High Salinity Formation Water Research Articles

The molecular explanation for polyacrylamide viscosity reduction in high-salinity formation-water

Many oilfields report that the viscosity of polymers in high-salinity reservoirs will decrease significantly. In this paper, molecular dynamics simulations were conducted to investigate the molecular configuration and network of hydrolyzed polyacrylamide (HPAM) molecules in high-salinity formation-water and the viscosity changes from the microscopic dense to dilute phase. In addition, the viscosity of HPAM/formation-water solution was measured to verify and compare with simulation results. Simulation and experimental results show that the molecular network of the microscopic dense phase is essential for the apparent viscosity. The calculated apparent viscosity could decrease 37% as the net-shape molecular network of the microscopic dense phase is broken by calcium ions, which is similar to our experimental results. This paper improved our understanding of the mechanisms of polymer viscosity alteration in high-salinity formation-water and provided insights that can be used to improve the strategy of enhanced polymer flooding and the novel polymer gel formula.

Surface activity and thermodynamic properties of some green surfactants from wastes in formation water at reservoir conditions

In this work an attention has been paid to prepare some anionic and nonionic surfactants based on aliphatic and aromatic moieties to evaluate their application in enhanced oil recovery (EOR). The aliphatic surfactants derived from Jatropha and waste cooking oil but the aromatics derived from alkyl benzene sulfonic acid. The nonionic surfactants were prepared by tans esterification of acids with different types of poly ethylene glycols and anionic surfactants prepared by saponification. The designated formula of the aromatic surfactants was RC6H4SO3 (en)x OH and RΦSO3Na where aliphatic surfactants designated as RCOO(en)n OH and RCOONa. The structures of these surfactants were confirmed by FT-IR. The surface activity and thermodynamic properties for three surfactants groups have been investigated. The Surface and interfacial tension were measured in high salinity formation water (200,000ppm) at different temperatures (25, 35, 45 and 55 °C) and 1000 psi. From surface tension measurements, CMC, Πcmc, Γmax, Amin, Pc20 were calculated. The thermodynamic parameters of micellization and adsorption were also calculated. The data discussed on the basis of structural effect. The EHJ23 (RCOO(en)23OH) gave a high value of structural effect(22.18 KJmol−1) which met the most negative value of ΔGads (-37.61 KJmol−1) . The results explained that the (ΔGads) negatives values were more than the values of (ΔΔGmic), which means that surfactants prefer to adsorb at interface before forming micelles. These surfactants exhibited ultra-low interfacial tension (IFT) at 55 °C and 1000 psi between 8 × 10−2 to 2 × 10−4 mNm−1 which gave indication that, these surfactants can be used in EOR applications.

Wettability alteration and oil recovery by surfactant assisted low salinity water in carbonate rock: The impact of nonionic/anionic surfactants

Combining low salinity water (LSW) and chemicals to enhance oil recovery has recently received more attention in the oil industry. In this study, a systematic experimental procedure was conducted to evaluate the performance of low salinity nonionic surfactant with/without anionic surfactant in wettability alteration and oil recovery of oil-wet carbonate having high salinity formation water (FW) (196 g/L) and moderate temperature (75 °C). A polyethoxylated nonionic surfactant (C13EO12) and two anionic surfactants: sulfonate (IOS 20–24) and carboxylate (AEC 938) were used in this study. Contact angle (CA) results showed that low salinity nonionic surfactant was effective in altering the wettability of oil-wet calcite toward water-wet state. While the low salinity anionic surfactants' systems were only able to reduce the oil-wetness of the oil-wet calcite. When nonionic surfactant is mixed with anionic surfactant, the wettability of oil-wet calcite was altered toward intermediate-wet or only a reduction of its oil-wetness occurred depending on the type of the anionic surfactant. Spontaneous imbibition tests using oil-wet limestone cores showed that among the low salinity single surfactants’ systems, carboxylate anionic surfactant resulted in the highest oil recovery (61% of oil initially in place (OIIP)) and sulfonate anionic surfactant resulted in the lowest oil recovery (31% of OIIP). The low salinity nonionic surfactant recovered 51% of OIIP by spontaneous imbibition. Addition of sulfonate anionic surfactant to the nonionic surfactant resulted in an oil recovery of 49% of OIIP while addition of carboxylate anionic surfactant to the nonionic surfactant considerably improved the oil recovery to 74% of OIIP. Hence, selection of proper surfactant class is crucial for a successful oil recovery.

