Abstract Scale inhibitor squeeze treatments are one of the most common ways to prevent scale deposition. The mineral scale will be inhibited if the concentration of the scale inhibitor (SI) in the produced water is above a certain threshold, known as the Minimum Inhibitor Concentration (MIC), which is controlled by scale inhibitor retention. Therefore, accurate modelling of the SI retention through adsorption (G) and precipitation (P) is critical to the successful design and implementation of squeeze treatments. In this study, an equilibrium model has been developed to simulate the coupled adsorption-precipitation (G/P) of phosphonate scale inhibitors in reactive formations, such as carbonates, in the presence of calcium and magnesium cations. In this approach, the scale inhibitor (SI) was considered as a poly weak acid that may be protonated (HnA), resulting in the complexation with Ca/Mg ions, leading to the precipitation of SI_Ca/Mg complexes. All these reactions occur in an integrated system where carbonate system reactions and adsorption of the soluble species are occurring in parallel. In the adsorption process, all the SI derivatives remaining in the solution, including free and complex species, are considered to participate in the adsorption process, described by an adsorption isotherm model (e.g., Freundlich). For the precipitation part, the model considers the following reactions: (i) the carbonate system, (ii) SI speciation, considered as a weak polyacid, HnA, (iii) the SI-metal (Ca and Mg) binding complexes, and (iv) subsequent precipitation of the SI-Ca/Mg complex. The system charge balance and the mass balances for calcium, magnesium, carbon, and SI are considered to numerically equilibrate the system (excluding the adsorbed species) by solving a determined set of non-linear equations numerically. Following the algebraic reduction of the equations, the system is reduced to three non-linear equations that may be solved by the Newton-Raphson method. The precipitation of the SI-Ca/Mg is modelled in the equilibrium model based on the solubility of SI in the solution, determined from the lab experiments. The reliability of the proposed model was established by comparison with experimental results from a previous study (Kalantari Meybodi et al., 2023) on the interactions of DETPMP in a Calcite/brine (containing free Ca/Mg) system, where the final concentration of SI, Ca2+, Mg2+, CO2, and pH were compared. The modelling showed good general agreement with the experimental results, and a further sensitivity analysis was performed to examine the behaviour of some uncertain parameters, such as the stability constant of complexes.

This paper describes a study of the interactions of diethylenetriamine penta(methylene phosphonic acid) (DETPMP), one of the most widely used phosphonate scale inhibitors (SIs), with carbonate substrates. Much previous work has appeared on this topic, but here, we present results addressing key gaps identified in earlier studies. The experimental program focused on four main areas: (i) static adsorption/compatibility analysis of DETPMP at both 95 and 21 degrees C. Static tests revealed that SI retention mechanisms are significantly more active at elevated temperatures compared to 21 degrees C, where only minimal adsorption was observed. At 21 degrees C with initial pH0 = 4, calcite dissolution occurs, and Ca2+ may interact with DETPMP, but precipitate formation is minimal. The SI's concentration primarily governs pH behavior under these conditions. The experimental results presented here provide data to validate computational modeling work reported in a separate study (Kalantari Meybodi et al., Colloids Surf. A Physicochem. Eng. Asp. 2024, 133535). (ii) Precipitation and re-dissolution tests of DETPMP_Ca complexes, which were conducted across a temperature range of 21-95 degrees C, with a subsequent larger-scale test at 95 degrees C. For systems with high [Ca2+], the smaller-scale experiments yielded similar masses of precipitate (post-filtration and oven-drying) across all temperatures. The stoichiometries of the DETPMP_Ca complexes formed were determined using two methods: direct analysis of redissolved precipitates in distilled water/HCl and indirect measurement of Delta[Ca] and Delta[DETPMP] from supernatant solutions, both using Inductively Coupled Plasma-Optical Emission Spectroscopy (ICP-OES). The stoichiometric analysis revealed that the excess [Ca2+] and initial pH of 8.5, rather than temperature, governed the reaction, almost achieving maximum complexation (5 ligands) between Ca2+ and DETPMP in solution. The precipitates were characterized using ESEM-EDX and thermogravimetric analysis (TGA). ESEM-EDX surface imaging and compositional analysis demonstrated that the complexes had amorphous structures under all temperature conditions, while TGA results showed that the complexes had decreasing water content with increasing preparation temperature. (iii) The purified SIs obtained at 95 degrees C were used to examine how removing phosphorus-containing impurities affects inhibition and adsorption performance. A series of inhibition efficiency (IE) and static adsorption experiments compared purified and commercial DETPMP. Their effectiveness in preventing BaSO4 precipitation was assessed by measuring Delta[Ba2+] before and after the addition of DETPMP to the brines using ICP analysis. Results demonstrated that purified materials exhibited very similar barium sulfate inhibition efficiency to commercial products, indicating that the impurities did not significantly influence the inhibition process. Comparative adsorption studies revealed higher apparent adsorption values for purified DETPMP, attributed to the impurities in the commercial products being measured as active DETPMP concentrations despite not participating in the adsorption process. It is shown how this can easily be corrected and accounted for in our results. (iv) The supernatant solution from the DETPMP_Ca complexation process was analyzed following initial precipitation. The effectiveness of this supernatant solution was then evaluated for BaSO4 scale inhibition. The results indicated that these residuals showed almost no efficiency in inhibiting BaSO4 formation. Subsequently, precipitation experiments were conducted to further investigate the complexation and precipitation behavior of the supernatant materials, revealing that only small amounts of DETPMP_Ca complexes were actually present; i.e., the relatively high apparent "DETPMP" concentration was mainly (P-containing) impurity and not DETPMP.

