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Subsurface hydrogen (H2) storage in geological formations is of growing interest for decarbonization. However, there is a knowledge gap in understanding the multiphase flow involved in this process, which can have a significant impact on the recovery performance of H2. Therefore, a full-compositional modeling study was conducted to analyze potential issues and to understand the fundamental hydrodynamic mechanisms of H2 storage. We performed a range of 2D vertical simulations at the decametre scale with a very fine cell size (0.1 m) to observe the detailed flow behaviour of H2 with carbon dioxide (CO2) as cushion gas in various flow regimes. Issues such as viscous instability, capillary bypassing, gas trapping and gravity segregation are analysed here. To generalize our calculations, we have validated and applied the scaling theory in the context of subsurface H2 storage. Since this study is focused on the hydrodynamic behaviour, three dimensionless groups, including aspect factor, capillary/viscous ratio and gravity/viscous ratio were identified to correlate recovery performance between various scales in a fixed heterogeneous system. It was found that H2 could infiltrate the cushion gas in the proximity of the injectors, meaning that CO2 is not displaced away from the injectors in a piston-like fashion. As a result, the purity of the back produced H2 is much degraded, particularly in a viscous-dominated scenario. On the other hand, the injected H2 mostly accumulates at the top forming a highly restricted mixing zone with CO2 in the gravity-dominated case. The recovery performance is therefore much improved in this case. Although the gas distribution can be significantly altered by capillary forces leading to bypassed zones, the recovery performance of H2 is hardly influenced. This is because the back-produced H2 recovery is not dependent on the sweep efficiency of the gas. H2 can be back produced following the same paths which were formed during injection.

SummaryInjection of low-sulfate seawater (LSSW) instead of untreated full-sulfate seawater (FSSW) is widely used to mitigate barium sulfate scaling risk at the production wells. LSSW injection may no longer be required when the barium concentrations in the produced water drop below a certain threshold. Such a trigger value could be estimated from the barium sulfate precipitation tendency. Relaxation of requirements for the sulfate reduction plant (SRP) can significantly reduce operational costs. This study investigates the impact of several parameters on the timing and degree of relaxation of the output sulfate concentration by the SRP. Finally, the optimal switching strategy is proposed for a field case.The strategy for switching from LSSW to FSSW (e.g., time and method; direct or gradual increase in the sulfate concentration) was initially investigated using generic 2D areal and vertical models. The sensitivity study included the impact of reservoir heterogeneity and the initial barium and sulfate ion concentrations. Findings were later applied on a full-field reservoir simulation model followed by a mineral scale prediction software to investigate the specific switching strategy for a field that has multiple wells and significantly more complex heterogeneity.The results show that barium concentrations in the formation brine affect the choice of switching time more than the output sulfate concentration produced by the SRP. The degree of heterogeneity around the producers also has a significant impact on the switching time. Another parameter is the contrast in the permeability between layers; higher contrast allows a longer period of coproduction of the scaling ions and thus delays the switching time. In the field case, switching to FSSW at early times allows higher consumption of barium ions because of its in-situ precipitation. Barium is no longer a limiting ion, and so a higher degree of deep reservoir precipitation reduces the requirement for prolonged LSSW injection. Another strategy is a gradual relaxation of LSSW output, which allows even earlier buildup of the injected sulfate concentration compared with the direct FSSW switch.The study investigates the reservoir parameters that affect sulfate relaxation of LSSW injection for a field. After the proposed workflow, the optimal relaxation strategy can be designed for other field cases.

The dissertation describes the efforts towards synthesizing new collision-induced dissociation-cleavable protein cross-linkers (CID-XLs). Chapter one describes the background of CID-XLs and the various fragmentation pathways molecules undergo during collision-induced dissociation. Chapter two details the design and synthesis of new lysine-reactive, cysteine- reactive, and carboxylic acid-reactive sulfoxide-containing cross-linkers. A mechanism for fragmentation during tandem mass spectroscopy is proposed, and the limits of the sulfoxide functional group prompted investigation into a different CID-XL functional group. Chapter three investigates the trioxane core as a novel cleavable functional group, and two trioxane-containing CID-XLs were synthesized. Chapter four focuses on appending affinity purification to both a sulfoxide-containing and trioxane-containing CID-XL.