A novel approach to solve the water saturation challenges in reservoirs under LoSal water injection

Enhancing hydrocarbon recovery is an ongoing practice in the petroleum industry. Multiple approaches are developed and proved their effectiveness in increasing reservoirs recovery. One of the recent approaches is the Low Salinity Water Injection which is known in the industry by “LoSal”. The determination of the optimum low salinity of the injected water and the mechanism behind its ability to enhance the hydrocarbon recovery are still the subjects of interest for many researchers and industry professionals. Despite the value of the LoSal water injection, it brings with it a considerable challenge to the future formation evaluation, namely the determination of the fluids’ saturation. The mixing of the low salinity injected water with the original high-salinity formation water creates variable water salinity across the reservoir. This is known in the industry by the “mixed-salinity” problem. The horizontal and the vertical heterogeneity of the permeability and porosity across the reservoir is the main factor that controls the “mixed-salinity” distribution in the injected volume. The challenge of calculating the fluids’ saturation exists for both the infill drilling wells and the monitoring wells. For the infill drilling wells, the saturation calculations require accurate formation water resistivity values, Rw, which became variable due to the mixed-salinity. For the monitoring wells, the fluids saturation calculations require accurate formation water sigma absorption, Σw, which also became variable for the same reason. The inability to determine the current Rw and Σw on foot-by-foot basis results in incorrect calculations of the water and hydrocarbon saturations. This creates an economic burden on the reservoir management. The existing methods to interpret the fluids saturation in mixed-salinity reservoirs face the challenges of accuracy, effect of borehole environment and high-data acquisitions cost. A forward modeling is developed to illustrate the problem and its impact on the reservoir decisions making process. A solution to the challenges is proposed, investigated, and proved both theoretically and in the laboratory. The proposed solution is based on lowering the LoSal water resistivity, prior to injection, to be equal to the original formation water resistivity without changing its low salinity. This is achieved by mixing the LoSal water with either acid or alkaline based on the reservoir condition. The acid or alkaline will reduce the resistivity of the LoSal water while keeping its low salinity unchanged. The determination of the required volume of the acid or the alkaline is calculated using the conductivity mixing law and the solution is tested on core plugs. The possible effects of the acid on the formation lithology, specially the clay content is discussed and proved to be negligible due to the very low acid volume required. This is also supported by previously published measurements.

Failure analysis on the oxygen corrosion of the perforated screens used in a gas injection huff and puff well

The perforated screens of a gas injection huff and puff well broke down in an oilfield in western China. The physical and chemical properties of the failure-perforated screens met the requirements of relevant technical protocols. The injected gas was nitrogen produced by the membrane nitrogen method, which contains approximately 5% O2. Therefore, a substantial amount of O2 entered the well during the gas injection, and greatly promoteed the cathodic process of the electrochemical corrosion. High salinity formation water, especially with large amounts of Cl-, further accelerated the corrosion. The significant oxygen corrosion under the well finally led to the failure of the perforated screen.

The effect of salt on the evolution of a subsalt sandstone reservoir in the Kuqa foreland basin, western China

Two sets of thick salt have developed in the Kuqa foreland basin, which has a great influence on the evolution of subsalt reservoirs. The abnormal favorable reservoirs, developed at a depth of approximately 4000–5500 ms, was several hundred meters from the bottom of the salt body based on the drilling data. The study was carried out to understand the formation of the favorable subsalt reservoirs based on the techniques of formation water salinity analysis, scanning electron microscopy (SEM) and cast thin section analysis. The results showed that during the first stage, the high-salinity formation water began to infiltrate and crystallized in the pores after the salt deposition, causing the decrease in the porosity. During the second stage, the formation water salinity decreased for the groundwater activities, which caused dissolution of the salt in the pores, a favorable subsalt reservoir was formed. During the third stage, hydrocarbons were charged and accumulated in the favorable subsalt reservoir. The high heat conductivity characteristic of the salt cooled the subsalt reservoir, which was also helpful for the forming of the favorable reservoir.