The widespread use of hydrogen as an energy source relies on efficient large-scale storage techniques. Underground Hydrogen Storage (UHS) is a promising solution to balance the gap between renewable energy production and constant energy demand. UHS employs geological structures like salt caverns, depleted reservoirs, or aquifers for hydrogen storage, enabling long-term and scalable storage capacity. Therefore, robust and reliable predictive tools are essential to assess the risks associated with geological hydrogen storage. This paper presents a novel reactive transport model called "Underground Gas Flow simulAtions with Coupled bio-geochemical reacTions" or "UGFACT", designed for various gas injection processes, accounting for geochemical and microbial reactions. The flow module and geochemical reactions in the UGFACT model were verified against two commercial reservoir simulators, E300 and CMG-GEM, showing excellent agreement in fluid flow variables and geochemical behaviour. A major step forward of this model is to integrate flow dynamics, geochemical reactions and microbial activity. UGFACT was used to conduct a simple storage cycle in a 1D geometry across three different reservoirs, each with different mineralogies and water compositions: Bentheimer sandstone, Berea sandstone, and Grey Berea sandstone, under three microbial conditions ("No Reaction", "Moderate Rate", "High Rate"). The findings suggest that Bentheimer sandstone and Berea sandstone sites may experience severe effects from ongoing microbial and geochemical reactions, whereas Grey Berea sandstone shows no significant H2 loss. Additionally, the model predicts that under the high-rate microbial conditions, the hydrogen consumption rate can reach to as much as 11 mmol of H2 per kilogram of water per day (mmol / kg & sdot;day) driven by methanogenesis and acetogenesis.

