Seawater Injection Research Articles

Data Science Enables Management of Stealth Asphaltene Flow-Assurance Risk

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216216, “Managing Stealth Asphaltene Flow-Assurance Potential Risk in Gas-Injection Field Based on Data Science Using Over 20-Year Accumulated Data Set,” by Hideharu Yonebayashi, SPE, and Takeshi Hiraiwa, SPE, Japan Oil Development, and Khuloud T. Al Khlaifi, SPE, ADNOC, et al. The paper has not been peer reviewed. _ Gas injection is recognized generally not only to improve oil recovery but also to increase the risk of asphaltene destabilization. The recent discovery of asphaltene deposits in a subject field motivated the operator to launch an immediate investigation to evaluate what critical risks might exist and consider appropriate mitigation. It was found that precipitated but invisible asphaltenes still can be flowable. This stealth asphaltene behavior could explain a possible mechanism of the first asphaltene observation in the upper reservoir. Introduction The subject giant offshore field in the Arabian Gulf has not experienced asphaltene-induced production deterioration during long-term lean hydrocarbon gas injection. The gas has been injected into the crestal area of two reservoirs (upper and lower) with peripheral powered seawater injection. Both reservoir fluids contain a small amount of asphaltenes (0.1–1.5 wt%) distributed at higher concentration at deeper locations. In May 2022, the first discovery of asphaltene deposits from the historical no-issued area in the upper reservoir motivated an immediate investigation for risk assessment and mitigation. A resulting study captured stealth asphaltenes, which were detected by a laser-light-scattering technique while high-pressure microscopy detected no visible asphaltene solid particles. Historical Asphaltene Data Accumulation The permeability range and pore-throat size of the subject field are relatively low in the lower reservoir compared with the upper. Both reservoirs are under highly unstable asphaltene-stability conditions. The reservoir pressure-maintenance scheme, consisting of dump-floodwater injection followed by peripheral powered seawater injection and crestal gas injection, however, has maintained asphaltene-free production except for the gas-injection pilot (GIP) during 2005–2009. No asphaltenes have been observed in the crestal gas-injection area; however, asphaltene deposits were observed in the GIP area in 2007. The injected gas was enriched gradually by a vaporizing gas-drive process. The previous studies involving numerical modeling analysis and laboratory experiments reported that enriched hydrocarbon gas can more easily allow asphaltene precipitation compared with lean hydrocarbon gas. GIP Asphaltene Risk Analysis (Upper Reservoir). In 2009, an asphaltene flow-assurance risk evaluation was conducted using the single-phase bottomhole sample collected from Well 6, which is 90 ft shallower that the GIP area and far from the crestal gas-injection area. Therefore, the Well 6 reservoir fluid was not affected by injection gas. The bottomhole condition of the GIP production well was entered into the asphaltene precipitation envelope (APE) that was expanded by injection-gas enrichment but never covered by the APE without an enrichment process. Latest Laboratory Analysis (Lower Reservoir). In 2022, an asphaltene flow-assurance risk evaluation was conducted. After the location was narrowed to a depth range, Well 1 was selected by taking an asphaltene gradient into account.

Optimizing CO2 Hydrate Sequestration in Subsea Sediments through Cold Seawater Pre-Injection

Carbon sequestration technology offers a solution to mitigate excessive carbon dioxide emissions and sustainable development in the future. This study proposes a method for subsea carbon sequestration through the injection of cold seawater to promote CO2 hydrate formation. Using a self-developed simulator, we modeled and calculated the long-term sequestration process. The study focuses on analyzing the thermal regulation of the seabed following cold seawater injection, the multiphysical field evolution during CO2 injection and long-term sequestration, and the impact of seawater injection volumes on sequestration outcomes. The feasibility and leakage risks of this method were evaluated on a 100,000-year timescale. Results indicate that the injection of cold seawater significantly improves the pressure–temperature conditions of subsea sediments, facilitating early hydrate formation and markedly increasing the initial CO2 hydrate formation rate. Consequently, the distribution pattern of hydrate saturation changes, forming a double-layer hydrate shell. Over the long term, while cold seawater injection does not significantly reduce CO2 leakage, it does increase the safety margin between the hydrate layer and the seabed, enhancing the safety coefficient for long-term CO2 hydrate sequestration. Through detailed analysis of the behavior of CO2 components during sequestration, this study provides new theoretical insights into subsea CO2 hydrate storage.

