conducted. The results show that the dolomite is the product of recrystallization of micritic to crystal powder dolomite rather than the product of dolomitization of grain limestone. In the spherical grains are residual gypsum and halite pseudo crystals identical with those in the host micritic dolomite. The spherical particles of dolomite has similar trace elements and δ18O and δ13C characteristics to micritic dolomite. Furthermore, Mn/Sr ratio of the fine—medium dolomite between the dolomite grains is about 5-8, while Mn/Sr ratios of calcite in limestone, micritic dolostone in micritic dolomite, and micritic and powdery dolomite are about 0-2, indicating that the dolomite experienced strong diagenesis. Homogenization temperature of inclusions of fine—medium dolomite is about 148. 19 °C, higher than that of inclusions in micritic to crystal powder dolomite (about 122.60 °C), which also supports the conclusion that the grain dolomite experienced burial diagenesis and negative shift of δ18O and δ13C. The δ18O, δ13C values of micritic to crystal powder dolomite match with the negative migration, but those of calcite in limestone don't. It is of great significance to elucidate the genesis of “dolomite recrystallization” for the prediction of such dolomite reservoirs.

Hydrocarbon accumulation and main controlling factors of reef-shoal gas reservoirs in Changxing Formation in the complex tectonic area, Eastern Sichuan Basin

Reef-shoal gas reservoirs of Upper Permian Changxing Formation, which are the important targets for increasing gas reserve and production in Sichuan Basin, are highly heterogeneous in Eastern Sichuan Basin. However, because of the complex tectonic situation, the source and accumulation of natural gas are still being controversial. The lack of systematic research and relevant experimental analysis on controlling factors of hydrocarbon accumulation restrict the effective natural gas exploration. Based on petrographic observation, 3D seismic data and geochemistry, the reservoir spaces, fluid-inclusion of filling mineral, reservoir solid bitumen, and restoration of tectonic evolution are analyzed, which indicates that the reef-shoal gas reservoirs of Changxing Formation are fractured-vuggy type and formed mainly by dolomitization. The reservoir porosity system consists of pores, vugs, and fracture network. The gas reservoir boundary is mainly controlled by reef dolomite reservoirs distributed intermittently along the platform-margin. Both water and gas production wells have undergone two-stage accumulation process. The first stage is the crude oil charging of Wujiaping Formation from the Middle Jurassic to the early of the Late Jurassic; the second stage is that the crude oil of Wujiaping Formation was cracked into gas, accompanied with the formation of a large amount of reservoir bitumen from the middle-late of the Early Cretaceous to the middle of the Late Cretaceous. Tectonic-lithologic traps in both east and west side of the Kaijiang-Liangping Trough are formed in the late period of Indosinian. The faulting activity in the Yanshanian period, which gradually dropped in both east and west side of the Trough and slightly increases the tectonic-lithologic traps, is consistent with the peak period of hydrocarbon charging in the Wujiaping Formation source rock. The direct contact with the active fault above and damage to the regional caprock of the 4th member of Feixianguan Formation jointly result in the destruction of the reef-shoal gas reservoir in Changxing Formation. The Himalayan faulting activity, which further elevated the tectonic amplitude of tectonic-lithologic traps in both east and west side, forms the unique northwest–southeast strike faults in the east side of the Trough.

Characteristics, formation and evolution of pre-salt dolomite reservoirs in the fifth member of the Ordovician Majiagou Formation, mid-east Ordos Basin, NW China

Abstract The characteristics and formation of the pre-salt dolomite reservoirs in the fifth member of Ordovician Majiagou Formation in the mid-east Ordos Basin are investigated through observation of cores and thin sections, and geochemical analysis. (1) The pre-salt dolomites can be divided into dolomicrite, grain dolomite and dolarenite, in which the main reservoir space consists of intercrystalline pores and various dissolved pores. (2) The diagenesis in the study area is complex and mainly includes dolomitization, dissolution, filling, and recrystallization. (3) Multi-stages of dolomitization, including penecontemporaneous capillary concentration dolomitization, seepage-reflux dolomitization during penecontemporaneous and shallow burial stage, and burial dolomitization in later stage, are conducive to the preservation of primary pores and development of secondary pores. (4) Multi-stages of dissolution also have strong influence on the development of secondary pores; the secondary transgression and regression cycles during the contemporaneous-penecontemporaneous stage led to exposure and dissolution of soluble minerals and thus the generation of secondary pores. (5) In the burial stage, reservoir pores were further improved due to organic acid dissolution and the dissolution by hydrosulphuric acid from thermochemical sulfate reduction (TSR) and its product H2S. (6) High H2S concentration area in pre-salt reservoirs can thus be considered as targets for future exploration.