Due to the mixing of sulphate ions in the seawater with barium, strontium, and calcium ions in the formation water, the spread use of seawater as a pressure support fluid during secondary oil recovery within sandstone and carbonate reservoirs may lead to the precipitation of inorganic scales. Oil production may be significantly and adversely impacted by the formation of these salts within the reservoir and, more concerningly, in the vicinity of the wellbore and in the production string itself. It has been studied that in situ geochemical reactions occur during the waterflooding process due to water-rock and water-water interactions (CARDOSO et al, 2023). Calcium sulphate scale may form in high temperature chalk reservoirs that undergo seawater injection as a consequence of mineral reactions involving calcite dissolution and magnesium rich carbonate precipitation. One important factor in the precipitation of calcium sulphate (gypsum or anhydrite) is temperature (with has low solubility at high temperature, especially for anhydrite). One of the scaling risk control strategies is to alter the injection water composition to lower the SO42- concentration, such as by injecting low sulphate seawater from a sulphate reduction plant (SRP). Increasing the tolerance of the SRP requirement can not only save operation expense but also free up limited deck space on FPSOs (Wright et al., 2008) PRIO is developing a pre-salt field in the north of the Campos Basin. It has been demonstrated that reactions in the reservoir may strip SO2- from the injection brine stream, helping to mitigate the scaling risk. A mineral deposition reaction deep within the reservoir is the mechanism responsible for removing sulphate from the brine, thus reducing the scaling risk for anhydrite and celestite where the injected brine mixes with formation water within and adjacent to the producers. Because the mineral deposition takes place deep within the reservoir where the fluid throughput to rock volume ratio is relatively small (typically order <10 pore volumes), there is no observable impact on flow (Macka et al., 2014). The fact that the field is at temperatures higher than 110°C is critical in this regard, since CaSO4 is relatively soluble at downhole water injection temperatures (<50°C), but above 90°C the solubility decreases significantly. The amount of Ca2+ that drives the CaSO4 reaction in such system can be significantly influenced by the presence of bicarbonate (HCO3-) in the brines and the reactions with the carbonate rock. The system's flow configuration is another crucial element. The effects of distance between injector-producer pairs, injecting seawater into high permeability areas, including fractures, differ from those of injecting water into the oil leg. In the study, the injectors are positioned to inject seawater directly into the aquifer, only for pressure support. This configuration could impact the sulphate scaling risk at the production wells and how it evolves as the field ages. In order to assess the effects of injection water composition, temperature, rate, and injector locations relative to the producers on calcium and strontium sulfate scaling risks in the Field, a reactive transport model has been established using CMG GEM (Yisheng et al., 2016).

In the design and optimisation of an underground hydrogen (H2) storage facility in an aquifer or other reservoir system, the H2/water relative permeabilities (RP) are the most critical two-phase data for input to numerical simulation. In this paper, we present a critical analysis of the published experimental H2/water RP functions in the literature. We present fine-grid simulations of H2 displacing water (denoted H2 à water) using three of the most widely cited RP datasets (Yekta et al., 2018; Boon and Hajibeygi, 2022; Lysyy et al., 2022) in a mildly heterogeneous permeability field, at a field length scale of ~100m. Since the viscosity ratio between water and H2 is (mw/ mH2) ≈ 70, then at some length scale above a few metres, it is inevitable that the system must show immiscible viscous fingering of the H2 into the water phase. Indeed, the emergence of viscous fingering at some length scale is a “sense check” that the input data used in the simulations are correct, especially the H2/water relative permeability functions. In fact, none of the three published H2/water RP curves leads to viscous fingering. Instead, they all show stabilised flood fronts. The reasons for this are due to shortcomings of the (conventional) gas/liquid experimental methods used to obtain the RP functions. These methods yield RP functions at the wrong force balance between the capillary, gravity and viscous forces. For fingering to emerge, it is necessary to derive the viscous dominated RP functions. An alternative, more physically appropriate set of viscous dominated “fingering RP functions” is proposed and applied. When applied at the core scale, these new RP functions show fully dispersed flow due to capillary dispersion, as they do when applied in a vertical (downwards) gravity stable displacement. However, the viscous fingering emerges naturally in horizontal flow as the length scale of the system increases and viscous (and gravity segregation) forces become dominant.

