Composition Of Formation Waters Research Articles

STRATIGRAPHY AND DIAGENESIS OF THE THAMAMA‐B RESERVOIR ZONE AND ITS SURROUNDING DENSE ZONES IN ABU DHABI OILFIELDS AND EQUIVALENT OMAN OUTCROPS

We review published studies characterizing the Thamama‐B reservoir zone in the upper Kharaib Formation (late Barremian) in Abu Dhabi oilfields and at outcrops in Oman. Available data for oxygen and carbon isotope compositions, fluid inclusion measurements, cement abundance and formation water composition are interpreted in terms of a paragenetic model for the Thamama‐B in field F in Abu Dhabi where the interval is deeply buried. The present synthesis provides a useful basis for understanding and predicting reservoir quality in static models and undrilled prospects, as well as for planning promising directions for further research. The goals of this study were to summarize the geologic setting and petrology of the Thamama‐B reservoir and its surrounding dense zones, and to examine how sedimentology, stratigraphy and diagenesis have interacted to control porosity and permeability. Results that may have useful applications for similar microporous limestone reservoirs in general include: the depositional environments and stratigraphy of the subject strata; a model for how porosity variations result mainly from calcite cementation sourced from stylolites, with little dependence on lithofacies other than the localization of chemical compaction by depositional clay linked to sequence stratigraphy; the use of solidity (rock thickness with porosity removed) as a check on porosity creation by burial dissolution; observations linking high‐permeability streaks with storm lag beds and fractures; the concept of strata being gradually buried through a relatively static salinity‐stratified water column; integration of conventional and clumped stable‐isotope data with petrologic observations to constrain the timing of porosity evolution.

Исследование микроэлементного состава нефтяных пластовых вод c использованием сорбционного и пламенноионизационного методов

Using sorption and flame ionization methods, the microelement composition of formation waters associated with Azerbaijani oil fields (Lokbatan and Bibiheybat) was studied. The sorbents used were cross-linked copolymers obtained from co-oligomers of alkenylphenols, formaldehyde, maleic anhydride, and other compounds (three- dimensional structures of 4 types). The influence of the structure of the sorbent and the composition of water on the degree of extraction of microelements was studied. It has been established that cross-linked copolymersobtained on the basis of 4-isopropenylphenol and maleic anhydride have the highest sorption properties.

Interplay between microbial activity and geochemical reactions during underground hydrogen storage in a seawater-rich formation

Subsurface hydrogen storage would be one of the main possible solutions for a successful energy transition in the future of world energy. However, hydrogen gas is an electron donor which may lead to microbial activity when storing hydrogen in the subsurface. Methanogenesis, acetogenesis, and sulfate reduction are the primary biological reactions that can lead to hydrogen loss through biochemical processes. This paper presents a novel bio-geochemical modelling approach which considers the kinetics of microbial reactions as well as the equilibrated geochemical reactions in the context of underground hydrogen storage. The findings demonstrate that the type of mineralogy and formation water composition may greatly influence biochemical reactions and thus potentially the storage/recovery performance of hydrogen. This study provides a detailed comparison and analysis of the behaviour occurring in calcite, dolomite, and quartz systems assuming the North Sea seawater composition as the in-situ brine. It is found that dolomite is the least favourable mineralogy in terms of hydrogen loss and hydrogen sulfide production, while calcite and quartz are better suited in a seawater-rich environment.