The objective of this study is to design a series of squeeze treatments for 20 years of production of a Brazilian pre-salt carbonate reservoir analogue, minimizing the cost of scale inhibition strategy. CO2-WAG (Water-Alternating-Gas) injection is implemented in the reservoir to increase oil recovery, but it may also increase the risk of scale deposition. Dissolution of CaCO3 as a consequence of pH decrease during the CO2 injection may result in a higher risk of calcium carbonate precipitation in the production system. The deposits may occur at any location from production bottom-hole to surface facilities. Squeeze treatment is thought to be the most efficient technique to prevent CaCO3 deposition in this reservoir. Therefore, the optimum WAG design for a quarter 5-spot model, with the maximum Net Present Value (NPV) and CO2 storage volume identified from a reservoir optimization process, was considered as the basis for optimizing the squeeze treatment strategy, and the results were compared with those for a base-case waterflooding scenario. Gradient Descent algorithm was used to identify the optimum squeeze lifetime duration for the total lifecycle. The main objective of squeeze strategy optimization is to identify the frequency and lifetime of treatments, resulting in the lowest possible expenditure to achieve water protection over the well's lifecycle. The simulation results for the WAG case showed that the scale window elongates over the last 10 years of production after water breakthrough in the production well. Different squeeze target lifetimes, ranging from 0.5 to 6 million bbl of produced water were considered to optimize the lifetime duration. The optimum squeeze lifetime was identified as being 2 million bbl of protected water, which was implemented for the subsequent squeeze treatments. Based on the water production rate and saturation ratio over time, the optimum chemical deployment plan was calculated. The optimization results showed that seven squeeze treatments were needed to protect the production well in the WAG scenario, while ten treatments were necessary in the waterflooding case, due to the higher water rate in the production window. The novelty of this approach is the ability to optimize a series of squeeze treatment designs for a long-term production period. It adds valuable information at the Front-End Engineering and Design (FEED) stage in a field, where scale control may have a significant impact on the field's economic viability.

We demonstrate how geological heterogeneity impacts the effectiveness of surfactant-based enhanced oil recovery (EOR) at larger (inter-well and sector) scales when upscaling small (core) scale heterogeneity and physicochemical processes. We used two experimental datasets of surfactant-based EOR where spontaneous imbibition and viscous displacement, respectively dominate recovery. We built 3D core-scale simulation models to match the data and parameterize surfactant models. The results were deployed in high-resolution models that preserve the complexity and heterogeneity of carbonate formations in the inter-well and sector scale. These larger-scale models were based on two outcrop analogues from France and Morroco, respectively, which capture the reservoir architectures inherent to the productive carbonate reservoir systems in the Middle East. We then assessed and quantified the error in production forecast that arises due to upscaling, upgridding, and simplification of geological heterogeneity. Simulation results showed a broad range of recovery predictions. The variability arises from the choice of surfactant model parameterization (i.e., spontaneous imbibition vs viscous displacement) and the way the heterogeneity in the inter-well and sector models was upscaled and simplified. We found that the parameterization of surfactant models has a significant impact on recovery predictions. Oil recovery at the larger scale was observed to be higher when using the parametrization derived from viscous displacement experiments compared to parameterization from spontaneous imbibition experiments. This observation clearly demonstrated how core-scale processes impact recovery predictions at the larger scales. Also, the variability in recovery prediction due to the choice of surfactant model was as large as the variability arising from upscaling and upgridding. Upscaled and upgridded models overestimated recovery because of the simplified geology. Grid coarsening exacerbated this effect because of the increased numerical dispersion. These results emphasize the need to use correctly configured surfactant models, appropriate grid resolution that minimizes numerical dispersion, and properly upscaled reservoir models to accurately forecast surfactant floods. Our findings present new insights into how the uncertainty in production forecasts during surfactant flooding depends on the way surfactant models are parameterized, how the reservoir geology is upscaled, and how numerical dispersion is impacted by grid coarsening.