Silicate scaling is recognized as a potential operational problem for geothermal power plants. In this work, a static bottle test methodology was developed to assist in identifying efficient silicate inhibitors/dispersants with 80-90% performance, applicable for low enthalpy geothermal heat recovery systems. To investigate products to control amorphous silicate and magnesium silicate scale, the inhibition efficiency (IE) and potential mechanism of a sulphonated polymer-based scale inhibitor/dispersant, denoted A5, were studied. The most common metal ion to combine with silicate in power plants is magnesium. In this work, magnesium at an initial concentration of 120ppm, was allowed to react with silicate ions (1880ppm) for 3 days, during silicate scaling static bottle tests (at 60ºC and 95ºC; pH 8.5). The scale inhibitor A5 IE performance was evaluated over a concentration range of 20-500ppm. To investigate the inhibition mechanism of A5, the concentration of sulphur, contained within its structure, was monitored alongside the scaling ion consumption of magnesium and silicate by Inductively Coupled Plasma – Optical Emissions Spectrometer (ICP-OES) throughout the test duration. The 60ºC results are similar whether the scale inhibitor A5 is deployed in magnesium brine or silicate brine. For 20ppm A5, there is less than 60% silicate and magnesium IE at 2hrs and no performance after 22hrs and 3 days. A5 shows 60-85% silicate and magnesium IE performance at 50ppm and above. The most consistent results are measured for A5 in magnesium brine before brine mixing and hence this method is used for subsequent testing. Due to low A5 consumption (< 20%) at 50-500ppm, despite displaying a moderate 60-85% IE performance, it is believed A5 is performing as a dispersant rather than a scale inhibitor. At higher temperature, 95°C, ≥100ppm A5 is required to control silicate scale effectively (cf. 50ppm A5 at 60oC). It appears A5 is less effective at preventing magnesium silicate scale (60-70% IE) as opposed to amorphous silicate scale (80-90% IE). The highest A5 consumption is found at 50-60% for 20ppm and 50ppm, whilst at 100ppm and 200ppm, less than 10% is consumed. These 95ºC results also confirm that A5 is acting as a dispersant, since it is not being consumed during its effective IE performance. A successful investigation of the initial formulation of scale inhibitor in magnesium brine prior to mixing was performed for the first time, due to observed inconsistencies during SI/silicate brine test regimes. This has provided greater confidence in the A5 inhibition performance results. The novel approach of monitoring the scale inhibitor, based on its sulphur content, by ICP-OES, means further insights relating to the inhibition mechanisms can be determined, thus advancing our knowledge of the mechanism of how silicate inhibitors/dispersants work.

Reservoir injectivity and storage efficiency may be put at risk during CO2 injection in a complex and compartmentalized saline formation with variable reservoir quality due to the salting-out effect. Consequently, a risk assessment of injectivity loss due to halite precipitation in the near-wellbore formation is required. This study investigates the influence of heterogeneity on reservoir dynamics under specific field conditions and the impact of salt deposition in a multi-layered fluvio-deltaic system. Numerical simulations were performed using a reactive transport compositional model. 2D radial models were developed to identify near-well injection effects (evaporation, deposition, imbibition and crossflow between the layers) and then calculate the extent of the dry-out zone, porosity changes and injectivity changes. The injection of dry CO2 at a constant rate of 0.77 Mt/yr for 360 days into a candidate aquifer with a salinity of 160 g/L was modelled. The well was completed in a target formation 80 m thick with three sandstone units separated by interbedded shales. The bottom layer has the highest reservoir quality, and the middle layer has the lowest. The results show that because there is no hydraulic communication between the layers due to the barriers to vertical flow, most of the CO2 flows preferentially into the highest permeability layer, despite it being the deepest. After 90 days of injection, dry-out radii of 1.2m, 1.1m, and 3m were observed for the top, middle and bottom layers, respectively, resulting in significant loss of effective porosity in the rock adjacent to the well, especially in the deepest layer. The wellbore pressure increases by 10,000kPa (100 bars) and reaches the fracture pressure within 70 days of injection due to complete blockage of the sandstone units. The profile of injectivity vs time shows that injectivity increases within the first few days of injection due to an increase in gas saturation around the well; however, subsequent halite precipitation more than reverses this advantage. Capillary-driven counterflow imbibition in the horizontal direction means that there is continuous re-saturation of the dry-out zone with brine that evaporates, adding to the amount of salt deposited, thus reducing the injectivity by an order of magnitude. Additional calculations show that there would have been crossflow of brine into the middle layer if the interbedded shale layers had been absent. This paper presents a methodology to evaluate the impact of geochemical processes, such as halite deposition, which is useful for assessing the risk of formation damage during CO2 injection projects. It may also provide information for improved reservoir pressure management and well-intervention operations, such as freshwater preflushes or water-wash scheduling to alleviate permeability loss and increase injectivity.