Transcriptomic and functional analysis of the antiviral response of mussels after a poly I:C stimulation

The study of mussels (Mytilus galloprovincialis) has grown in importance in recent years due to their high economic value and resistance to pathogens. Because of the biological characteristics revealed by mussel genome sequencing, this species is a valuable research model. The high genomic variability and diversity, particularly in immune genes, may be responsible for their resistance to pathogens found in seawater and continuously filtered and internalized by them. These facts, combined with the lack of proven mussel susceptibility to viruses in comparison to other bivalves such as oysters, result in a lack of studies on mussel antiviral response. We used RNA-seq to examine the genomic response of mussel hemocytes after they were exposed to poly I:C, simulating immune cell contact with viral dsRNA. Apoptosis and the molecular axis IRFs/STING-IFI44/IRGC1 were identified as the two main pathways in charge of the response but we also found a modulation of lncRNAs. Finally, in order to obtain new information about the response of mussels to putative natural challenges, we used VHSV virus (Viral Hemorrhagic Septicemia Virus) to run some functional analysis and confirm poly I:C's activity as an immunomodulator in a VHSV waterborne stimulation. Both, poly I:C as well as an injury stimulus (filtered sea water injection) accelerated the viral clearance by hemocytes and altered the expression of several immune genes, including IL-17, IRF1 and viperin.

Multiphysics Measurements for Detection of Gas Hydrate Formation in Undersaturated Oil Coreflooding Experiments with Seawater Injection

Multiphysics Measurements for Detection of Gas Hydrate Formation in Undersaturated Oil Coreflooding Experiments with Seawater Injection

IORSim: A Mathematical Workflow for Field-Scale Geochemistry Simulations in Porous Media

Reservoir modeling consists of two key components: the reproduction of the historical performance and the prediction of the future reservoir performance. Industry-standard reservoir simulators must run fast on enormous and possibly unstructured grids while yet guaranteeing a reasonable representation of physical and chemical processes. However, computational demands limit simulators in capturing involved physical and geochemical mechanisms, especially when chemical reactions interfere with reservoir flow. This paper presents a mathematical workflow, implemented in IORSim, that makes it possible to add geochemical calculations to porous media flow simulators without access to the source code of the original host simulator. An industry-standard reservoir simulator calculates velocity fields of the fluid phases (e.g., water, oil, and gas), while IORSim calculates the transport and reaction of geochemical components. Depending on the simulation mode, the geochemical solver estimates updated relative and/or capillary pressure curves to modify the global fluid flow. As one of the key innovations of the coupling mechanism, IORSim uses a sorting algorithm to permute the grid cells along flow directions. Instead of solving an over-dimensionalized global matrix calling a Newton–Raphson solver, the geochemical software tool treats the species balance as a set of local nonlinear problems. Moreover, IORSim applies basis swapping and splay tree techniques to accelerate geochemical computations in complex full-field reservoir models. The presented work introduces the mathematical IORSim concept, verifies the chemical species advection, and demonstrates the IORSim computation efficiency. After validating the geochemical solver against reference software, IORSim is used to investigate the impact of seawater injection on the NCS Ekofisk reservoir chemistry.Article HighlightsThe IORSim sorting algorithm decouples the nonlinear geochemical reaction calculations into recurring one-dimensional problems to assure numerical stability and computation efficiency. To the best of our knowledge, this work presents the mathematical concept, implementation, and application of topological sorting for the first time on (industry) field-scale problems.IORSim combines topological sorting with basis swapping and splay trees to significantly reduce computation times. Moreover, a high-speed forward simulation mode was developed to allow the post-advection of chemical components to visualize species distribution, water chemistry, and mineral interactions. If the geochemical reactions interfere with the fluid flow, the IORSim backward mode uses relative permeability curves to update the global fluid flow at each time step.We validate the implemented topological scheme on a reservoir grid, show the computation efficiency, and compare the impact of explicit, implicit, and grid refinement on numerical dispersion.The decoupled flow simulator and geochemical reaction calculations allow seamless integration of full-field reservoir models that contain complex geological structures, a large number of wells, and long production histories.The computation capabilities of IORSim are demonstrated by simulating and reproducing the impact of seawater injection in the southern segment of the giant Ekofisk field (more than 50 years of injection and production history). IORSim shows that seawater injection changed the Ekofisk mineralogy and impacted the produced water chemistry. In the investigated Ekofisk case, seawater promoted calcite dissolution and led to the precipitation of magnesite and anhydrite. Moreover, surface complexation modeling revealed that sulfate is adsorbed on the calcite surface.