Summary Barium sulfate (BaSO4) scale is a serious problem that is encountered during oilfield production and has been studied mainly for fields undergoing waterflooding. Chemical enhanced oil recovery (cEOR) processes involve interactions between the injected brine and the formation brine, rock and oil. Very little work has appeared in the literature on how cEOR processes can influence the severity of the mineral scaling problem that occurs in the field and how this can be managed. This study investigates barium and sulfate coproduction behavior, the deposition of BaSO4 in the formation and in the producer wellbore, and its inhibition during polymer, surfactant, and surfactant/polymer (SP) flooding cEOR processes. To aid the cEOR economic decision, assessment of the impact of cEOR flooding type on both scale management and oil recovery is performed. Reservoir simulation has been used in this study, employing homogenous and heterogeneous two-dimensional (2D) areal and vertical models. Data from the literature are used to define the parameters controlling the physical and chemical functionality of anionic surfactant and partially hydrolyzed polyacrylamide (HPAM) polymer [e.g., oil/water interfacial tension (IFT), IFT, polymer viscosity, and SP adsorption]. Assessment is made of the minimum inhibitor concentration (MIC) required to control the scale that is predicted to occur due to the changes in brine composition induced by the water and chemical flooding processes. The expected retention and release of a phosphonate scale inhibitor (SI) during squeeze treatments in the production wells is modeled. The high viscosity and more stable HPAM polymer slug reduces the mixing between the injected and the formation brines, especially with low-salinity low-sulfate (SO42−) make-up brine, reducing BaSO4 scale precipitation in the formation, delaying and reducing the potential scale risk in the producer wellbore compared to normal waterflooding. During surfactant flooding, from an oil recovery perspective, the optimal phase type and salinity can be any of the three microemulsion (ME) phase types, depending on the system multiphase parameters. However, the scaling risk can be different to that in the waterflooding case, depending on the IFT, ME phase type, the injected salinity, and sulfate concentration. In SP flooding, low-salinity make-up brine is preferred to enhance oil recovery, and it also delays and reduces scale risk. The impact of the injection brine salinity, SO42− concentration, and changing brine composition due to ion reactions affects the produced water rates, the number of required squeeze treatments and MIC values over time. This, then, impacts the inhibitor retention and release, which influences the treatment volumes and cost required to control scale over field life. Considering the economic impact of cEOR flood type on both oil recovery and scale management, low-salinity SP flooding is demonstrated to be the most viable option, showing the highest positive net present value (NPV). The study shows that barium and sulfate coproduction and the evolving scale risk depend on the mobility ratio (which is determined by the injected brine and oil viscosities) on the oil/water IFT, on the level of chemical adsorption, and on the selected brine salinity. The severity of the scale risk is also impacted by the flood techniques used, with the extent of reservoir reactions having an effect on the MIC required to control scale and the squeeze treatment volumes required to maintain production after breakthrough.