This paper describes a study of the interactions of phosphonate scale inhibitor with carbonate substrate. Much previous work has appeared on this topic, but here we present results which attempt to address some gaps identified in previous studies of this subject. The experimental programme focused on three main areas: (i) static adsorption/ compatibility analysis of phosphonate scale inhibitor at both 95°C and room temperature (RT). Static tests revealed that SI retention mechanisms are significantly more active at elevated temperatures compared to RT conditions, where only minimal adsorption was observed. At RT conditions with initial pHo = 4, while calcite dissolution occurs and Ca2+ may interact with SI, the formation of precipitate is minimal. Under these conditions, SI concentration primarily governs pH behaviour. These experimental results provided validation data for computational modelling work, which is presented in a separate study [1]. And: (ii) precipitation and re-dissolution tests of SI-Ca2+ complexes which were conducted across a temperature range of 20-95°C, with a subsequent larger-scale test at 95°C. For systems with high [Ca2+], the smaller-scale experiments yielded similar masses of precipitate (post-filtration and oven-drying) across all temperatures. Complex stoichiometry was determined using two methods: direct analysis of re-dissolved precipitates in distilled water/HCl, and indirect measurement of Δ[Ca] and Δ[SI] from supernatant solutions, both using Inductively Coupled Plasma - Optical Emission Spectroscopy (ICP-OES). The stoichiometric analyses revealed that excess [Ca2+] and initial pH of 8.5, rather than temperature, governed the reaction, resulting in near maximum possible complexation between Ca2+ and DETPMP in solution. The precipitates were characterized using ESEM-EDX and thermogravimetric analysis (TGA). ESEM-EDX surface imaging and compositional analysis demonstrated amorphous structures across all temperature conditions, while TGA results showed decreasing water content with increasing preparation temperature. Finally, (iii) Purified SIs obtained at 95°C were used to examine how the removal of phosphorus-containing impurities affects inhibition and adsorption performance. A series of inhibition efficiency (IE) and static adsorption experiments were conducted. The precipitated and redissolved DETPMP samples were evaluated against unmodified commercial DETPMP. Their effectiveness in preventing BaSO4 precipitation through Ba2+ interaction was assessed by measuring Δ[Ba2+] before and after SI addition to the brines using ICP analysis. Results demonstrated that purified materials exhibited similar barium sulphate inhibition efficiency to commercial products, indicating that impurities did not significantly influence the inhibition process. Comparative adsorption studies revealed higher apparent adsorption values for purified DETPMP, attributed to impurities in commercial products being measured as active DETPMP concentrations despite not participating in adsorption. It is shown how this can be easily corrected and accounted for in our results.

Recent trends toward carbon net zero and the push to develop renewable energy as an alternative to fossil fuels have resulted in major environmental focus on decarbonization projects with emphasis on carbon capture, utilization, and storage (CCUS). A range of scale-related issues can impact the efficiency of CCUS. These include halite and iron sulfide scale deposition during supercritical, dry carbon dioxide (CO2) injection, and dissolution of carbonate cements and minerals in reservoir rocks, which impact both cement and reservoir rock integrity, resulting in potential CO(2 )and methane (CH4) leaks. In addition, during CO2 utilization for enhanced oil recovery (EOR) and water injection/disposal, calcium and iron carbonate/hydroxide deposition can occur in downhole production tubing and throughout topside production facilities. Effective scale management strategies will be essential to maintain a safe, sustainable, and efficient CCUS process and to minimize CO2 footprint for any adopted scale control process. In this paper, we explore some aspects of scale risk and scale management for calcium carbonate deposition during carbon capture and CO2 injection/storage in different lithology scenarios. We also include halite, microbial-induced calcium carbonate, and iron sulfide deposition, along with highlights of both conventional and unconventional scale management approaches. The impact of well completion, cement type, and CO2 injection rates on CCUS and the selected scale management process are discussed in addition to laboratory data which were generated for proof of concept for controlled barium sulfate (BaSO4) mineral scale deposition to reduce the potential for CO2 and CH4 leaks and protect the wellbore and cement integrity. Also explored are the scale risk and management strategies for CO2 utilization through disposal in a calcareous sandstone and CO2 water alternating gas (WAG) injection in a carbonate reservoir, which demonstrate the possibility to apply reservoir management strategies to reduce or minimize the scale risk in these scenarios.

Permeability reduction due to salt precipitation near CO2 injection wells will reduce injectivity and may place the viability of large-scale CCS projects at risk of failure. Therefore, an understanding of the optimum injection conditions to mitigate the risk of deposition of halite and other salts is key. This study investigates the influence of continuous and intermittent CO2 injection on reservoir dynamics under two specific field conditions (one an offshore North Sea CCS project and the other an onshore North American project) by performing parametric sensitivity analyses.