The origin of two distinct diagenetic depth zones in hydrocarbon-bearing sediments of Huanghekou Sag, offshore Bohai Bay Basin, China

Formation waters from the Huanghekou Sag, offshore Bohai Bay Basin, exhibited two depth zones with elevated total dissolved solid (TDS) composition. The shallow diagenetic zone at a depth of ∼1200–2000 m (∼45–70 °C) and the deep diagenetic zone at a depth of ∼3000–4000 m (∼100–130 °C) have TDS concentrations exceeding 70,000 mg/L, while the depth interval in between the two zones has TDS concentrations lower than 35,000 mg/L. Isometric log-ratio interpretations of the reconstructed formation water compositions, crude oil compositions, stable hydrogen and oxygen isotopes, light microscopy and clay mineral analysis were used to interpret the origins of the two diagenetic depth zones. Formation waters within each stratigraphic unit were dominantly composed of Na–K–Cl type. Processes affecting the deep diagenetic zone were attributed to (1) the dissolution of halite, albite and albitization, which predominantly caused the TDS enrichment, and (2) the dilution of TDS caused by the inter-layer H2O released from the transformation of smectite to illite (salinity reversal at depths > ∼3500 m). In comparison, the enrichment in TDS in the shallow diagenetic zone was attributed to hydrocarbon biodegradation, which consumed free water. The crude oil composition indicates severe hydrocarbon biodegradation. Biodegradation of low-molecular-weight organic carbons such as hexadecane (through methanogenesis) and benzene (through microbial sulfate reduction) could consume sufficient H2O to enrich TDS to the observed levels. At the same time, relatively constant Na/Cl and Ca/Cl ratios versus TDS can be explained by water consumption as well. This work could serve as a reference for the interpretation of two diagenetic zones characterised by distinct TDS enrichments in other hydrocarbon-bearing sedimentary basins.

Simulation of Hydrate Plug Formation During Joint Operation of a Gas-Bearing Reservoir and a Well for the Case where the Equilibrium Conditions of Hydrate Formation Depend on Formation Water Composition

Simulation of Hydrate Plug Formation During Joint Operation of a Gas-Bearing Reservoir and a Well for the Case where the Equilibrium Conditions of Hydrate Formation Depend on Formation Water Composition

Formation Waters Delineate Diverse Hydrogeologic Conditions at a Plate Scale: Eastern Flank of the Juan de Fuca Ridge

AbstractThe chemical composition of formation waters within the upper basaltic crust were calculated or measured at 24 sites on the northwest portion of the Juan de Fuca (JDF) Plate using data from sediment pore waters, scientific boreholes, and seafloor springs. Formation waters differ in composition across this ridge‐flank region because of variations in water‐rock reactions and residence times, exchange rates with overlying sediment pore waters, and microbial processes along flow paths. We interpret spatial variations in the solute composition of formation waters to resolve areas that are geochemically distinct or similar, lateral trends that result from water transport, areas where water‐rock reactions in the deeper crust are apparent, and sites of seawater recharge and formation water discharge. We provide evidence for large‐scale lateral flow associated with two (mostly) buried basement ridges on ∼1.4 and ∼3.5 Ma seafloor, which are subparallel to the JDF spreading axis to the west. Between these two ridges, where the seafloor and the sediment‐basement interface are relatively flat, formation waters have undergone extensive exchange with overlying sediment pore waters, consistent with a long residence time. Basaltic outcrops provide sites of seawater recharge and hydrothermal discharge, sometimes through the same feature, highlighting the heterogeneous nature of hydrogeologic conditions and processes. This work provides a blueprint for future plate‐scale studies to assess, for example, geologic controls of crustal age, spreading rate, and sedimentation on subsurface hydrologic patterns.

Implications of CO[formula omitted] mass transport dynamics for large-scale CCS in basalt formations

Flood basalts have the potential for relatively rapid mineral trapping when used as an injection target for CO2 storage. Although CO2 mineral trapping in basalt has been studied in various ways, including two successful small-scale pilot projects, questions remain about how the system will behave during a full-scale CO2 storage project. These questions include whether a full-scale CO2 injection can expect complete mineralization on time scales similar to those observed during small-scale injections, as well as how the properties of the target formation will be altered by decades of geochemical reactions. Recently, we developed VIRTra, a vertically integrated reactive transport model specifically designed for efficient field-scale simulation of CO2 storage in reactive rocks. The present work uses this new method to explore the behavior of the water-CO2-basalt system during large-scale injection of separate-phase CO2 in a deep saline aquifer. Trends in the assembled data indicate that a high rate of CO2 dissolution into the aqueous phase results in faster mineralization. However, the time scales on which full mineralization of the injected CO2 is achieved are on the order of centuries, orders of magnitude larger than those observed in small-scale field tests. This appears to be a direct result of the increase in scale of the injection. During the injection period, changes in porosity are observed to be highly dependent on mineral reaction kinetics. Important areas of further research include the impact of mineralogy and formation water composition on the mineralization process, and the relationship between porosity and permeability in vesicular rock types.