Rock fluid interactions during seawater injection in carbonates: An experimental evaluation on dolomitization and anhydrite precipitation

Rock fluid interactions during seawater injection in carbonates: An experimental evaluation on dolomitization and anhydrite precipitation

Experimental investigation of the sequence injection effect of sea water and smart water into an offshore carbonate reservoir for enhanced oil recovery

This study explores enhanced oil recovery (EOR) strategies, with a focus on carbonate reservoirs constituting over 60% of global oil discoveries. While “smart water” injection proves effective in EOR for carbonate reservoirs, offshore application challenges arise due to impractical volumes for injection. To address this, we propose a novel continuous injection approach, systematically investigating it on a laboratory scale using the Iranian offshore reservoir, Sivand. Thirty-six contact angle tests and twelve flooding experiments are meticulously conducted, with key ions, potassium, and sulfate, playing pivotal roles. Optimal wettability alteration is observed at 4 times potassium ion concentration in 0–2 times sulfate concentrations, driven by ionic strength and charge interactions. Conversely, at 3–5 times sulfate concentrations, the optimal contact angle shifts to 2 times potassium ion concentration, suggesting a mechanism change linked to increasing sulfate ion ionicity. A significant wettability alteration, evidenced by a 132.8° decrease, occurs in seawater with a twofold concentration of potassium ions and a fivefold concentration of sulfate ions. Micromodel experiments introduce an innovative alternation of smart water and seawater injections. The first scenario, smart water followed by seawater injection, reveals negligible post-seawater injection oil recovery changes. In contrast, the second scenario yields a maximum recovery of 7.9%. The first scenario, however, boasts superior overall sweep efficacy, reaching approximately 43%. This research expands understanding of smart water and seawater injection in EOR, presenting a viable solution for optimizing offshore carbonate reservoir recovery. The insights contribute to evolving EOR methodologies, emphasizing tailored strategies for varying reservoir conditions.

Reactive transport modeling of scale precipitation and deposition during incompatible water injection in carbonate reservoirs

Seawater injection is an efficient enhanced oil recovery (EOR) method that capitalizes on the chemical composition differences between the injecting seawater and in-situ formation water, which leads to physicochemical interactions between the rock and fluids. These rock and fluid interactions result in changes of rock wettability and subsequent improved microscopic sweep efficiency. However, the ion imbalance resulting from seawater injection and its incompatibility with the in-situ formation water may interfere with the rock and fluids equilibrium state, causing scale precipitation and subsequent deposition which can negatively impact rock quality, well productivity and reservoir performance. In this study, an accurate, robust, and general approach is presented by coupling a geochemical module with a compositional two-phase fluid flow model to handle reactive transport in porous media. The proposed coupled model, so-called ad-scale model, is capable of simulating carbonate rock dissolution and sulfate scale formation/deposition for evaluating reservoir performance under incompatible water injection. The model predictions were validated using experimental data. This model was also utilized to predict water injection rate into a carbonate formation. It was obtained that both the reacting and non-reacting component profiles were accurately predicted using the proposed coupled model. The water injection rate prediction was also validated and showed high accuracy with absolute error and coefficient of determination values of 9.02% and 0.99, respectively. In addition, a sensitivity analysis was performed on water composition, which showed a strong dependence of reservoir and well performance on water composition.Graphical abstractThis diagram elucidates what exactly happens during incompatible water injection in the mixing zones near the injection well (right half of the figure) or production well (left half of the figure) where most of the geochemical phenomena occur.