Laser ablation in situ U-Pb dating and its application to diagenesis-porosity evolution of carbonate reservoirs

Abstract Through the development and calibration of a reference material which is 209.8 Ma old using a newly-developed Laser Ablation (LA) Multi-Collector Inductively Coupled Plasma Mass Spectrometry (MC-ICP-MS) technique, we successfully overcome the difficulty in sampling and dating ultra-low U-Pb ancient marine carbonates, which was previously untenable by isotope dilution (ID) methods. We developed the LA-MC-ICP-MS in situ U-Pb dating technique for ancient marine carbonates for the study of diagenesis-porosity evolution history in Sinian Dengying Formation, Sichuan Basin. By systematically dating of dolomitic cements from vugs, matrix pores and fractures, we found that the burial and diagenetic process of dolomite reservoirs in Sinian Dengying Formation was characterized by progressive filling-up of primary pores and epigenic dissolution vugs. The filling of vugs happened in three stages, early Caledonian, late Hercynian-Indosinian and Yanshanian-Himalayan, while the filling of matrix pores mainly took place in early Caledonian. The unfilled residual vugs, pores and fractures constitute the main reservoir sapce. Based on the above knowledge, we established the diagenesis-porosity evolution history of the dolomite reservoir in Sinian Dengying Formation, Sichuan Basin. These findings are highly consistent with the tectonic-burial and basin thermal histories of the study area. Our study confirmed the reliability of this in situ U-Pb dating technique, which provides an effective way for the investigation of diagenesis-porosity evolution history and evaluation of porosity in ancient marine carbonate reservoirs before hydrocarbon migration.

Geo-chromatographic fractionation effect of methyldibenzofuran in dolomite reservoirs and its application in tracing oil filling pathways in the Sichuan Basin

Abstract Dibenzofuran and its methyl substituted homologues are the important oxygen-containing polycyclic aromatic compounds in crude oils. The ratio of 1-/4-methyldibenzofuran has been successfully used in sandstone reservoir tracing oil migration orientation. Here we focus on the geo-chromatographic fractionation effect of methyldibenzofuran (MDBF) in dolomite reservoirs. We calculated the charge density differences between 1-methyldibenzofuran (1-MDBF) and 4-methyldibenzofuran (4-MDBF) based on density functional theory. The E I n between MDBF isomers and dolomite (104) surface was also calculated according to molecular dynamics simulation. The result show that comparing with the 4-MDBF, there is strong interaction between 1-MDBF and dolomite (104) surface leading the ratio of 1-MDBF and 4-MDBF increase with the migration distance. There is no significant correlation between bitumen reflectance and the ratio of 1-MDBF and 4-MDBF in our samples. In addition, molecular simulation results show that the MDBF isomers are thermodynamically stable and dissociation of Ph-CH3 is difficult to occur under geological condition. All these demonstrate that 1-MDBF and 4-MDBF can be survived after oil-cracking to gas and pyrobitumen. Therefore, in theory, the ratio of 1-/4-methyldibenzofuran is also regarded as an index for oil migration orientation in dolomite reservoir. Gas chromatography-mass spectrometry results show that MDBFs occur at relatively higher abundance in the bitumens of the Ediacaran Dengying Formation (Z2dn4) and Cambrian Longwangmiao Formation (Є1l) in the Sichuan Basin. The ratio of 1-/4-methyldibenzofuran has been successfully used to trace the crude oil filling pathway in the Z2dn4 and Є1l dolomite reservoir in the Sichuan Basin in this study. Two preferential filling orientations (i.e. from west to east and from north to south) for paleo-oil have been identified in the contour maps of 1-/4-methyldibenzofuran in the Z2dn4 and Є1l, which is consistent with the geological background.