Hydrogeochemistry of oil-field formation water in relation to diagenesis of reservoirs: A case study from Shahejie formation, Dongying Depression

The composition of formation waters in the Dongying Depression provide important clues about regional water-rock interactions. Chemical analysis (181 samples) of formation waters form the Shahejie Fm (58 wells) in the Niuzhuang oilfield suggest two main geochemical facies, the chloride-magnesium (Cl–Mg) and bicarbonate-sodium (HCO3–Na) facies (pH = 7.8 ± 0.9) that have low salinity (TDS = 7.3 ± 7.8 g/L) and occurs within source rocks, and the Cl–Ca facies (pH = 6.5 ± 0.7) that has high salinity (TDS = 79.1 ± 79.0 g/L) and occurs within clastic reservoirs.For the water within the clastic reservoirs, salinities and dissolved chloride concentrations (47.8 ± 48.8 g/L) are attributed to halite dissolution. The broad systematic increase in dissolved Mg2+ and Ca2+, and decrease in pH with increasing salinity (Na+ concentration) strongly suggest that the formation water has been thermodynamically buffered by silicate-carbonate mineral assemblages. The Caexcess increase with Nadeficit suggests that the albitization of detrital plagioclase (anorthite) might have provided a internal source for Ca2+. The pH was mainly buffered by silicate minerals, which is indicated by the increase of acidity with Na+. This is also consistent with the externally buffered carbonate system indicated by the negative correlation of log(HCO3−) with log(Ca2+). The increasing acidity associated with the addition of Na+ might have been responsible for the abundant kaolinite and secondary porosity developed by K-feldspar dissolution.The contribution from halite dissolution to formation waters within the source rocks was relatively restricted. The positive correlation of log(HCO3−) with log(Ca2+) suggests an internally buffered carbonate system. The formation water might have been partly buffered by illitization, which is consistent with the negative correlation of Nadeficit with Caexcess.

Shale gas preservation conditions of Lower Paleozoic Niutitang formation in southeastern Chongqing, China: Evidence from formation water and shale gas components

To quantitatively characterize the preservation conditions of shale gas in different wells, the formation water and gas composition characteristics of five wells (YC1, YY6, YY1, YK1, and QQ1) in southeastern Chongqing were analyzed. The formation water type of QQ1 and YK1 is CaCl2, and CY1 includes CaCl2 and NaHCO3 types. The CNa/Cl and Cd are low, while CCa/Mg and CCl/Mg are high, indicating that the retention degree of formation water is high. The formation water of YY6 and YY1 is NaHCO3 type, the CNa/Cl and Cd are high, while the CCa/Mg and CCl/Mg are low, indicating the strong connectivity of formation water. The N2 content of wells QQ1 and YK1 is below 32%, and 15N is between −7.33‰ and −1.98‰, the source of nitrogen is ammoniated in the process of organic matter pyrolysis and hydrocarbon generation, and the preservation conditions are relatively good. Therefore, the preservation conditions combined with the metamorphic degree of formation water and gas composition can be judged.