Study on salt precipitation induced by formation brine flow and its effect on a high-salinity tight gas reservoir

For the tight gas reservoir with high salinity formation water, the flow of formation brine may cause salt precipitation and thus promote scale formation. Salt deposition and the accompanying scale formation as well as swelling and shrinkage of clay minerals may cause blockage of the pore and throats, which will significantly reduce permeability and the subsequent gas production rate. In this study, the influence of salt precipitation/dissolution on the physical properties of a tight gas reservoir is studied. Core analyses, core flooding tests, core evaporation tests, and microscopic visual flooding inspections are carried out on core samples extracted from the Shahejie Formation. To simulate the depletion production process in the subsurface, brine flow characteristics are studied by core flooding tests with pressure reduction at a formation temperature of 115 °C and with the change of pressure ranging from 30 to 1 MPa. The potential changes in physical properties including permeability, porosity, pore radius, pore size distribution, and surface area are analyzed by core evaporation tests. To show the brine flow and geometry of salt deposits in the pore structure, visual brine flooding is observed under high magnification microscope. Photos of the pore structure at different stages of salt precipitation are recorded. The results reveal that salt dissolution/precipitation has a significant impact on flow-through characteristics, and it can be divided into three stages during the depletion process. The damage of salt to the core permeability could reach more than 90%, and it increases gradually with the reduction of porosity and initial permeability and the increase of specific area. The maximum formation damage caused by salt precipitation is realized when the salt crystal size and pore throat diameter are close in size. The semi-empirical Carman-Kozeny equation together with porosity and grain diameter is used to estimate the permeability after precipitation.

Studying the corrosion mitigation behavior and chemical durability of FeTiO3/melamine formaldehyde epoxy composite coating for steel internal lining applications

Currently, construction of composite coating is considered a vital pattern for corrosion protection of steel petroleum internal lining applications. For supporting this concept, the potential of incorporating various loading levels of fabricated FeTiO3 (ilmenite)/melamine formaldehyde composite (IMFC) particles on the corrosion mitigation behavior and chemical resistance of the epoxy coating was investigated. Micro-sized FeTiO3 natural pigment particles were obtained by a direct solid-phase milling process as a bi-functional modifier. Characterizations for the micro-sized FeTiO3 grains were clarified using scanning electron microscope (SEM), x-ray diffraction (XRD) and dynamic light scattering (DLS) methods. The electrochemical behavior of epoxy coated films against blank carbon steel surface in high salinity formation water has been examined by using both potentiodynamic polarization (PDP) and electrochemical impedance spectroscopy (EIS) techniques. Cure durability and water resistance tests were performed according to standard protocols to confirm the chemical resistance property of the modified coating. Scanning electron microscope (SEM) and energy dispersive analysis of X-rays (EDX) analysis were performed to investigate the corrosion protection performance of the surface modified IMFC epoxy coated film compared to the unmodified conventional coating on the C-steel substrate in high salinity formation water solution. The results of this study boosted the prominent corrosion mitigation behavior of the considered modified epoxy composite coating.

Corrosion failure analysis of A L80 oil tube thread

Material properties of L80 oil tube thread were tested by means of chemical composition analysis, hardness testing and metallographic examination. The results showed that the content of chemical compositions and HRC value accorded to API SPEC 5CT requirements. Micro-morphology and corrosion production analysis of inner surface were carried out by SEM, EDS and XRD. The results showed that the corrosion products on thread were dense and mainly consisted of FeCO3, but there were a large number of microcracks and micropores in it. The main reason of corrosion for thread sample was crevice corrosion which originated from the infiltration of corrosive medium such as high salinity formation water and CO2 to thread joint.