Stratospheric ozone depletion inside the volcanic plume shortly after the 2022 Hunga Tonga eruption

Abstract. Near-term in-plume ozone depletion was observed for about 10 d by the Aura Microwave Limb Sounder (MLS) right after the January 2022 Hunga Tonga–Hunga Ha'apai (HTHH) eruption. This work analyzes the dynamic and chemical causes of this ozone depletion. The results show that the large water injection (∼ 150 Tg) from the HTHH eruption, with ∼ 0.0013 Tg injection of ClO (or ∼ 0.0009 Tg of HCl), causes ozone loss due to strongly enhanced HOx and ClOx cycles and their interactions. Aside from the gas-phase chemistry, the heterogeneous reaction rate for HOCl + HCl → Cl2 + H2O increases to 104 cm−3 s−1 and is a major cause of chlorine activation, making this event unique compared with the springtime polar ozone depletion where HCl + ClONO2 is more important. The large water injection causes relative humidity over ice to increase to 70 %–100 %, decreases the H2SO4 / H2O binary solution weight percent to 35 % compared with the 70 % ambient value, and decreases the plume temperature by 2–6 K. These changes lead to high heterogeneous reaction rates. Plume lofting of ozone-poor air is evident during the first 2 d after the eruption, but ozone concentrations quickly recover because its chemical lifetime is short at 20 hPa. With such a large seawater injection, we expect that ∼ 5 Tg Cl was lifted into the stratosphere by the HTHH eruption in the form of NaCl, but only ∼ 0.02 % of that remained as active chlorine in the stratosphere. Lightning NOx changes are probably not the reason for the HTHH initial in-plume O3 loss.

Modeling of formation damage during smart water flooding in sandstone reservoirs

Impairment of permeability has been observed as an effective factor in production decline during secondary and tertiary recovery processes such as water flooding. Among different permeability damage mechanisms, fines migration and deposition is known as the main mechanism which occurs due to pore throat clogging and blocking. Because injected water and formation water are usually incompatible, permeability damage evaluation and scale formation prediction must be done before the water flooding process in the oil field is implemented. For this purpose, compatibility tests and core flood experiments are common, but experimental approaches with time and facility limitations are expensive. Thus, by decreasing the time required for conducting experiments, modeling approaches can replace the routine laboratory experiments. Based on thermodynamic balance and the solubility of ions in water, scale development due to seawater injection in an Iranian oil field was predicted in this work using the OLI ScaleChem software. After that, it was suggested that special water be introduced to help reduce the amount of scales that had accumulated in the rock pore space. The extent of permeability damage in various seawater injection scenarios was then assessed via dynamic core flood experiments. Finally, scales-seawater injection into the core was simulated using digital core analysis (DCA) results and the pore scale modeling approach. The core flood experiment data are consistent with the scale formation prediction made by the OLI ScaleChem software, which indicates that smart water can be determined by optimizing the salinity and ion content of injected water. Also, results of permeability damage prediction by our modeling approach have good agreement with the core flood experiment data. Therefore, our modeling approach can replace the conventional core flood experiments as a low-cost method with high computational efficiency and high enough accuracy to evaluate formation damage in the water flooding process.

Reactive Transport Modelling of carbon mineralization – a machine learning-based approach