Summary The drive towards net zero by 2050 has led to the development of alternative energy sources, with a focus on geothermal energy projects. Geothermal brines often contain dissolved minerals and gases that cause scale deposition in wells and plant equipment, leading to decreased efficiency in thermal energy production and reduced flow capacity in injection wells. Geothermal plant conditions and brine chemistry of each geothermal plant vary greatly, making the selection of a suitable scale management process crucial for sustainable energy production. Prevention through chemical inhibition or removal is preferred over costly mechanical methods, though nonchemical alternatives are attractive for reducing the CO2 footprint. Chemical treatment options include continuous topside injection, scale squeeze, or batch treatment in injection/production wells. High temperatures and water throughput in geothermal wells challenge chemical scale control and removal. Selected inhibitors/dissolvers must be thermally stable up to 250°C, preferably biodegradable, and effective against calcium carbonate and silica/silicate scales. Geothermal brines contain dissolved CO2 and H2S, making fluids corrosive. Therefore, the interaction between scale and corrosion inhibitors must be considered in any management strategy, possibly requiring modified laboratory test methods, especially for plants with water reinjection. This paper will review geothermal scale and its mechanisms of formation and management options, including chemical and nonchemical treatments. It also discusses the impact of well completion, high water production, corrosion, CO2 footprint, and the challenges of chemical treatments regarding thermal stability and laboratory testing.

This paper presents an investigation of the impact of in situ chemical and geochemical interactions on oil recovery efficiency and inorganic scale management. A common technique to support the reservoir pressure is water injection, but scale problems can be a major issue that develop during oil field production when there is water (especially seawater) injection. In such flooding scenarios, geochemical reactions occur between formation and injected water in terms of sulphate scales, such as barite. On the other hand, the carbonate scales may form due to a variety of reasons: changes in temperature, pressure, pH and CO2 concentration in the aqueous or hydrocarbon phases. This paper investigates the impact of CO2 availability, and changes in pH, ionic concentrations and temperature on carbonate and sulphate scaling risk in waterflooded reservoirs where choices may be exerted over injection water composition. In this work, the injected water does not contain CO2, but CO2 is present in the oil phase, and may partition from there, or diffuse from the formation water. Also presented is the relationship between brine composition and scale precipitation and management in the production wells. There are various factors affecting the system, such as water injection well and production well flow rates and flow through the reservoir, and also compositional effects due to use of Full Sulphate Seawater (FSSW) or Low Sulphate Seawater (LSSW), and due to variations in temperature and the concentration of CO2 in the oil phase. In this study, as preparation for addition of geochemistry to a full field 3D history matched model, we include geochemical reactions in a 1D model that has the field pressure, temperature and fluid properties, to test the impact of the various potential reactions in a simple system. This is necessary to fully understand the system before, in future work, moving on to the full field modelling, and in fact provides very valuable learnings that would be more difficult to distil if full field modelling alone had been performed. We assume the mineral reactions (anhydrite, gypsum, barite, huntite and calcite) are in equilibrium, excepting for the magnesium rich carbonate mineral reaction, which is assumed to be kinetic. The results shows that SO4 2-, Mg2+, HCO3 - and Ca2+ are the major ions that have a very significant effect on the system, and therefore impact on precipitation (4.7E-06gmole) and dissolution (-4E-06gmole) of calcite, barite and the magnesium rich carbonate mineral. Dissolution of anhydrite (-5.1E-05gmole) present in the initial mineral assemblage is shown to have a significant impact in most scenarios, except where FSSW has been heated up to reservoir temperature, where anhydrite precipitation (5E-05gmole) in situ occurs. This has a significant impact on the levels of desulphation that should be used to prevent sulphate scales in the production wells.

This study addresses the limited understanding of how shear-thinning polymer rheology influences enhanced oil recovery (EOR) at the pore scale. Using a pore network model and the Carreau rheological model, the impact of shear thinning under varying wettability, dilution, flow rates, and mobility ratios is examined. Results show that shear thinning strongly affects displacement patterns, with significant viscous fingering and reduced recovery efficiency at high shear rates, as viscosity declines within pore spaces. In contrast, minimal shear-thinning effects lead to stable displacement fronts, resembling a shear-independent flood with improved recovery. Higher oil viscosities exacerbate the impact of shear thinning, with reduced oil recovery in the presence of more severe shear-thinning polymers. In oil-wet systems, capillary forces counteract shear-thinning effects, promoting uniform displacement. The results also show that higher injection rates do not guarantee better recovery when shear thinning is present, as excessive shear may reduce polymer viscosity. Optimal recovery occurs at lower flow rates, where the polymer maintains higher viscosity and displacement fronts remain stable. This work highlights the importance of incorporating realistic shear-thinning behavior in polymer flooding models to enhance the predictive accuracy of EOR simulations and improve understanding of how polymer rheology influences pore-scale mechanisms in oil recovery.