This study seeks to improve numerical simulations of the key physics occurring in CO2 enhanced oil recovery (CO2-EOR) processes, with a particular focus on the transition from immiscible to miscible displacements. In the previous work, we have investigated interactions between compositional effects and the underlying heterogeneities of the flow field in near-miscible floods (Wang et al. in Transp Porous Media 129(3):743–759, 2019a). In this current study, we have further analysed the effects of reduction in interfacial tension (IFT) on the flow behaviour, as motivated by the study on the film-flow mechanism previously presented by Sorbie and van Dijke (SPE improved oil recovery symposium, Society of Petroleum Engineers, 2010). We identify two clear mechanisms of oil recovery that may occur in near-miscible CO2 (or other gas) injection processes, which we denote, MCE, as oil stripping or conventional compositional effects, and MIFT as lower IFT oil film-flow effects. The latter MIFT effects are described by an enhanced hydrocarbon relative permeability in the near-miscible three-phase relative permeabilities (3PRP). Various combinations between the MCE and MIFT mechanisms were tested by numerical simulations to evaluate the impact of each mechanism on the flow behaviour, i.e. their separate and joint effects on quantities such as the local oil displacement efficiency, phase flow vectors and the ultimate oil recovery. When acting in combination, the oil stripping and IFT effects can greatly improve the local displacement performance even when viscous fingering flow occurs. Viscous fingering is well known to lead to bypassed oil in the “non-preferential” flow paths between the main fingers. We show that the remaining oil in these non-preferential flow paths (i.e. bypassed oil) can be efficiently recovered by the combined MCE and MIFT mechanisms, but only with the application of water alternating gas (WAG). In contrast to oil stripping effects, the IFT effect is not dependent on continuous contact between oil and CO2. Instead, the remaining oil is mobilized by gas as the IFT is reduced and can be efficiently produced by subsequent water injection. This MIFT mechanism has much less impact in cases with continuous CO2 injection compared to its efficiency in WAG. This is because during continuous injection, gas fingers are dominant in the preferential flow paths, and therefore the local displacement efficiency is very good, but only in these preferential routes. On the other hand, WAG is able to make full use of the IFT effects because of its relatively stable displacing front, which allows the MIFT mechanism to contribute. In this study, the effects of using different three-phase relative permeability methods were investigated and, as expected, different methods yielded different results. However, an important observation is that when IFT effects (MIFT) were included, there was much less difference in the final oil recovery using the different 3PRP models; our analysis shows why this is the case.

We demonstrate that the static elastic properties of a carbonate sample, comprised of dolomite and calcite, could be accurately predicted by Digital Rock Physics (DRP), a non-invasive testing method for simulating laboratory measurements. We present a state-of-the-art algorithm that uses X-ray Computed Tomography (CT) imagery to compute the elastic properties of a lacustrine rudstone sample. The high-resolution CT-images provide a digital sample that is used for analyzing microstructures and performing quasi-static compression numerical simulations. Here, we present the modified Segmentation-Less method withOut Targets method: a combination of segmentation-based and segmentation-less DRP. This new method assigns the spatial distribution of elastic properties of the sample based on homogenization theory and overcomes the monomineralic limitation of the previous work, allowing the algorithm to be used on polymineralic rocks. The method starts by partitioning CT-images of the sample into smaller sub-images, each of which contains only two phases: a mineral (calcite or dolomite) and air. Then, each sub-image is converted into elastic property arrays. Finally, the elastic property arrays from the sub-images are combined and fed into a finite element algorithm to compute the effective elastic properties of the sample. We compared the numerical results to the laboratory measurements of low-frequency elastic properties. We find that the Young’s moduli of both the dry and the fully saturated sample fall within 10% of the laboratory measurements. Our analysis also shows that segmentation-based DRP should be used cautiously to compute elastic properties of carbonate rocks similar to our sample., Frontiers in Earth Science, 9, ISSN:2296-6463

Summary Wells generally face barium, strontium and calcium sulphates (BaSO4/SrSO4/CaSO4) scaling due to incompatibility of formation water and seawater injected in the reservoir. Barium sulphate deposit was expected in this field due to the high level of barium in the formation water. Scale mitigation is achieved using conventional treatments such as continuous scale inhibitor injection or batch scale inhibitor squeeze treatment; another non-chemical and environmental preventive mitigation is the injection of low sulphate seawater (LWSW). This study showed that the increasing level of heterogeneity (layering permeability contrast), size of aquifer and high initial barium concentration in the formation water, delay the optimal relaxation timing from desulphated seawater to full seawater injection. Sulphate level in the desulphated seawater, the existing of horizontal flow barriers and slow barium sulphate reaction rate, have marginal impact on the optimal relaxation timing from desulphated seawater to full seawater injection. Gradual build-up in the sulphate concentration allows earlier relaxation behavior, with lower degree of risks compared to the direct switch to full seawater injection.