Carbon mineralisation is currently one of the most promising Carbon Capture and Storage (CSS) options for permanent gas sequestration since it ensures a rapid conversion of carbon from the gas phase to a carbonate mineral. Mafic and ultramafic rocks are the best geological options for mineral carbonation due to the relatively fast dissolution rates of the mineral components that can release carbonatable divalent cations such as Mg2+, Sr2+, Ba2+, Mn2+, Ca2+ and Fe2+. Once in solution, these cations react with dissolved carbonate ions to form, under convenient pH and temperature conditions, carbonate minerals like calcite, magnesite, siderite, rhodochrosite, or dolomite.
 The viability of carbon mineralization with injection of freshwater has been proven in the CarbFix project [1]. The main feature of the CarbFix method is that CO2 (and other minor gases) is not injected under its gaseous form but already dissolved in an aqueous fluid, which greatly enhances the mineralisation rates. The methodology, however, requires vast amounts of water that can be a limited resource in many regions. Seawater may be the most viable water source for underground carbonation in many areas, but its use raises questions on the efficiency of the carbonation process. The high ionic strength of seawater makes the geochemical interactions between CO2-rock and seawater more complex and, so far, more unpredictable. Reactive transport modelling (RTM) based on experimental thermodynamic and kinetic data of seawater-basalt interaction [2, 3] can shed some light on the expected mineralisation progress in sites with different mineralogy and variable temperature conditions. Figure 1 shows the results obtained with a reactive transport model that simulates the injection of CO2-charged seawater in basaltic rock.
 geochemical reaction calculations in particular might be considerably slow and are sometimes redundant as they might be based on a very similar set of input values. These challenges are usually faced by introducing a number of simplifications in the models to meet the objectives of the simulation studies. Thus, alternative ways to solving the full system are a priori a potential way to reduce the computational burden of numerical models.
 One of such alternatives is Machine Learning (ML) and, more specifically, Artificial Neural Networks (ANN), which are inspired on biological neural networks as the ones found in the human brain. They contain several computational “neurons” arranged in different layers. Each of these neurons can be activated based on the response of the other connected neurons. The training process consists of feeding data into the ANN and fitting the connection weights between the neurons to reproduce and learn the hidden relationships of the data. Recently, the authors have coupled ANNs of a geochemical system into a reactive transport simulator [5]. In this approach, Supervised Machine Learning with ANNs is used to accurately predict the geochemical evolution in a reactive transport framework without the need of actually performing the (expensive) chemical equilibrium calculations in the reactive transport model.
 The goal of this work is to apply and further develop the technology based on Supervised Machine Learning algorithms to drastically boost the efficiency of reactive transport models of carbon mineralization in the Carbfix system [6]. Firstly, a set of geochemical models of CCS are developed in batch systems (0D) as well as reactive transport models in 1D axisymmetric, 2D, and 3D RTM modelling with different degrees of complexity. Modelling focuses on the injection of CO2-charged seawater into basaltic rocks. In this system, CO2 is consumed via a two-step reaction: (1) Dissolution of Basaltic Glass and release of cations (Ca and Mg), and (2) precipitation of Ca-Mg carbonates and other secondary minerals. The RTM models consider a 1 km domain and a characteristic mineralization of 3-4 years. As a first step, these models are solved with the convential (non ML-based) reactive transport simulator iCP [7]. Then, ANNs are trained and validated with the latest developments in setting up neural networks and used to solve these RTM systems with a Comsol-ML library. The resulting ANNs present good accuracies with coefficients of determination (R2) above 0.95 for all outputs, and a batch calculation speedup of 30 as compared to traditional chemical equilibration with PhreeqC. Preliminary results of RTM using ML to predict the chemical step indicate a speedup of on order of magnitude and reasonable accuracy as compared to conventional RTM. Our results demonstrate that it is conceivable to replace a geochemical solver in a RTM environment with significantly faster surrogate-based models powered by a machine learning algorithm

Application of Integrated Evaluation on Seawater Injection to Improve Injectivity for Carbonate Reservoir in Offshore Oilfield

Seawater flooding is popular for carbonate reservoirs in offshore oilfields and seawater is sometimes the unique choice of injection water source due to the lack of surface water supply. Seawater is injected into reservoirs to maintain reservoir pressure after water treatment for technically and economically effective field development. Uneven injection and production in B oilfield caused unbalance of pressure distribution and poor injection performance. It is essential to improve the injectivity of single well to a satisfied level through a integrated workflow on the basis of performance analysis, brine compatibility study, core flooding experiment, strategy and solution optimization. In this paper, the injection status has been analyzed and the decisive impacting factors were given including formation properties, stimulation activity, the brines compatibility and pre-treatment of injection water, which play a very important role in injection performance sustainability as the seawater injection continues. Scale modelling was done with formation water, mud filtrate, injection water and stimulation fluid for self-scaling assessment. Mixing experiment of two of the brines of four introduced at either atmospheric or reservoir condition. Core flooding experiment was carried out with formation water and filtered injection water after critical velocity for core flooding is confirmed. Then the injectivity for each wells have been analyzed at different locations of the reservoir with different formation properties, solutions have been subsequently put forward and the improvement on injectivity of injectors before and after the stimulation or even re-stimulation and the effect of cleanup after the stimulation was also compared. It was concluded that injectivity could be enhanced through stimulation and the cleanup after stimulation and the sulfate should be removed or reduced in the process of the pre-treatment of injection water from the remote terminal to ensure desirable water injection and production performance.