Wettability alteration and improved oil recovery in unconventional resources

The ultimate recovery factor in tight and shale resources is limited and is usually in the range of 5–10%. Although high-intensity fracturing and refracturing can increase recovery, an enormous amount of oil will remain in place, hence the desirability of enhanced oil recovery methods. Many of the shale reservoirs are oil-wet with negligible water uptake. By altering the wettability, water can spontaneously imbibe into the formation matrix, creating a counter-current flow that forces the oil out. Here, we assess the likelihood of increased oil recovery by modifying the fracturing-fluid composition (salinity and ion concentration) that transforms the formation wettability into a more water-wet state.Oil wetting of tight formations is usually controlled by the adhesion of oil droplets on the surface of clay minerals. When clay minerals are not predominant, the oil attached to carbonate minerals can significantly control rock wettability. In this study, we first identify the primary reactions that define the initial wettability of the rock depending on the formation mineralogy, formation water composition, and oil type. Second, we build a geochemical model considering the surface complexation of various minerals to mimic the wettability state of the reservoir. Third, we validate our method on zeta-potential, contact angle, and imbibition data from a previously published study using different fluids with different salinities. Finally, we present a mechanistic approach to model the wettability-alteration impact on spontaneous imbibition and compute the incremental oil recovery contributed by different fracturing fluid compositions.Based on the studied case, the oil adhesion to clay can be reduced by tuning the fracturing fluid salinity. The ionic concentrations of 2.5 wt % of NaCl and 5.0 wt % of CaCl2 induced the smallest contact angles of 44.7 and 51.2°. We observe that further brine dilution increases the contact angle. For example, distilled water shows the most oil-wet condition with a contact angle to 93.4°. We argue that the main factors that maximize water wetting for the reported optimum salinities are the contrast in the rock and oil surface potential and the sodium concentration. Spontaneous-imbibition simulations indicate that the low salinity fluids promote a change in water-oil capillary pressure, leading to increased water uptake in the cores and improved oil recovery compared to distilled water. The agreement between the developed model and experimental data implies that the wettability in shale and tight formations can be quantitatively predicted and regulated.

Composition of Formation Water and Natural Gas as an Indicator of Shale Gas Preservation Conditions: A Case Study of the Marine Shale of the Niutitang Formation in the Cengong Block in Northern Guizhou, China.

Shale gas (SG) wells in the Wufeng–Longmaxi Formation in northern Guizhou differ considerably in their production capacities. Preservation conditions are a crucial factor affecting the formation of SG reservoirs. In this study, the formation water (FW) in four wells in northern Guizhou was analyzed to determine the type; the Cl/Mg, Ca/Mg, and Na/Cl coefficients (CCl/Mg, CCa/Mg, and CNa/Cl, respectively), and the coefficient of desulfurization (Cd); the SG in these wells was tested to identify its composition and the sources of its components. The results show the following: wells TX1 and CY1 contain two types (CaCl2 and NaHCO3) of FW, each with low CNa/Cl, low Cd, high CCa/Mg, and high CCl/Mg, suggesting a high level of FW retention. The FW in wells TM1 and CD1 is of NaHCO3 type and is characterized by high CNa/Cl, high Cd, low CCa/Mg, and low CCl/Mg, indicating a high level of connectivity between the FW and surface water. Nonhydrocarbon gases account for a high proportion of SG in composition; with a 15N value between −8.7 and −4.2‰, N2 accounts for approximately 20% of SG in wells TX1 and CY1, respectively. This result indicates the ammonification of organic matter (OM) during pyrolysis and hydrocarbon generation as sources of N2. In contrast, with a 15N value between −3.6 and 0‰, N2 accounts for over 70% of SG in wells TM1 and CD1, respectively, indicating the atmosphere, the ammonification of OM, and the presence of poor preservation conditions due to a high level of connectivity between the shale bed and the atmosphere acted as the sources of N2. The metamorphism coefficients of FW in conjunction with the SG composition and the sources of nonhydrocarbon gases can serve as auxiliary indicators of the quality of SG preservation conditions.