Toward a mechanistic understanding of wettability alteration in reservoir rocks using silica nanoparticles

Traditional concepts of simple liquid spreading may not apply to nanoparticle-fluids. Most investigations pertaining to the wettability alteration of solid surfaces due to the presence of nanoparticles in the fluid are oversimplified, i.e. nanoparticles dispersed in DI-water and smooth, homogeneous, and clean surfaces have been used. From a practical enhanced oil recovery (EOR) point of view, the nanoparticles must be dispersed in either seawater or high salinity formation water containing diverse types and concentrations of ions. These ions interact with the electrostatic properties of the nanoparticles. Likewise, the oil phase may contain many surface active components like asphaltene and naphthenic acids which can interact with nanoparticles at oil-water and oil-rock interface. In reality, the rock sample is a heterogeneous, non-smooth, mixed-wet substrate with a diverse mineralogical composition. The electrical charge of minerals can vary when contacted with an ionic fluid. This can alter the electrostatic repulsion between substrate and nanoparticles and consequently the substrate can either attract or repel charged particles, including nanoparticles. Hence, the role of nanoparticles must be evaluated considering multicomponent complex fluids and real formation rock. Despite numerous reports regarding the wettability alteration of reservoir rock from oil-wet to water-wet by nanoparticles, some inherent limitations in the wettability alteration experiments prevent conclusions about the performance of nanoparticles in practical complex conditions. For instance, the wettability alteration by nanoparticles is often determined by contact angle measurements. In this method, the substrates are either aged with (immersed in) nanoparticle-fluids before conducting the experiments or contacted with nanoparticle-fluids before attachment of the oil droplet on the rock surface. Hence, in both cases, before initiating the contact angle measurements, the nanoparticles would already exist at the oil-rock interface possibly giving inaccurate measurements. The objective of this work is to investigate the mechanism of wettability alteration by silica nanoparticles pre-existing on the rock interface (conventional contact angle measurements) and using a new displacement contact angle method to better mimic the scenario of injecting a nanoparticle fluid into the reservoir already containing formation brine. The impact of pre-existing nanoparticles at the oil-rock interface (in the conventional contact angle measurements) on the contact angle measurements are examined for simple (n-decane, NaCl brine, and pure substrates) and complex (crude oil, seawater, and reservoir rock) systems on various wetting conditions of substrates (water-wet and oil-wet). The nanoparticles are dispersed in seawater using our H+ protected method [1]. Then, the effect of surface and nanoparticle charge on the contact angle is evaluated by adjusting the aqueous phase salinity. We also differentiate between the disjoining pressure mechanism and diffusion of silica nanoparticles through the oil phase by testing the attachment of nanoparticles on the rock surface.

Time-Dependent Physicochemical Changes of Carbonate Surfaces from SmartWater (Diluted Seawater) Flooding Processes for Improved Oil Recovery.

Over the past few decades, field- and laboratory-scale studies have shown enhancements in oil recovery when reservoirs, which contain high-salinity formation water (FW), are waterflooded with modified-salinity salt water (widely referred to as the low-salinity, dilution, or SmartWater effect for improved oil recovery). In this study, we investigated the time dependence of the physicochemical processes that occur during diluted seawater (i.e., SmartWater) waterflooding processes of specific relevance to carbonate oil reservoirs. We measured the changes to oil/water/rock wettability, surface roughness, and surface chemical composition during SmartWater flooding using 10-fold-diluted seawater under mimicked oil reservoir conditions with calcite and carbonate reservoir rocks. Distinct effects due to SmartWater flooding were observed and found to occur on two different timescales: (1) a rapid (<15 min) increase in the colloidal electrostatic double-layer repulsion between the rock and oil across the SmartWater, leading to a decreased oil/water/rock adhesion energy and thus increased water wetness and (2) slower (>12 h to complete) physicochemical changes of the calcite and carbonate reservoir rock surfaces, including surface roughening via the dissolution of rock and the reprecipitation of dissolved carbonate species after exchanging key ions (Ca2+, Mg2+, CO32-, and SO42- in carbonates) with those in the flooding SmartWater. Our experiments using crude oil from a carbonate reservoir reveal that these reservoir rock surfaces are covered with organic-ionic preadsorbed films (ad-layers), which the SmartWater removes (detaches) as flakes. Removal of the organic-ionic ad-layers by SmartWater flooding enhances oil release from the surfaces, which was found to be critical to increasing the water wetness and significantly improving oil removal from carbonates. Additionally, the increase in water wetness is further enhanced by roughening of the rock surfaces, which decreases the effective contact (interaction) area between the oil and rock interfaces. Furthermore, we found that the rate of these slower physicochemical changes to the carbonate rock surfaces increases with increasing temperature (at least up to an experimental temperature of 75 °C). Our results suggest that the effectiveness of improved oil recovery from SmartWater flooding depends strongly on the formation of the organic-ionic ad-layers. In oil reservoirs where the ad-layer is fully developed and robust, injecting SmartWater would lead to significant removal of the ad-layer and improved oil recovery.