On the benefits of desulfated seawater flooding in mature hydrocarbon fields

Removal of sulfate from the injection seawater (desulfation) in hydrocarbon reservoirs is a Modified Salinity Water (MSW) flooding method that mitigates microbial reservoir souring, improves oil recovery, and enables produced-water re-injection (PWRI). Aside from the Improved Oil Recovery (IOR) effect, desulfation results in a cleaner production of oil through enabling PWRI and reducing the environmental impacts associated with reservoir souring and nitrate treatment. However, whether desulfation is still beneficial for mature fields, after years of the injection of untreated seawater, is a valid common concern. In such cases, sulfate concentration inside the reservoir has already increased due to years of untreated seawater injection. The high sulfate concentration inside the subsurface reservoir before desulfated water flooding may render desulfation pointless. The present study investigates the potential benefits of desulfation after around 20 years of untreated seawater injection in a sector of an oil field in the Danish North Sea. The results show that depending on the cessation of production point in time and the efficiency of residual oil saturation reduction of MSW flooding, desulfation results in a significant increase in oil production. Even if improving oil recovery is no longer a priority, modification of injected seawater would still help reduce the amount of water required to support a given oil production rate. Moreover, desulfation is considerably more effective than nitrate treatment in mitigating microbial reservoir souring. Furthermore, the possibility of scale formation is decreased considerably due to desulfation, which further encourages PWRI.

Effect of the Type and Concentration of Salt on Production Efficiency in Smart Water Injection into Carbonate Oil Reservoir Rocks.

Smart waterflooding is one of the most practical emerging methods of enhanced oil recovery in carbonate reservoirs. In this study, the effect of salt type and its concentration in smart water on oil recovery from a carbonate reservoir rock is investigated. A series of experimental measurements, including zeta potential (ZP), interfacial tension (IFT), and contact angle (CA), were conducted to examine the effect of ions on the oil/brine/rock interaction. IFT, ZP, and CA were also used as screening methods to select effective solutions for flooding experiments. The results of the study show that synthesized brines containing sodium acetate and potassium acetate salts have a significant effect on the reduction of IFT; however, rock surface wettability due to such brines is insignificant. The presence of organic salts in the injected water can alter the properties of the fluid and rock surface, leading to improved oil recovery. The salts can reduce the interfacial tension between the oil and water phases, making it easier for the water to displace and mobilize trapped oil. This effect is particularly beneficial in reservoirs with high oil-water interfacial tension as it enhances the capillary forces and improves the sweep efficiency. Smart water with sodium acetate (MSW.NaOAc) caused a 7% increase in oil production in the tertiary injection process due to IFT and CA reduction. The secondary injection of MSW.NaOAc led to an oil production efficiency of 76%, which is 10% higher than that of the secondary injection of seawater (SW), confirming the effectiveness of acetate ions in enhancing oil recovery. Doubling the concentration of sulfate ions in modified SW (MSW.NaOAc.2S) caused a 19% increase in oil production in tertiary injections after SW flooding. The secondary injection of MSW.NaOAc.2S produced a 13% increase in the recovery factor compared to SW flooding in the secondary mode. The main driving mechanism for oil mobilization was found to be wettability alteration, which is supported by the analyses of CA and ZP. This study confirms that the salt type and concentration present in a brine solution play a vital role in the movement of trapped oil in carbonate reservoirs.