Environmental Impacts of chemical composition Produced Water (оn the Siyazan field example)

This article describes the increased environmental impact of fuel energy complex depending on growth in oil and gas production. At the moment, due to the intensification of oil and gas production, associated mineralized reservoir water is one of the main sources for environmental pollution, and sufficiently plays role at soil cover degradation. This paper reviews recent research analysis of the physical chemical composition of formation water and the effect of this composition on soil ecosystems on the example of monocline of Siyazan field. Water samples have been taken from of monocline of Siyazan field. This information has been used to determine the most significant contaminants and their geochemical behaviour. Based on the analysis results, the examined formation water samples were characterized in terms of various classifications used in oil and gas hydrogeology. And, conclusions were drawn and it was noted that the hydrochemical composition of mineralized reservoir waters to degradation of biocenoses and soil cover.

Search for hydrogeochemical indicators of the genetic relation between mud volcanism and oil and gas fields

The paper reports the results of a comparative analysis of the chemical and isotope composition (δ180 and δD) of mud volcanic waters and formation waters from oil and gas fields. Studies show that the waters discharged by mud volcanoes in most cases are very similar to formation waters. The most characteristic geochemical traits of both waters are elevated concentrations of hydrocarbonate ions, iodine, boron, bromine, and a low content of sulfate ions.

Investigation of Water Composition on Formation Damage and Related Energy Recovery from Geothermal Reservoirs: Geochemical and Geomechanics Insights

The main challenge in extracting geothermal energy is to overcome issues relating to geothermal reservoirs such as the formation damage and formation fracturing. The objective of this study is to develop an integrated framework that considers the geochemical and geomechanics aspects of a reservoir and characterizes various formation damages such as impairment of formation porosity and permeability, hydraulic fracturing, lowering of formation breakdown pressure, and the associated heat recovery. In this research study, various shallow, deep and high temperature geothermal reservoirs with different formation water compositions were simulated to predict the severity/challenges during water injection in hot geothermal reservoirs. The developed model solves various geochemical reactions and processes that take place during water injection in geothermal reservoirs. The results obtained were then used to investigate the geomechanics aspect of cold-water injection. Our findings presented that the formation temperature, injected water temperature, the concentration of sulfate in the injected water, and its dilution have a noticeable impact on rock dissolution and precipitation. In addition, anhydrite precipitation has a controlling effect on permeability impairment in the investigated case study. It was observed that the dilution of water could decrease formation of scale while the injection of sulfate rich water could intensify scale precipitation. Thus, the reservoir permeability could decrease to a critical level, where the production of hot water reduces and the generation of geothermal energy no longer remains economical. It evident that injection of incompatible water would decrease the formation porosity. Thus, the geomechanics investigation was performed to determine the effect of porosity decrease. It was found that for the 50% porosity reduction case, the initial formation breakdown pressure reduced from 2588 psi to 2586 psi, and for the 75% porosity reduction case it decreased to 2584 psi. Thus, geochemical based formation damage is significant but geomechanics based formation fracturing is insignificant in the selected case study. We propose that water composition should be designed to minimize damage and that high water injection pressures in shallow reservoirs should be avoided.

Deriving optimal and adaptive nanoparticles-assisted foam solution for enhanced oil recovery applications: an experimental study

Here, Fe2O3 and SiO2 nanoparticles are synthesized and utilized to investigate their effects on foam stability and flowing behavior in porous media. At first, the effect of main operative parameters including surfactant concentration, formation water composition and dosage, and temperature on foam stability are studied at static condition for preparation of an optimal foam solution. Then, the synthesized nanoparticles are dispersed in optimal foam solution for subsequent main experiments. High pressure-high temperature microscopic injection experiments are employed to assess the oil-flow displacement in heterogeneous porous medium pattern by foam injection in the absence and presence of the nanoparticles. The results show that sodium dodecyl sulfonate surfactant concentration of 0.75 wt% provides the optimal dosage independent of other factors. The foam solution becomes unstable with increasing the salinity. Conversely, the presence of more sulfate ions improves the foam stability and foam textural characteristics. In the presence of the synthesized nanoparticles significant enhancement of foam solution stability is observed. Microscopic analysis of the injection experiments in glass micromodel reveals postponement of the displacing fluid breakthrough time, lessening the severity of the finger phenomenon at displacement front, and higher oil recovery for Fe2O3 and SiO2 nanoparticles-assisted foam solutions. However, the enhancement of the foam textural features and flowing behavior are more manifest in the case of SiO2 nanoparticles compared to the Fe2O3 nanoparticles.