Diagenetic Processes and Reservoir Heterogeneity in Salt-Encased Microbial Carbonate Reservoirs (Late Neoproterozoic, Oman)

A common problem in dolomite reservoirs is the heterogeneous distribution of porosity-reducing diagenetic phases. The intrasalt carbonates of the Ediacaran-Early Cambrian Ara Group in the South Oman Salt Basin represent a self-sourcing petroleum system. Depositional facies and carbonate/evaporite platform architecture are well understood, but original reservoir properties have been modified by diagenesis. Some of the carbonate reservoirs failed to produce hydrocarbons at acceptable rates, which triggered this study. The extent of primary porosity reduction by diagenetic phases was quantified using point counting. To visualize the distribution of diagenetic phases on a field scale, we constructed 2D interpolation diagenesis maps to identify patterns in cementation. The relative timing of diagenetic events was constrained based on thin-section observations and stable isotope analyses. Near-surface diagenesis is dominated by reflux-related processes, leading to porosity inversion in initial highly porous facies and a patchy distribution of early cements. This strong diagenetic overprint of primary and early diagenetic porosity by reflux-related cements leads to a reduction of stratigraphic and facies control on porosity. Calcite was identified as a burial-related cement phase that leads to an almost complete loss of intercrystalline porosity and permeability. Bitumen is an important pore-occluding phase and time marker of the deep-burial realm. The stratigraphic position of the dolomite reservoirs embedded at the base of a salt diapir had a strong impact on its diagenetic development. The salt isolated the dolomites from external fluids, leading to a closed system diagenesis and the buildup of near lithostatic fluid pressures. In combination, these processes decreased the impact of further burial diagenetic processes. The study highlights that cement distribution in salt-encased carbonate reservoirs is mainly related to early diagenetic processes but can be very heterogeneous on a field scale. Further work is needed to implement these heterogeneities in an integrated numerical reservoir model.

Sulphate Ion Interference on Oil Recovery Mechanism of Low Salinity Waterflooding in Dolomite Reservoirs

This study focused on the sulphate ion concentration interference with different divalent cations ratio, used in low salinity water flooding in dolomite reservoirs by comparing the oil recovery with the altered amount of divalent cations dissolved in brine, occurred from rock surface equilibrium shifting. The oil recovery from injecting different potential determining ions concentration is measured by core flood experiment. The process of detecting the amount of divalent cations begins with establishing oil adsorption on the dolomite grain surface. Then, the grain is stirred in brine with different formula, which is later titrated in order to gather the desired data. Finally, the phenomena occurred during flooding with different potential determining ion concentration is described by combining the result of oil recovery with altered amount of divalent ions. The results showed that at high temperature (70°C), the oil recovery from each case is not much different because high amount of calcium sulphate precipitation can be compensated by high rate of rock dissolution and magnesium carboxylate complex formation. However, at low temperature (30°C), the oil recovery tends to be lower when the sulphate concentration is higher because calcium ion tends to form or precipitate with sulphate ion rather than forming the carboxylate complex. Due to low dissolution rate, the amount of calcium ion is insufficient for oil recovery mechanism, especially when the sulphate ion concentration exceeds the solubility limit. Furthermore, for the case that the ratio of magnesium to calcium ion is high, it is observed that some amount of magnesium ion can form the carboxylate complex to compensate the lost amount of calcium ion. From the result, it can be concluded that at low temperature, which the dissolution reaction occurs slowly, the effect of changing the divalent cation ratio, including sulphate concentration, is large because the formation of magnesium carboxylate complex is not much at this temperature, however calcium sulphate precipitation reduces the number of active calcium ions in oil recovery mechanism. On the other hand, because the dissolution reaction occurs faster and the formation of magnesium carboxylate complex is more favourable at high temperature, therefore the values of oil recovery, even at different concentration of potential determining ions, are not much different at this temperature. Furthermore, it is also found that the carboxylate complex formation can be induced by high concentration of either type of divalent ions when the sulphate ion concentration is not too high.