This study evaluates the potential of recycling carbon dioxide (CO2) in the associated gas for Carbon Capture Utilization and Storage (CCUS) in pre-salt carbonate reservoirs. We performed compositional subsurface modelling of a hypothetical field for multi-objective optimization, aiming at minimizing carbon emissions whilst maximizing the project’s economics. Although no absolute reduction in total CO2 emissions was met with economic improvement, all simulated CCUS scenarios yielded a lower carbon footprint oil, with 41% reduction in operational emissions and up to 20% increase in Net Present Value. The best CCUS case presented break-even oil price of 39.2 USD/STB and CO2 abatement cost of negative 92.4 USD/tCO2 abated, also showing significant reduction in number of squeeze treatments and cost of calcite scale management.

Summary Conventional carbonate reservoirs contain most of the world’s oil and gas reserves. However, the recovery factors after primary and secondary oil recovery remain low overall. Surfactant-based enhanced oil recovery can be used to enhanced oil recovery by changing the wettability of the rock and reducing the interfacial tension. In this study, we incorporated the experimentally validated surfactant models into a high-resolution outcrop analogue model. We built core-scale simulation models based on the experimental data to identify the key physical mechanisms that lead to increased oil recovery. We then parametrise the respective models in order to obtain a better understanding of physico-chemical processes during surfactant injection. Using advanced assisted history-matching methods, we were able to match the laboratory results for both the Spontaneous Imbibition and core flooding. We then implemented the results from the core-scale at a larger scale i.e., inter-well scale model. We used a realistic analogue outcrop for the Shuaiba and Kharaib formations in the Middle East, in order to understand how complex geological structures and multi-scale heterogeneities impact the recovery processes and effectiveness of surfactant-based enhanced oil recovery.

We investigate the effect of heterogeneous petrophysical properties on Low Salinity Water Flooding (LSWF). We considered reservoir scale models, where the geological properties were obtained from a giant Middle East carbonate reservoir. The results are compared against a typical sandstone model. We simulated low salinity induced wettability changes in field scale models in which the petrophysical properties were randomly distributed with spatial correlation. We examined a wide range of geological realisations which mimic complex geological structures. Sandstone was simulated using a log-linear porosity-permeability relation with fairly good correlation. A carbonate reservoir from the Middle East was simulated where a much less correlated porosity permeability relationship was obtained. The salinity of formation water was set to typically observed values for the sandstone and carbonate cases. A number of simulations were then carried out to assess the flow behaviour. We have found that the general trend of permeability-porosity correlation has a key role that could mitigate or aggravate the impact of spatial distributions of petrophysical properties. We considered models with a log-linear permeability-porosity correlation, as generally observed for sandstone reservoirs. These are likely to be directly affected by the spatial distribution more than models with a power permeability-porosity correlation, which is often reported for flow units of carbonate reservoirs. The scatter of data in the permeability-porosity correlations had a relatively small impact on the flow performance. On the other hand, the effect of heterogeneity decreases with the width of the effective salinity range. Thus, uncertainty in carbonate reservoirs arises due to the ambiguity of spatial distribution of permeability and porosity would be less affects the LSWF predictability than in sandstone case. Overall, the incremental oil recovery due to LSWF was higher in the carbonate models than the sandstone cases. We observe from uncertainty analysis that the formation waterfront was less fingered than the low salinity waterfront and the salinity concentration. The dispersivity of salinity front and the water cut can be estimated for models with various degrees of heterogeneity. The outcome of the study is a better understanding of the implications of heterogeneity on LSWF. In some cases the behaviour can appear like a waterflood in very heterogeneous cases. It is important to assess the reservoir effectively to determine the best business decision.