Applied random forest for parameter sensitivity of low salinity water Injection (LSWI) implementation on carbonate reservoir

This study applied a Machine Learning Algorithm based on Random Forest Regression for eliminating the insignificant parameter and evaluating the correlation between each parameter and response parameter on the LSWI process. 1000 experimental designs of LSWI parameters, Reservoir & Injection Temperature, Volume Injection, Formation Water Composition, and Injection Water Composition were build using Design of Experiment on CMOST from Computer Modeling Group with Recovery Factor as the response parameter. Finally, the sensitivity analysis is carried out on Random Forest Regressor based on the decrease in the mean squared error (MSE). The Random Forest Algorithm methods respectively recognized Injection SO42- Composition, Formation Water SO42-Composition dan Volume Injection as the top three of most significant parameters. Five variations of the random state value are applied and the hyperparameters of Random Forest also optimized. Both training and test data, the R2 score respectively are consistently over 0.9 for 5 variations of the random state used. The information about the significant operation parameter of the LSWI process presented in this article is potential bearing the novel to the industry. The insight into those parameters is predicted to be useful to encourage the LSWI implementation on Carbonate Reservoir.

Mapping of potential environmental risks associated to formation water in the Oriente Basin, Ecuador

Formation water is the water produced jointly with oil as part of oil production process, which in Ecuador it is performed mainly within the Amazon region. Despite this region is highly vulnerable, due to its biodiversity and hydrological richness, formation water is produced in large volumes, contains toxic substances and receives limited treatment. This research determined the spatial distribution of the potential environmental risks associated to formation water chemical composition using geographic information systems to generate risk and vulnerability maps. Specifically, the objectives were 1) to analyze the chemical composition of formation water; 2) to compare formation water chemical composition between oil fields; 3) to determine the level of vulnerability of the environment and nearby populations; 4) to map the potential environmental risks associated to formation water; and 5) to review the current water treatment methods. Results show that formation water contains elements that are carcinogenic and with high bioaccumulation potential, like cadmium. Moreover, their concentration varies depending on the reservoir from where the water is extracted and the geographical location of the field. The potential risk of an area is determined by its well density, formation water quality and production volume, and the course of any nearby river. Therefore, Blocks 15 and 57 and the basin of the Aguarico River are associated to high environmental risk. Finally, water treatment process removes suspended solids and oil, while production chemicals slightly contribute to its toxicity. To track environmental potential risks, it is suggested periodical water quality evaluations of nearby rivers, similar environmental studies, and better land use planning by the local governments considering the potential risks associated to oil production activities.

Scaling tendency prediction in water injection well of K2 formation of C68 block

The K2 formation of C68 block is explored by injecting water to maintain formation pressure, but the continuous decrease of injection rate significantly reduces oil production. Therefore, it is important to predict scaling tendency of injected water in the formation. Firstly, ion composition of formation water and injected water was tested according to recommended practices in petroleum industry. Then, wellbottom temperature distribution of injection wells was simulated under injection water rate requirement of oilfield development. Furthermore, based on the “Oddo-Tomson” prediction model of inorganic scale, the scaling trend of water flooding in K2 formation is predicted according to the possible temperature and pressure. The research indicates that sulfate scale cannot be formed in C68 block and there is a slight possibility of carbonate scaling, which provides a basis to select the correct stimulation technology for increasing production.