Study on 3D Micro-pore Structure Characteristics of Dolomite Reservoir with Different Scales

Study on 3D Micro-pore Structure Characteristics of Dolomite Reservoir with Different Scales

The preparatory phase of the Mw 6.1 2009 L’Aquila (Italy) normal faulting earthquake traced by foreshock time-lapse tomography

AbstractThe Mw 6.1 (6 April 2009) L’Aquila (Italy) earthquake occurred in one of the most seismically active areas of central Italy and was preceded by a three-month-long foreshock period. Thanks to recordings by a regional permanent network, we derive for the first time P- and S-wave velocity tomographic models of a major fault prone to an imminent main shock. Close to the Mw 6.1 hypocenter, we observe high Vp (>6.8 km/s) and high Vp/Vs (>1.9) consistent with thick dolomitic volumes filled with fluids sealed by impermeable anhydritic layers. Significant changes in velocities defined by time-lapse imaging during the foreshock period suggest rapid fluid migration through the locked fault zone. The complex positive feedback between fluid pressure buildup and hydrofracturing of the dolomitic reservoir, testified by foreshock production, eventually provoked the catastrophic coseismic breaching of the fault seal. Our results show that foreshock time-lapse tomography provides clues on the preparatory phase of a large normal-faulting earthquake.

A Model To Simulate Matrix-Acid Stimulation for Wells in Dolomite Reservoirs with Vugs and Natural Fractures

SummaryDesigning matrix-acid stimulation treatments in vuggy and naturally fractured carbonate reservoirs is a challenging problem in the petroleum industry. It is often difficult to physically model this process, and current mathematical models do not consider vugs or fractures. There is a significant gap in the literature for models that design and evaluate matrix-acid stimulation in vuggy and naturally fractured carbonate reservoirs. The objective of this work is to develop a new model to simulate matrix acidizing under field conditions in vuggy and naturally fractured carbonates.To obtain accurate and reliable simulation parameters, acidizing coreflood experiments were modeled using a reactive-flow simulator. A 3D radial field-scale model was used to study the flow of acid in the presence of vugs (pore spaces that are significantly larger than grains) and natural fractures (breaks in the reservoir that were formed naturally by tectonic events). The vugs’ size and distribution effects on acid propagation were studied under field conditions. The fracture length, conductivity, and orientation, and the number of fractures in the formation, were studied by the radial model. The results of the numerical simulation were used to construct Gaussian-process (GP)-based surrogate models for predicting acid propagation in vuggy and naturally fractured carbonates.Finally, the acid propagation in vuggy/naturally fractured carbonates was evaluated, as well.The simulation results of vuggy carbonates show that the presence of vugs in carbonates results in faster and deeper acid propagation in the formation when compared with homogeneous reservoirs at injection velocities lower than 8×10–4 m/s. Results also revealed that the size and density of the vugs have a significant impact on acid consumption and the overall performance of the acid treatment. The output of the fracture model illustrates that under field conditions, fracture orientations do not affect the acid-propagation velocity. The acid does not touch all of the fractures around the well. The GP model predictions have an accuracy of approximately 90% for both vuggy and naturally fractured cases. The vuggy/naturally fractured model simulations reveal that fractures are the main reason behind the fast acid propagation in these highly heterogeneous reservoirs.

Dolomite genesis and reservoir-cap rock assemblage in carbonate-evaporite paragenesis system