Experimental investigation of porosity and permeability change caused by salting out in tight sandstone gas reservoirs

Salt precipitation and its induced problems are increasingly prominent with the development of deep and ultra-deep tight sandstone gas reservoirs with high salinity formation water. In this paper, the change of porosity and permeability of a series of tight sandstone was measured, and then the morphology and occurrence state of crystalloid salt within the pore was observed by SEM. Meanwhile, high-pressure mercury injection analyzed the changes of pore size distribution. Experimental results show that salt precipitation could affect the porosity and permeability, which decreases by 53% and 65% after salt precipitation, respectively. The occurrence state of the crystalloid salt can be divided into three models: superposition growth along with the intergranular pore-fractures/natural micro-fractures, lamellar growth attached to the surface of the hydrophilic mineral like I/S interstratified mineral and the individual particles located in the corner of the pore. When the size of crystalloid salt is closer to the pore size distribution of tight sandstone, it will cause cracks and pore throat blockage easily. It is suggested that salt wash pretreatment should be carried out before analysis of tight sandstone with porosity less than 5%.

Insights into the role of clays in low salinity water flooding in sand columns

Clays in sandstone are thought to be a key factor in low salinity (LS) water flooding. This study investigates the effects of quartz, kaolinite and illite in LS water flooding in synthetic sand columns as a function of temperature. Four chromatography columns containing different amounts of pure quartz sand, illite, and kaolinite (100% quartz sand; 95/5% sand/illite; 95/5 sand/kaolinite; and 95/2.5/2.5% sand/illite/kaolinite). The use of these synthetic columns gives full control over mineralogy. These columns were saturated with high salinity (HS) formation water with 0.01 M (M) sodium acetate and aged for a week at 70 °C. They were then flooded with waters (yes, the use of water to displace water) with various salinities at four different temperatures (25, 70, 90 and 120 °C). Effluent concentrations of Ca2+ and acetate (CH3COO−) and pH were measured. This is a novel experimental design, where formation water containing sodium acetate is flooded with waters of varying salinity to gain insight into LS flood performance and possible recovery mechanisms. The hypothesis pursued here is that the behavior of the acetate ion (attached to matrix minerals during the aging process and then released due to ionic exchange) in an LS flood would provide a valuable analog that would simulate the bonding of carboxylic acids in crude oils with reservoir matrix minerals (and subsequent desorption during LS flooding). Key results include the following: (a) Our hypothesis was correct—the use of Na acetate behaved analogously to carboxylic acid, giving useful insights; (b) The quartz-only column showed strong evidence (elevated pH, presence of Ca2+ and acetate in effluent) of ionic exchange due to LS flooding, showing that pure quartz is responsive to LS flooding and that clays are not absolutely needed; (c) Quartz plus kaolinite plus illite gave a slightly higher response than pure quartz so clays can play a role. Oil displacement results were also done for a pure quartz sand column, and this showed a strong response to the LS flood, confirming that clays are not absolutely needed.

CO&lt;sub&gt;2&lt;/sub&gt;在原油及高矿化度地层水体系中的溶解试验

CO&lt;sub&gt;2&lt;/sub&gt;在原油及高矿化度地层水体系中的溶解试验

CO&lt;sub&gt;2&lt;/sub&gt;在原油及高矿化度地层水体系中的溶解试验

CO&lt;sub&gt;2&lt;/sub&gt;在原油及高矿化度地层水体系中的溶解试验

State of stress in exhumed basins and implications for fluid flow: insights from the Illizi Basin, Algeria