Petroleum-rich basins at a mature stage of exploration and production offer many opportunities for large-scale Carbon Capture and Storage (CCS) since oil and gas were demonstrably contained by low-permeability top-sealing rocks, such as shales. For CCS to work, there must be effectively no leakage from the injection site, so the nature of the top-seal is an important aspect for consideration when appraising prospective CCS opportunities. The Lower Cretaceous Rodby Shale and the Palaeocene Lista Shale have acted as seals to oil and gas accumulations (e.g., the Atlantic and Balmoral fields) and may now play a critical role in sealing the Acorn and East Mey subsurface carbon storage sites. The characteristics of these important shales have been little addressed in the hydrocarbon extraction phase, with an understandable focus on reservoir properties and their influence on resource recovery rates. Here, we assess the characteristics of the Rodby and Lista Shales using wireline logs, geomechanical tests, special core analysis (mercury intrusion) and mineralogical and petrographic techniques, with the aim of highlighting key properties that identify them as suitable top-seals. The two shales, defined using the relative gamma log values (or Vshale), have similar mean pore throat radius (approximately 18 nm), splitting tensile strength (approximately 2.5 MPa) and anisotropic values of splitting tensile strength, but they display significant differences in terms of wireline log character, porosity and mineralogy. The Lower Cretaceous Rodby Shale has a mean porosity of approximately 14 %, a mean permeability of 263 nD (2.58 &times, 10&minus, 19 m2), and is calcite rich and has clay minerals that are relatively rich in non-radioactive phases such as kaolinite. The Palaeocene Lista Shale has a mean porosity of approximately 16% a mean permeability of 225 nD (2.21 &times, 19 m2), and is calcite free, but contains abundant quartz silt and is dominated by smectite. The 2% difference in porosity does not seem to equate to a significant difference in permeability. Elastic properties derived from wireline log data show that Young&rsquo, s modulus, material stiffness, is very low (5 GPa) for the most shale (clay mineral)-rich Rodby intervals, with Young&rsquo, s modulus increasing as shale content decreases and as cementation (e.g., calcite) increases. Our work has shown that Young&rsquo, s modulus, which can be used to inform the likeliness of tensile failure, may be predictable based on routine gamma, density and compressive sonic logs in the majority of wells where the less common shear logs were not collected. The predictability of Young&rsquo, s modulus from routine well log data could form a valuable element of CCS-site top-seal appraisals. This study has shown that the Rodby and Lista Shales represent good top-seals to the Acorn and East Mey CCS sites and they can hold CO2 column heights of approximately 380 m. The calcite-rich Rodby Shale may be susceptible to localised carbonate dissolution and increasing porosity and permeability but decreasing tendency to develop fracture permeability in the presence of injected CO2, as brittle calcite dissolves. In contrast, the calcite-free, locally quartz-rich, Lista Shale will be geochemically inert to injected CO2 but retain its innate tendency to develop fracture permeability (where quartz rich) in the presence of injected CO2.

Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the in situ mineral reactions on the produced scaling ions and pH has been little reported in the literature. The objective of this study is to investigate the impact of the in situ chemical and geochemical interactions on the scale precipitation risk when the fluids reach the wellbore, and their inhibition during Alkaline-Surfactant (AS) and ASP flooding processes. Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options. Results show that the in situ rock dissolution, mineral precipitation and brine mixing reduce the produced ion concentrations (Ca2+, Mg2+, HCO3-) and pH compared to the initial concentration and the injected pH value. The calcite scaling risk can be high during Na2CO3 injection while silica and Mg(OH)2 scales are potential minerals that will precipitate in the production system during NaOH injection. Uncertainty in the mineral reaction rate parameters, especially mineral surface area, is important and must be captured, as this may impact the scaling risk in the producer. Among the studied flooding options, ASP with pre and post polymer slugs shortens the calcite scaling period, reduces the scaling ion concentrations and the produced water rates. This case, then, requires the least number of squeeze treatments, the lowest scale inhibitor volume, and delivers the highest incremental oil recovery. This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.