Regarding to the problem on the reservoir-cap rock assemblage evaluation in the carbonate-evaporite paragenesis system, this study examined the dolomite and reservoirs genesis and the characteristics of reservoir-cap rock assemblage. Based on the literature research of the global carbonate reservoirs and the case study on four profiles of carbonate-evaporite succession, together with geological and experimental work, three aspects of understandings are achieved. (1) Lithology of carbonate-evaporite paragenesis system is mainly composed of microbial limestone/bioclastic limestone, microbial dolomite, gypsum dolomite and gypsum salt rock deposited sequentially under the climatic conditions from humid to arid, and vice versa, and an abrupt climate change event would lead to the lack of one or more rock types. (2) There developed two kinds of dolomite (precipitation and metasomatism) and three kinds of reservoirs in the carbonate-evaporite system; and the carbon dioxide and organic acid generated during early microorganism degradation and late microbial dolomite pyrolysis process, and early dolomitization are the main factors affecting the development of microbial dolomite reservoirs with good quality. (3) In theory, there are 14 types of reservoir-cap rock assemblages of six categories in the carbonate-evaporite system, but oil and gas discoveries are mainly in four types of reservoir-cap rock assemblages, namely “microbial limestone/bioclastic limestone – microbial dolomite – gypsum dolomite – gypsum salt rock”, “microbial limestone/bioclastic limestone – gypsum salt rock”, “microbial dolomite – gypsum dolomite – gypsum salt rock” and “gypsum dolomite – microbial dolomite – tight carbonate or clastic rock”. These four kinds of reservoir-cap rock assemblages should be related with the climate change rules in the geologic history, and have good exploration prospects.

Oil and gas enrichment patterns and major controlling factors for stable and high production of tight lacustrine carbonate rocks, a case study of Yingxi area in Qaidam Basin, West China

In recent years, sustained important discoveries of oil and gas exploration in the E 32 reservoir of Oligocene in the Yingxi area have been achieved, which revealed great exploration potential in Qaidam Basin. Based on core observations and systematic research on micro-petrological and structural characteristics, lithology, hydrocarbons enrichment patterns, and major controlling factors of stable and high production of the Oligocene reservoir in the Yingxi area of Qaidam were studied. The following findings were reported: (1) the lithology of the target layer is mainly lacustrine carbonate rocks, which can be divided into inter-salt and subsalt strata. In addition, many thick layers of halites widely developed in inter-salt strata. While thin layers of gypsum also developed scatteringly in the subsalt strata. (2) Fine-grained lacustrine carbonate rocks (including dark mudstone) were deposited under saline conditions, which not only are relatively the best quality source rock, but also developed a “dessert” dolomite reservoir. This set of strata is characteristic of “authigenic source rock and authigenic reservoir”. The upper salt layers have a strong sealing ability because of their very high capillary breakthrough pressure and plastic characteristics, and joints formed widely in the subsalt strata since stress concentration. The good matching relationship among all of the above factors led to the formation of favorable area for large-scale hydrocarbon accumulation in the subsalt strata. (3) The development of the matrix intercrystalline pores controls the scale of oil and gas reservoirs and stable production. Moreover, the development of fractures controls the enrichment of oil and gas reservoirs and high production. The research results have important guiding significance for further research on subsalt oil and gas distributing regularities, as well as further exploration deployment of E 32 in the Yingxi area.

Sparse spectral attributes to detect hydrocarbons: A case study from deep dolomite reservoirs

Hydrocarbon detection is always one of the most critical sections in geophysical exploration, which plays an important role in subsequent hydrocarbon production. However, due to the low signal-to-noise ratio and weak reflection amplitude of deep seismic data, some conventional methods do not always provide favorable hydrocarbon prediction results. The interesting dolomite reservoirs in Central Sichuan are buried over an average depth of 4500 m, and the dolomite rocks have a low porosity below approximately 4%, which is measured by well-logging data. Furthermore, the dominant system of pores and fractures as well as strong heterogeneity along the lateral and vertical directions lead to some difficulties in describing the reservoir distribution. Spectral decomposition (SD) has become successful in illuminating subsurface features and can also be used to identify potential hydrocarbon reservoirs by detecting low-frequency shadows. However, the current applications for hydrocarbon detection always suffer from low resolution for thin reservoirs, probably due to the influence of the window function and without a prior constraint. To address this issue, we developed sparse inverse SD (SISD) based on the wavelet transform, which involves a sparse constraint of time-frequency spectra. We focus on investigating the applications of sparse spectral attributes derived from SISD to deep marine dolomite hydrocarbon detection from a 3D real seismic data set with an area of approximately [Formula: see text]. We predict and evaluate gas-bearing zones in two target reservoir segments by analyzing and comparing the spectral amplitude responses of relatively high- and low-frequency components. The predicted results indicate that most favorable gas-bearing areas are located near the northeast fault zone in the upper reservoir segment and at the relatively high structural positions in the lower reservoir segment, which are in good agreement with the gas-testing results of three wells in the study area.