Carbon Capture & Storage: Rock Experimental Characterization & Modelling Prospective

Geological storage of carbon dioxide is one of the options of greenhouse gas mitigation as it reduces the release of CO2 to the atmosphere. Eni is a major energy company in which decarbonization plays an essential role in its vision for a future with zero net emissions. H field carbon storage project comes in line with Eni strategy of carbon neutrality by 2050. Depleted gas fields are among the most suitable candidates for CO2 sequestration, with well-known high quality reservoir characteristics and good sealing. H is a depleted offshore gas field located in the North Sea; it has two main reservoirs: H1 and H2. Due to the massive size of both reservoirs, well-known reservoirs’ characterization, good reservoirs’ petrophysics, and the existence of thick and continuous cap layers (C1 & C2), H1 and H2 reservoirs have been nominated to be good candidates for a carbon sequestration project. The study objective is to build comprehensive mineralogical and geochemical models able to capture the physical and the chemical phenomena occurring in the short – medium – long terms after the CO2 injection in H1 and H2 formations. The proposed workflow relies on the following procedure: 1. laboratory experimental analyses (SEM-EDX, XRD, XRF) on core samples 2. data elaboration and integration 3. conceptual geological-geochemical models’ definition 4. 0D static batch models a. equilibrium approach b. kinetic approach Step 1, 2 and 3 are aimed at obtaining the mineralogical model, with attention devoted to the presence of the Fe-bearing minerals. In step 4, the rock-formation water geochemical system consistence is preliminary checked by performing a sequence of 0D equilibrium models with PHREEQC-V3 code, (USGS, 1999), allowing primary evaluations on mineral phases chemical stability (dissolution/precipitation). This step is also needed for obtaining a synthetic formation water composition at the equilibrium with the mineralogical model used in the subsequent reactive transport models (RTM), and to validate new-estimated site-specific minerals thermochemical parameters. Then, the CO2 injection is preliminary simulated by means of 0D kinetic models to assess the main acting geochemical processes triggered by rock-brine-CO2 interaction. The results show that, at the conditions considered in the project, the rock petrophysical properties (e.g. porosity) alteration does not seem to be an issue. However, the main criticalities/uncertainties might be related to the Fe-bearing minerals (carbonates, micas and clays) chemical behavior in presence of CO2. As a final remark, the simulation results obtained in this work cannot be regarded as values of general validity because they depend on the characteristics assigned to each reservoir model. Nevertheless, the study provides a novel geochemical modelling procedure, which implies building a detailed geochemical conceptual model modelled by means of a complex kinetic reaction network to simulate the mineralogical alterations. The presented procedure can be followed to preliminary assess the geochemical short- and long-term risks for a given carbon storage project.

Experimental study of CO2 huff-n-puff in a tight conglomerate reservoir using true triaxial stress cell core fracturing and displacement system: A case study

To reveal the enhanced oil recovery (EOR) potential of CO2 huff-n-puff in fractured tight conglomerate reservoirs, hydraulic fracturing combined with CO2 huff-n-puff experiments were conducted using a true triaxial stress cell core fracturing and displacement system. To better understand the potential mechanisms behind CO2 huff-n-puff, the change in rock properties and formation water properties caused by the interactions among supercritical CO2/formation water/oil/rock were investigated. Experimental results demonstrate that CO2 huff-n-puff is viable to boost oil recovery in tight conglomerate reservoirs with recovery factor of 23.2% after hydraulic fracturing and depletion process. Rock surface morphology, mineralogical composition and formation water composition analysis indicate that supercritical CO2 leads the water-oil-rock system to more water-wet by increasing rock surface roughness. Geochemical simulation results combining the surface complexation and ion-exchange shows that supercritical CO2 weakens the crude oil adsorption on rock surface, which also contributes to the oil recovery increment. These results reveal the EOR feasibility of CO2 huff-n-puff in fractured tight conglomerate reservoirs, and provide insights to characterize geochemical features of carbonated brine/oil/rock.