How to estimate operational controls so as to optimize economic returns in CO2-WAG projects and reduce calcite scale risk? The reactivity and heterogeneity intrinsic to carbonate reservoirs make CO2-WAG (Water Alternating Gas) injection a big challenge. While miscibility effects greatly increase oil recovered, the presence of CO2 can cause severe flow assurance issues. The aim of this paper is to introduce a simulation-based methodology to optimize the design of CO2-EOR operations, considering economics, mineral scaling risk and environmental impact. A compositional reservoir model was built to simulate a reactive 3-phase miscible flow in porous media. Aiming at maximizing the Net Present Value (NPV), we optimized the following operational variables: duration of waterflooding period; injection rates; producer bottomhole pressure (BHP); WAG ratio, gas half-cycle duration and number of cycles for different WAG stages (tapered WAG). We then used the forecasted data to quantify calcium carbonate scaling tendency for the scenarios of interest and design scale management strategies (squeeze treatments) with the lowest costs. The optimal WAG design found through the methodology increased NPV by 55.6% compared to a base-case waterflooding scenario. We also found that performing a waterflood in a carbonate reservoir with high CO2 content will result in more severe calcite scale risk than applying equivalent WAG schemes. A lower production BHP can reduce the potential for precipitation, by allowing the CO2 to evolve from the aqueous solution within the reservoir, before it arrives at the production wellbore. On the other hand, a lower producer BHP can increase water production rates and, therefore, scale risk. The proposed workflow provides valuable insights on the procedures involved in simulating and optimizing CO2-WAG projects with high calcite scale risk. Its application demonstrated the importance of an integrated analysis that seeks for higher economic returns in a sustainable manner, with reduced production issues caused by CO2 speciation.

It is common that a large volume of hydrocarbons remained unrecovered after primary and secondary recovery. Enhanced Oil Recovery (EOR), as tertiary recovery, plays a key role in recovering additional volumes of hydrocarbons. However, there is little work in the literature on the impact of different EOR mechanisms on the flow behaviour of formation/injected brines and scaling tendencies. The objective of this manuscript is to investigate, by the means of reservoir simulation, the impact of different EOR techniques, namely low salinity waterflooding (LSW), polymer flooding and Thermally Activated Polymer (TAP), for in-depth conformance control, on oil recovery and BaSO4 scale deposition. A reactive transport reservoir simulator was used to evaluate the impact of three EOR techniques in the mixing profiles of injected seawater and formation brine, resulting in the precipitation reaction of BaSO4, due to the incompatible mixing of formation and injected brines. Three two-dimensional models were considered, a homogeneous and heterogeneous areal model to compare polymer flooding and LSW; and a vertical heterogeneous model to analyse the effect of TAP. Results show that LSW delays and reduces the risk of BaSO4 scale deposition at the producer, due to the fact that the concentration of injected SO42- is significantly lower than full sulphate injection seawater. However, LSW results in longer co-production period of Ba2+ and SO42- ions, due to the fact that Ba2+ stripping is reduced because of the scale precipitation within the reservoir is reduced. Polymer flooding improves the sweep displacement, which delays the onset of scale formation, shortens the co-production period of the scaling ions at the producer and reduces the amount of water produced, hence, reducing the scale risk. TAP injection results in the delay of the injected water breakthrough, which delays the onset of scale formation in the producer; however, it can increase the amount of formation water (hence Ba2+ ions concentration), mainly from the low permeability zones, in the producer. EOR techniques may have a major influence on the evolution of scaling ions in the produced water, which has to be taken into account for an optimum scale management strategy, to maximize oil production.