An experimental assessment of seawater alternating near-miscible CO2 for EOR in pre-salt carbonate reservoirs

Enhanced oil recovery (EOR) methods considering the injection of seawater and CO2 have been widely investigated and applied in the Brazilian pre-salt fields. The high availability of these fluids in offshore facilities makes seawater alternating CO2 (CO2WAG) a viable and environmentally friendly EOR method. It combines the advantages of seawater injection and CO2 injection to improve fluid mobility control and viscous fingering attenuation. In this study, in addition to the core flooding test of secondary seawater flooding and the tertiary CO2WAG, different experimental determinations provided a better understanding of the mechanisms related to the EOR methods applied to a carbonate core composed mainly of dolomite, and their interactions with pre-salt oil, brines and CO2. A 13.30% incremental oil recovery was achieved by alternating seawater with CO2. Considering formation brine, non-carbonated seawater, or seawater saturated with CO2, contact angle measurements revealed that the wettability alteration is not significant when dolomite is slightly water-wet, even in the presence of CO2. On the other hand, measures of brine/oil, brine/CO2/oil and CO2/oil interfacial tension emphasize the beneficial effects of this gas for EOR, in near-miscible conditions. This is achieved by the reduction of capillary and interfacial forces that act by trapping the oil in the pores of the medium. The brine salinity, the presence of magnesium in dolomite and the oil's low TAN/TBN ratio proved to be essential factors in determining the slightly water-wet wettability of the dolomitic rock and the interfacial tension between the phases. Furthermore, for the experiments carried out in the presence of brine with solubilized CO2, a considerable variation in the oil drop volume was observed due to the mass transfer of CO2 between the phases. Finally, experimental results showed that the additional oil recovery was mainly associated with oil swelling, viscosity reduction, and mobility increase, which occur even in near-miscible conditions during CO2WAG.

Comprehensive analysis of the effect of reservoir key parameters on the efficacy of DTPA chelating agent in minimizing interfacial tension and enhanced oil recovery

Chelating agents reduce the salinity of seawater (SW) and mimic low salinity water (LSW) by binding metal ions in the solution and on the rock surface. This process decreases SW dilution costs and prevents scale formation while improving oil recovery without damaging the reservoir. This study investigates the impact of Diethylenetriaminepentaacetic acid (DTPA) chelating agent on the reduction of interfacial tension (IFT) between oil and SW, without the use of additional chemicals. For the first time, we comprehensively analyzed how reservoir key parameters (concentration, salinity, temperature, and pH) affect the performance of DTPA in reducing IFT. Additionally, rock wettability alteration and sand pack flooding experiments were conducted to evaluate the effect of DTPA on rock wettability and oil recovery. The results revealed that increasing the temperature to 75 °C and the concentration of DTPA to 5 wt% resulted in an IFT reduction to less than 1 mN/m, making the oil miscible in the DTPA solution. Salinity studies demonstrated that by increasing the solution salinity up to the optimal level, the IFT of oil/brine decreased. Furthermore, using 5 wt% DTPA solution altered the rock/oil contact angle from 143° (oil-wet) to 23° (strongly water-wet), highlighting the effect of DTPA on rock wettability alteration. Based on these findings, 5 wt% DTPA was selected as the optimal concentration, resulting in an increase in oil recovery up to 20.3% of original oil in place (OOIP) after SW injection. Elemental analysis of DTPA flooding effluent also confirmed the chelation of metal ions from rock and solution.

Evaluation of rock-fluid interaction in a carbonate reservoir: Backflow test and reactive transport simulations

Water injection is one of the most used secondary oil recovery methods. However, when injected into a carbonate reservoir, it disturbs the equilibrium between the porous rock and the formation water, altering the geochemical system. The aim of this work is to evaluate the rock-fluid chemical interaction associated with seawater injection into a carbonate reservoir, based on field flow tests and flow simulations using COORES™ and ARXIM. Though previous studies were carried out under laboratory conditions, in this work, for the first time, rock-fluid interaction was observed and quantified during a field test in a high-temperature and high-pressure reservoir. Chemical analysis of produced water during the flow test showed that calcium and alkalis concentrations were higher than those calculated by the simple mixture of injected and formation waters, confirming the existence of chemical reactions under reservoir conditions. Reactive transport simulations were used to determine kinetic parameters related to calcite dissolution and dolomite precipitation in the reservoir. The results of this study enhance the understating of chemical interactions between injected fluids and carbonate reservoirs and provide data for more reliable simulations. These could lead to more accurate predictions regarding produced water composition and pH, anticipating the likelihood of reservoir collapse and scaling issues.