Reservoir injectivity and storage efficiency may decline during CO2 injection in a heterogeneous saline formation with variable reservoir quality due to the salting-out effect. Rock heterogeneity affects salt precipitation patterns and distributions and causes changes in flow characteristics. Consequently, a risk assessment of injectivity loss due to halite precipitation in the near-well formation is required. This study investigates the influence of heterogeneity and injection rate on the extent and location of halite precipitation. Numerical simulations were performed using a reactive transport compositional model which accounted for brine evaporation, halite precipitation, capillary pressure re-imbibition, and gravity segregation. 2D radial models were developed to identify near-well injection effects and calculate the extent of the dry-out zone, porosity and injectivity changes. The phase behaviour is modelled using a Peng-Robinson equation-of-state to evaluate the evaporation of the aqueous phase and water solubility in the gas phase. Henry’s Law accounted for CO2 solubility in the aqueous phase. The Kozeny-Carman porosity-permeability relationship was used as the permeability-reduction in the model. Dry CO2 was injected at a constant rate of 0.9 Mtpa for 2 years into an aquifer with a salinity of 330 g/L. The well was completed in a formation 100 m thick with five heterogeneous scenarios viz. alternating high-perm and low-perm, bimodal high-perm to low-perm, bimodal low-perm to high-perm, coarsening-up and fining-up sequences. The results show that at high injection rates, viscous forces displace brine from the well such that there is insignificant formation damage due to halite precipitation, regardless of the degree of heterogeneity. However, at low CO2 injection, the injection rate and heterogeneity have a role to play. While the injection rate governs the interplay between viscous and gravity forces, causing dry-out to occur in the near-well formation, heterogeneity governs the location of salt precipitation and where exactly the blockage occurs. At low injection, gravity and capillary forces dominate, resulting in brine influx into the bottom layers, which supply salty water, and when this evaporates, there is a total blockage of these layers. Furthermore, the injectivity index at high injection rate depends on the ability to efficiently sweep brine from the well; at low injection, it depends on the formation damage of the high-perm and low-perm layers. This paper presents a methodology for evaluating the risk of halite precipitation during CO2 injection in heterogeneous saline aquifers. The understanding from this work is important for CCS projects where the CO2 injection rate may be low for prolonged periods or intermittently stopped.

This paper uses reactive transport modelling to investigate how mineralogy and reservoir properties can affect geochemical reactions and the sulphate concentration of brine in carbonate reservoirs under seawater-alternating-gas injection. Geochemical parameters, such as ion concentrations and mineral dissolution or precipitation, are analysed at the propagating injection front. The study is carried out in a 3D reservoir model assuming two zones with distinct mineralogies. A compositional reservoir simulator coupled with a geochemical model is used with the WOLERY database. Pressure, temperature, formation water and injected water compositions are based on the Brazilian pre-salt scenarios. The upper reservoir zone consists of calcite, dolomite, anhydrite, barite, and gypsum, and the lower reservoir zone is only formed by calcite and dolomite. Two different initial oil compositions are tested, the first with 1% CO2 and the second with 18% CO2. For the scenarios proposed, the results show that carbonate reservoirs with 1% or 18% CO2 in the initial oil phase and formed by calcite and dolomite can remove sulphate from the injected seawater as the seawater front flows through the reservoir, which means that sulphate is removed from brine during CO2 WAG EOR and this process is not dependent on the CO2 concentration in the initial oil phase. Calcite dissolution releases Ca2+ ions into the brine, which precipitate with SO42− ions from the injected seawater. The brine reaches the region of the producer well with depleted sulphate concentrations. Hence, injecting desulphated seawater for this scenario is expendable, as it involves the high cost of treating all water using a Sulphate Removal Unit (SRU) before injection, and the reservoir will perform the same function naturally. For carbonate reservoirs with anhydrite in their mineralogy, depending on reservoir properties, the produced brine may be less depleted in sulphate concentration due to anhydrite dissolution. For the models proposed, sulphate is almost fully removed from the injected brine in the 18% CO2 reservoir, and only partially removed from the injected brine in the 1% CO2 reservoir. This work suggests that geochemical reactions in carbonate reservoirs can naturally alter the sulphate content of injected seawater, demonstrating that sulphate can be naturally removed from the injected brine, leading to a produced brine depleted in sulphate. It was also demonstrated that the CO2 content in the original oil composition and mineralogy may have a significant role in the reservoir reactivity. This is a novel finding not reported in previous research.