AbstractThe petroleum prospectivity of an exhumed basin is largely dependent on the ability of pre-existing traps to retain oil and gas volumes during and after the exhumation event. Although faults may act as lateral seals in petroleum traps, they may start to become hydraulically conductive again and enable fluid flow and hydrocarbon leakage during fault reactivation. We constrain the present day in situ stresses of the exhumed Illizi Basin in Algeria and demonstrate that the primary north–south and NW–SE (vertical strike-slip) fault systems in the study area are close to critical stress (i.e. an incipient state of shear failure). By contrast, the overpressured and unexhumed Berkine Basin and Hassi Messaoud areas to the north do not appear to be characterized by critical stress conditions. We present conceptual models of stress evolution and demonstrate that a sedimentary basin with benign in situ stresses at maximum burial may change to being characterized by critical stress conditions on existing fault systems during exhumation. These models are supportive of the idea that the breaching of a closed, overpressured system during exhumation of the Illizi Basin may have been a driving mechanism for the regional updip flow of high-salinity formation water within the Ordovician reservoirs during Eocene–Miocene time. This work also has implications for petroleum exploration in exhumed basins. Fault-bounded traps with faults oriented at a high angle to the maximum principal horizontal stress direction in strike-slip or normal faulting stress regimes are more likely to have retained hydrocarbons in exhumed basins than fault-bounded traps with faults that are more optimally oriented for shear failure and therefore have a greater propensity to become critically stressed during exhumation.

Numerical simulation of chemical potential dominated fracturing fluid flowback in hydraulically fractured shale gas reservoirs

To find out the impact of chemical potential difference between the low salinity fracturing fluid and the high salinity formation water on fracturing fluid flowback, a chemical potential difference expression of fracturing fluid and formation water was deduced, on this basis, a mathematical model which considers viscous force, capillary force and osmosis pressure driven gas-water flow in matrix-fracture system was built, the flow back performance of fracturing fluid driven by chemical potential difference was simulated, and the formation water saturation and salt concentration profile with flow back time were analyzed. The results show that in the process of flow back, the water molecules in the matrix driven by the chemical potential difference continually migrated to the deeper reservoirs, while salt ions in the matrix constantly spread to the fractures. After 168 h of fracturing-fluid flow back, the migration distance of water was up to 40 cm, and the salt concentration near the fracture surface increased by 0.841%, and the cumulative flowback ratio of the gas well was only 22.1%. The cumulative flowback ratio would be 23.5%, 32.4% and 41.1% respectively, without taking into account the effect of gas absorption, chemical osmosis or capillary imbibition. The capillary imbibition and chemical osmosis seriously hindered the fracturing-fluid flow back, therefore, the two factors should be fully considered in the post-fracturing evaluation of shale gas wells.

Electrokinetics of Carbonate/Brine Interface in Low-Salinity Waterflooding: Effect of Brine Salinity, Composition, Rock Type, and pH on ?-Potential and a Surface-Complexation Model