Co-electrolysis of seawater and carbon dioxide inside a microfluidic reactor to synthesize speciality organics

We report co-electrolysis of seawater and carbon dioxide (CO2) gas in a solar cell-integrated membraneless microfluidic reactor for continuous synthesis of organic products. The microfluidic reactor was fabricated using polydimethylsiloxane substrate comprising of a central microchannel with a pair of inlets for injection of CO2 gas and seawater and an outlet for removal of organic products. A pair of copper electrodes were inserted into microchannel to ensure its direct interaction with incoming CO2 gas and seawater as they pass into the microchannel. The coupling of solar cell panels with electrodes generated a high-intensity electrical field across the electrodes at low voltage, which facilitated the co-electrolysis of CO2 and seawater. The paired electrolysis of CO2 gas and seawater produced a range of industrially important organics under influence of solar cell-mediated external electric field. The, as synthesized, organic compounds were collected downstream and identified using characterization techniques. Furthermore, the probable underlying electrochemical reaction mechanisms near the electrodes were proposed for synthesis of organic products. The inclusion of greenhouse CO2 gas as reactant, seawater as electrolyte, and solar energy as an inexpensive electric source for co-electrolysis initiation makes the microreactor a low-cost and sustainable alternative for CO2 sequestration and synthesis of organic compounds.

Integrating condition-based monitoring with process sensors information for operation and maintenance in a functional modeling framework

Safe operations and adequate maintenance are two main means to achieve reliable production and reduce downtime of a plant. While the tasks of operations and maintenance are carried out by two different groups of staff, as a result, the close relationship between the two tasks is split. In this paper, this challenge is handled by a proposed integrated functional modeling framework. In this framework, the Multilevel Flow Modeling (MFM) method with its cause-consequence reasoning rules is used. Condition-based monitoring is a well-accepted strategy for predictive maintenance and fault detection based on measurements is a well-developed technology for operation support. Information fusion including monitoring conditions of assets and process sensors information for both operation and maintenance in the same modeling framework is desired. The qualitative relationship distribution between operations and maintenance can be established based on the function states of the system. In addition, these relationships are visible for both groups of staff. As a result, the detected information in the early stage of the development of the unpleasant scenarios is used to improve their situation awareness, so that the undesired emergency shutdown from both perspectives of operation and maintenance is prevented. Consequently, it can reduce production loss. A case study of operations and maintenance of a seawater injection system is carried out and shows the industrial applicability of the proposed framework. The case study strongly reveals that there is a highly close relation between operation and maintenance for ensuring the system working properly. It demonstrates that the proposed integrated framework is not only able to support operational tasks but also for the maintenance tasks by including relevant maintenance information of the system. The results show that it can potentially help with decreasing downtime of the system.

Enhancement of Oil Recovery in West Qurna-1 Carbonate Reservoir by Injecting Seawater

Seawater injection is a novel emerging technology for enhancing oil recovery in Middle East carbonate reservoirs. This paper investigated the mechanism of seawater injection in Mishrif formation for the West Qurna-1 oil field. The decline in the pressure of West Qurna-1 needs pressure support by water injection, where it is a supergiant oil field. This study is significant because seawater injection technology is considered a future technology in the south of Iraq for several reasons. One of these reasons is the scarcity of fresh water in the Middle East, especially in Iraq, and the second reason is the availability of seawater, which is close to Basra city. This paper aims to study the essential parameters that influence the oil recovery via sweater injection as well as the inherent mechanisms that help increase the oil recovery. Collected five core plugs from producing units of Mishrif formation, MB1, and MB2, having different petrophysics properties where the permeabilities ranged from 6 to 143 md. Two types of water are used formation water and seawater. We conduct core flood experiments on chosen carbonate core samples and formation water from Iraq's West Quran-1 carbonates. The common belief facts that low salinity flooding of oil recovery gives more producing oil for the same volume of water injected due to wettability alteration. The analysis of injected and producing water indicates that higher concentrations of SO4-2 and Ca-2 ions change the wettability of the rock to more water-wet. Consequently, the oil recovery increases by 10-15 % when using seawater, which is richer in these ions.