A combination of enhanced oil recovery (EOR) methods, specifically polymer flooding and low salinity (LS) brine injection, has been shown to improve oil recovery beyond what is achievable with either method used alone. However, the optimal sequence and timing of these methods remain unclear, affecting their efficiency. This study investigates the impact of injection sequences and timing of LS brine and polymer to optimize oil recovery by understanding the underlying mechanisms. Six injection scenarios were tested: (1) injecting high salinity (HS) water followed by LS brine (tertiary injection), (2) injecting HS water to intermediate saturation followed by LS brine, (3) injecting LS brine directly (secondary injection), and in each case, (4) polymer injected simultaneously with LS brine, (5) polymer injected after the LS brine, or (6) polymer injected before the LS brine. The results showed a positive synergy between LS brine and polymer in both secondary and tertiary injections. This synergy is highly sensitive to injection timing, sequence, and rock/fluid properties. The combined effect of LS brine and polymer shifts the flow regime by altering the balance between capillary and viscous forces, maximizing oil recovery when both mechanisms are active. Conversely, the effectiveness declines when one mechanism dominates. Therefore, the timing and order of polymer and LS brine injection significantly influence displacement efficiency and oil recovery, with different injection sequences producing varying outcomes, even with the same EOR techniques.

Assessing microbial risks is key to feasible hydrogen storage in geological formations. This work quantitatively analyses the impacts of bio-methanation on hydrogen storage performance. Fine-scale flow simulations, coupled with the bio-methanation reaction, are presented to analyse its impact on the storage performance. Based on the reported rates in literature, methanogenesis may slightly degrade the recovery performance of hydrogen but is considered minor compared with the issue of gas mixing. The impacts of methanogenesis on a time scale of months (330 days) becomes observable in the system configured here, when the methanation rate is above 1746 nano molality per hour. The assumed methanation rate is two times greater than the rate reported from the Olla filed. Validated scaling theory generalises findings for gravity-dominated scenarios. But viscous-dominated flows see complications from property variations due to pressure changes at high rates. This study provides definitions of "target properties" (e.g., acceptable methanogenesis rates) for screening hydrogen storage projects.

Single-well tracer technique have been well applied in many petroleum industry and environmental applications. However, these tests have not been well developed for CO2 geological storage purposes to evaluate residual CO2 saturation during the appraisal phase of site investigation, due to the challenges occurring from the complex phase behaviour. In this study, two single-well tracer tests are numerically modelled to quantify the residual gas saturation. Our study addresses the design of an alternative single well tracer test sequence, which involved a single pass of the tracer saturated water over the residually trapped zone, thereby reducing the amount of CO2 dissolution into the tracer solution. A one-dimensional numerical modelling of the tracer propagation and partitioning with homogenous properties was used for the calculations of the difference in tracer breakthrough times during water withdrawal from the tests. Model sensitivity variations were applied to analyse the impact of reservoir and treatment design parameters on the residual gas saturation. The residual gas saturations calculated reflect the input values, including the effect of hysteresis, to within 10% accuracy. It was found that changing the CO2 saturated water volume injected after CO2 made the CO2 front to travel to different distances from the well, and thus the tracer had different size of residually trapped zones to travel through when it is back produced and encounters different residual gas saturations, and therefore affected the residual gas saturation calculations. The modelling also shows that optimal injection of CO2-saturated water to prevent the dissolution of the residually trapped CO2 and establish the residually trapped zone was challenging to achieve, and therefore using the fluid withdrawal method was more robust to establish the residually trapped zone. This is because of the dependency of solubility on pressure. The numerical models may be used to design, optimise, and interpret the field tests.