Summary Laboratory studies have shown that wettability of carbonate rock can be altered to a less-oil-wetting state by manipulation of brine composition and reduction of salinity. Our recent study (Mahani et al. 2015b) suggests that surface-charge alteration is likely to be the driving mechanism of the low-salinity effect in carbonates. Various studies have already established the sensitivity of carbonate-surface charge to brine salinity, pH value, and potential-determining ions in brines. However, in the majority of the studies, single-salt brines or model-carbonate rocks have been used and it is fairly unclear how natural rock reacts to reservoir-relevant brine as well as successive brine dilution; whether different types of carbonate-reservoir rocks exhibit different electrokinetic properties; and how the surface-charge behavior obtained at different brine salinities and pH values can be explained. This paper presents a comparative study aimed at gaining more insight into the electrokinetics of different types of carbonate rock. This is achieved by ζ-potential measurements on Iceland spar calcite and three reservoir-related rocks—Middle Eastern limestone, Stevns Klint chalk, and Silurian dolomite outcrop—over a wide range of salinity, brine composition, and pH values. With a view to arriving at a more-tractable approach, a surface-complexation model (SCM) implemented in PHREEQC software (Parkhurst and Appelo 2013) is developed to relate our understanding of the surface reactions to measured ζ-potentials. It was found that regardless of the rock type, the trends of ζ-potentials with salinity and pH are quite similar. For all cases, the surface charge was found to be positive in high-salinity formation water (FW), which should favor oil-wetting. The ζ-potential successively decreased toward negative values when the brine salinity was lowered to seawater (SW) level and diluted SW. At all salinities, the ζ-potential showed a strong dependence on pH, with positive slope that remained so even with excessive dilution. The sensitivity of the ζ-potential to pH change was often higher at lower salinities. The existing SCMs cannot predict the observed increase of ζ-potential with pH; therefore, a new model is proposed to capture this feature. According to modeling results, formation of surface species, particularly &amp;gt;CaSO4− and to a lower extent &amp;gt;CO3Ca+ and &amp;gt;CO3Mg+, strongly influence the total surface charge. Increasing the pH turns the negatively charged moiety &amp;gt;CaSO4− into both negatively charged &amp;gt;CaCO3− and neutral &amp;gt; CaOH entities. (Note that throughout this paper, the symbol &amp;gt; indicates surface complexes.) This substitution reduces the negative charge of the surface. The surface concentration of &amp;gt;CO3Ca+ and &amp;gt;CO3Mg+ moieties changes little with change of pH. Nevertheless, besides similarities in ζ-potential trends, there exist notable differences in terms of magnitude and the isoelectric point (IEP), even between carbonates that are mainly composed of calcite. Among all the samples, chalk particles exhibited the most negative surface charges, followed by limestone. In contrast to this, dolomite particles showed the most positive ζ-potential, followed by calcite crystal. Overall, chalk particles exhibited the highest surface reactivity to pH and salinity change, whereas dolomite particles showed the lowest.

Regional Geochemistry and Fluid Flow in the Palaeogene Aquifers of the Gaoyou Subbasin in the Southern Part of North Jiangsu Basin, China

AbstractChemical analysis of groundwater in petroliferous basins can be an effective way to determine the regional hydrogeological regime and to evaluate the preservation conditions of hydrocarbons. This paper presents the hydrochemical distribution of both individual aquifers and different structural units within the Palaeogene strata of the Gaoyou subbasin in the North Jiangsu Basin, east China. The results show that the salinity of the Palaeogene aquifers in the Gaoyou subbasin displays a systematic increase from the central deep depression to the periphery areas, and shows a reverse trend as the burial depth increases. Salinity maps of individual aquifers suggest that formation water in the deep layers at the centre of the study area probably retains original features of fresh lake water. Geofluids near the central deep depression of the Gaoyou subbasin migrate vertically through the Zhenwu and Hanliu faults, while those of the northern slope belt mainly flow laterally through aquifers. Both low and high salinity formation water can be found in the hydrocarbon producing areas. The low salinity zones commonly affected by infiltrated meteoric water are unfavourable conditions for the preservation of trapped hydrocarbons.

Environmental impacts of hydraulic fracturing in shale gas development in the United States

Abstract Through comprehensive investigation of the environmental issues in shale gas development in the US, the environmental impacts of hydraulic fracturing in shale gas development are summarized to provide reference for the shale gas development and management in China. The environmental risks of large-scale commercial shale gas development in the United States include water consumption, water contamination, seismic inducement and air pollution. Compared to conventional oil and gas production and other energy producing industries, shale gas development is not exactly “high-water-consuming” in terms of water consuming intensity. Its water consumption, accounting for a small proportion of the total regional water consumption, will not add much more stress on water supply. In terms of water pollution, hydraulic fracturing is unlikely to cause fractures to directly connect reservoir to the shallow aquifer, the known contamination cases are most likely related to faulty well completion, therefore well integrity is the key to the prevention of contamination; the flow-back fluids in large scale shale gas development have the characteristics of large quantity, many kinds of pollutants and complex composition, thus improper treatment would lead to serious contamination, and continuous monitoring and assessment of the pollutants are necessary. Existing evidence shows that hydraulic fracturing is unlikely to trigger destructive earthquakes. Greenhouse gas emissions in the life cycle of shale gas wells were estimated differently, but no doubt more effective measures should be taken to minimize leakage. The research priorities include contamination monitoring program design, detection indicators, moving pattern of hydraulic fracturing fluid and formation fluid, the effects of shale gas development on high salinity formation water and methane migration, and treatment and re-use of flow-back fluid.