Genesis and characteristics of the dolomite reservoirs in Middle Devonian Guanwushan Formation, Northwest Sichuan Basin, SW China

Abstract A great breakthrough has been made on oil-gas exploration of the Middle Devonian Guanwushan Formation in Northwest Sichuan Basin. The further exploration shows that the dolomite reservoir is complicated with insufficient investigation. Taking the Middle Devonian Guanwushan Formation as an example, systematic study has been carried out on its reservoir character, mechanism and genesis of dolostone. The field and core data suggest that reservoir types of Guanwushan Formation consist of crystalline dolomite, breccia dolomite and reef dolomite, and reservoir space is characterized by intercrystal (dissolution) pores, residual pores among breccias, intragranular dissolution pores, pockets as well as fractures. Besides, pore structure is of good configuration, showing medium-low porosity and moderate permeability, with average porosity and permeability of 2.23% and 0.44mD respectively, which suggesting fracture-pore and fracture-cavity reservoir. Combined with the previous research, it is suggested that the reservoir of Guanwushan Formation was controlled by facies, dolomitization and two-step karstification, with reef-shoal facies being material base for reservoir development, early dolomitization being key factor for reservoir space preservation, polyphase karstification being foundation for reservoir development and tectogenesis finally finalizing the reservoir.

Characteristics and dolomitization of the Lower Qiulitage Group reservoir in Bachu Uplift, Tarim Basin, China

The characteristics of the Lower Qiulitage Group in Bachu uplift, which originated in the Upper Cambrian period, are not clear. Based on four core observations, identification of 40 thin sections, and geochemical analysis of samples, this study concludes that crystal dolomite reservoirs developed in the Lower Qiulitage Group in Bachu uplift. Intercrystalline pores and dissolved pores formed the main reservoir space, while dissolution pores and fractures were developed in the middle and bottom part of the formation. The reservoir features low porosity and low permeability, and the fine-medium crystalline dolomite reservoir has the best pore structure. According to a petrochemical analysis, the Lower Qiulitage Group reservoir experienced intense dolomitization, with slightly higher content of trace elements Mn and Sr and negative oxygen isotropy. Tectonic hydrothermal dolomitization developed locally under the influence of base faults, and vug pores were filled with saddle dolomites and siliceous filling. The presence of rare earth elements Ce and Eu presented positive anomaly characteristics. It suggested that the CO2 acid dissolution caused by hydrothermal fluids may be a new mechanism for the increase in pores in deeply buried reservoirs, which is worth further study.

Porosity evolution in dolomitized Permian–Triassic strata of the Persian Gulf, insights into the porosity origin of dolomite reservoirs

Permian–Triassic Kangan and Dalan formations and their time equivalents in the Persian Gulf host the largest gas reservoirs of the world. Most parts of these reservoirs are dolomitized. This study focuses on the origin and evolution of porosity in these reservoirs. Thin sections from two wells were studied for analyzing petrographic characteristics including lithology, depositional texture, pore types and diagenetic processes. Porosity measured on all plug samples and scanning electron microscopy analysis helped to better understand small scale properties. Results showed that both limestones and dolomites can have high porosity. In limestone samples, grain-dominated textures are commonly porous. Dolomite samples inherit the porosity of the precursor limestones, but the ratios between mud and grain-dominated textures are different for these samples. So, at least parts of the porosities in these samples have been created during dolomitization process. Completely dolomitized intervals include both low and high porosity samples. Comparing anhydride and dolomite content, it can be concluded that pore spaces have been occluded by anhydrites cements along with dolomitization. This type of cement is also responsible for low porosity of moderately dolomitized facies. Overdolomitization is not present in the samples. With respect to the reflux dolomitization model of these formations, limited circulation of the dolomitizing fluid could not precipitate released carbonate as crystal overgrowth and so the high porosity of the samples retained to the later stages of diagenesis. This was not affected by the size or boundary shape of the dolomite crystals.

Petrological and geochemical constraints on the origin of dolomites: a case study from the early Cambrian Qingxudong Formation, Sichuan Basin, South China

Several types of dolomite had occurred pervasively in the lower Cambrian Qingxudong Formation in the Sichuan Basin. However, the origin of these dolomites remains particularly controversial until now. Here, we describe the petrographic and geochemical characteristics of dolomites from the lower Cambrian Qingxudong Formation in the southeastern Sichuan Basin, which can potentially provide useful information to constrain the origin and evolution of dolomitization fluid. Three fabric types and five dolomite generations were identified in this study: fabric-retentive dolomites (dolomicrite, Dol-1, and dolomitic microbialite, Dol-2), fabric-destructive dolomites (sucrosic dolomite, Dol-3) and pore-filling dolomites (medium- to coarse-crystalline dolomite, Dol-4, and saddle dolomite, Dol-5). The δ13C and δ18O values, 87Sr/86Sr ratios and rare earth element (REE) pattern of Dol-1, Dol-2 (except the δ13C values) and Dol-3 are approximately consistent with original seawater values, suggesting that the dolomitization fluids were mediated by seawater. The calculated dolomitization temperature (25.66 °C) and Z values (125.2) of Dol-1 with evaporite minerals indicate that the dolomitization fluid was high-salinity concentrated seawater derived from evaporation. The calculated dolomitization temperature (24.20 °C) and Z value (121.8) of Dol-2, and no traces of evaporite minerals in Dol-2 imply that the dolomitization fluid was slightly hypersaline seawater. The more negative δ13C and abundant microbial features of Dol-2 indicate that microbial mats were involved in dolomite formation. The dolomitization temperature (30.55 °C) and Z value (125) of Dol-3 also indicate that the dolomitization fluid was high-salinity concentrated seawater. However, Dol-3 is commonly distributed in reef and shoal facies (high porosity and permeability) throughout the Qingxudong Formation. Moreover, the abundant organic matters in the dolomitization fluid likely overcame the kinetic and thermodynamic barriers in the process of dolomitization. The geochemical data (except the δ18O values) of Dol-4 are approximately consistent with fabric-retentive dolomites, suggesting that the Dol-4 had been inherited from precursor carbonates. The negative δ18O values of Dol-4 revealed a further burial environment. High LREE/HREE ratios, positive europium anomalies and negative δ18O values of Dol-5 suggest that these dolomites were affected by hydrothermal fluids under deep burial conditions. Thus, Dol-1, Dol-2 and Dol-3 are likely attributed to sabkha, organogenic (microbial) and seepage-reflux dolomitization models during early-stage diagenesis, respectively. Dol-4 and Dol-5 are commonly attributed to burial and hydrothermal dolomitization models during deep burial diagenesis. This study provides new insights into the origin of dolomites and is especially useful for the further understanding of dolomite reservoir formation in the Qingxudong Formation.

Bed‐scale spatial patterns in dolomite abundance: Part II. Effect of varied fluid chemistry, flow rate, precursor mineralogy, temperature, textural heterogeneity, nucleation density and bed geometry

AbstractReaction‐transport modelling shows that a lateral, metre‐scale pattern in dolomite abundance can form during replacive dolomitization of calcite and aragonite precursors by Mississippian, Triassic and modern seawaters advecting at >20 cm year−1 in low temperature (≤60°C) hydrogeological systems. The modelled pattern develops best in beds >1 m thick with a relatively uniform nucleate density and a low variance in reactive surface area (for example, grainstones). These conditions suggest that a lateral pattern in dolomite abundance should be expected in dolomites formed by any shallow hydrodynamic system that advects dolomitizing fluid horizontally, including the down‐gradient portion of a reflux system, the oceanward reaches of geothermal (Kohout) convection systems, and the seaward reaches of a seawater entrainment zone below a freshwater aquifer. However, even in those systems, a pattern will not form in all dolomites. Pattern will be muted in thinner (≤ ca 50 cm thick) beds and non‐emergent where the precursor had a high variance in reactive surface area (for example, a skeletal wackestone) and/or large variation in nucleate density. Pattern also did not form at temperatures above ca 60°C, which implies that pattern should not be expected in dolomites formed at intermediate to deep burial depths. As the patterns are horizontal, they also should not be expected where dolomitizing fluids moved vertically (for example, reflux immediately below a brine source). Pattern metrics (short‐range correlation length, and wavelength and amplitude of the longer cyclic component) vary with flow rate, fluid chemistry, bed thickness, porosity, grain size, temperature and the flow complexity (one‐dimensional, two‐dimensional or three‐dimensional) within the bed. However, no modelled pattern produced metrics larger than those documented on dolomite outcrops. The results thus constrain the length scales of porosity and permeability variance to include in petrophysical models of dolomite reservoirs, as well as the geological scenarios in which to consider metre‐scale lateral petrophysical variability.

Reconstruction of the evolution of deep fluids in light oil reservoirs in the Central Tarim Basin by using PVT simulation and basin modeling

Abstract To better understand the fluid phase state and its evolution in a deep environment, an integrated PVT simulation and basin modeling method for two light oil reservoirs in the Central Tarim Basin was proposed and applied. The fluid phase models were built using PVT simulation technology after successfully recovering the fluid compositions. The envelopes of fluid from either the Awatage Formation (Є2a) for Well ZS1 or the Wusongar Formation (Є1w) for Well ZS5 show the order from cricondenbar (Pm), critical point (Cp) to cricondentherm (Tm), suggesting a single liquid phase for the present fluids in the Cambrian subsalt dolomite reservoirs. The result of this study indicates that the two reservoirs did not experience phase changes, phase differentiation, or oil cracking and maintained a universal state of the liquid phase over time by combining the evolutionary history of temperature and pressure derived from basin modeling. The fluid density and viscosity experienced relatively complicated fluctuation processes, and the fluctuations of fluid viscosity over geologic history are much more apparent than the variations in fluid density. The density and viscosity of the Awatage Formation (Є2a) for Well ZS1 are found to be lower than those of the Wusongar Formation (Є1w) for Well ZS5. The results reveal that factors, such as good trap conditions, a stable tectonic background, a low paleo-geothermal gradient (1.6–2.8 °C/100 m), and the weak effect of thermal sulfate reduction (TSR) altogether act on the early-accumulated light oil and gas that has been preserved as a single liquid phase over time. These results are significant for future explorations of large-scale liquid petroleum in Cambrian subsalt dolomite reservoirs of the Central Tarim Basin.

Effect of SO4−2 ion exchanges and initial water saturation on low salinity water flooding (LSWF) in the dolomite reservoir rocks

The low salinity water injection has become one of the most important studies in the oil industry for improving oil recovery compared to conventional seawater injection. Thus, extensive studies have been conducted in carbonate and sandstone reservoirs to investigate how the physical properties of rocks and the chemical composition of fluids influence low salinity effect, while, the carbonate reservoir rocks requires more investigation of the effect of molecular and/or ionic interactions. In this experimental work, the effectiveness of various water flooding schemes in carbonate reservoir rock samples is investigated. In this regard, the oil recovery potential of seawater (SW), reservoir formation water (RFW) and managed water salinity (MWS), with different ion compositions adjusted based on the formation water composition are used. The experiments have been performed on the dolomite core samples and crude oil from an Iranian oil reservoir. Various measurements including zeta potential, XRD, contact angle and interfacial tension have been planned. The main contribution is to investigate the effect of both brine’s ionic composition and rock’s initial water saturation on wettability change and oil recovery. The results show that, the concentration of ion in the injected water must be managed over an optimum range for each case. This results in changing the wettability of carbonate rock to a less oil-wetting state by altering the brine composition and reducing the salinity. Moreover, initial water saturation plays a role in the process, so that, by increasing content in optimum range, the oil recovery increased.