Deep geological formations such as saline aquifers and depleted oil and gas fields are potential sites for CO 2 geological storage. The local host rock in these formations can have significant quantities of calcite present, such as in limestone or where carbonate formations have overlying chalk intervals. Therefore, the objective of this work is to understand how CO 2 -saturated brine interacts with calcite under reservoir conditions. Hydrothermal experiments were carried out over a 6 month period to assess the potential for calcite to buffer brine and promote mineral carbonation over time. In addition, as the system had yet to reach equilibrium at 6 months, geochemical modelling using PHREEQC was performed to calculate the equilibrium state. The dissolution and precipitation of minerals were investigated to determine the effect that these processes have on the properties of the rock, such as porosity. The addition of calcite to the brine resulted in a significant increase in brine pH from 2.03 to 5.72. However, once CO 2 had been injected there was only a slight initial increase in pH, and therefore, the buffering effect of calcite is not sufficient to promote mineral carbonation. The formation of anhydrite, celestite and hematite was observed after 3 months, although dissolution and precipitation were still taking place after 6 months. The PHREEQC modelling conducted estimated an overall decrease in mineral volume of 2.3%, leading to an increase in porosity that is dependent on the SO 4 2 − concentration in the original brine. Therefore, brine composition needs to be considered when injecting CO 2 into reservoirs containing calcite bearing rock.

SummaryIn waterflooded reservoirs under active scale management, produced-water samples are routinely collected and analyzed, yielding information on the evolving variations in chemical composition. These produced-water chemical-composition data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale-management programs designed to minimize damage and enable improved recovery.In this interdisciplinary paper, the analyses of produced-water compositional data from the Miller Field are presented to investigate possible geochemical reactions taking place within the reservoir. The 1D and 2D theoretical model has been developed to test the modeling of barium sulfate precipitation implemented in the streamline simulator FrontSim. A completely 3D streamline simulation study for the Miller Field is presented to evaluate brine flow and mixing processes occurring in the reservoir by use of an available history-matched streamline reservoir-simulation model integrated with produced-water chemical data. Conservative natural tracers were added to the modeled injection water (IW), and then the displacement of IW and the behaviors of the produced water in two given production wells were studied further. In addition, the connectivity between producers and injectors was investigated on the basis of the comparison of production behavior calculated by the reservoir model with produced-water chemical data. Finally, a simplified model of barite-scale precipitation was included in the streamline simulation, and the calculation results with and without considering barite precipitation were compared with the observed produced-water chemical data. The streamline simulation model assumes scale deposition is possible everywhere in the formation, whereas, in reality, the near-production-well zones were generally protected by squeezed scale inhibitor, and, thus, the discrepancies between modeled and observed barium concentrations at these two given wells diagnose the effectiveness of the chemical treatments to prevent scale formation.

The alternate injection of CO gas and water (CO WAG) adds more complexity to the development of carbonate oil reservoirs. First, the switching between water and gas cycles causes oscillations in the pressure and flow rate because of variable fluid mobilities. Second, gravity segregation can occur since the CO2 is less dense than water (and oil) under most reservoir conditions. Moreover, since the injected fluids are generally cooler than the initial reservoir temperature, heat exchange is constantly happening because the injected fluids (especially water) extract heat from the reservoir rock as they propagate from cooler to warmer regions. These changes in temperature disturb the flow behaviour not only by modifying the physical properties of the fluids, such as densities and viscosities, but also by enhancing calcite dissolution and subsequent pore space alterations. In this work, we simulate multiphase flow coupled with heat exchange and mineral reactions to model the porosity and permeability changes during CO2 WAG injection in carbonate oil reservoirs. A multilayered model of a limestone reservoir is initialised with 500 bar to calculate calcite volume changes in a more reactive environment comparable with the Brazilian pre-salt, as compared to reported (carbonate) field cases and simulations. Porosity changes are derived from volume change of calcite at each time step, while permeability is updated following the formulation of Carman-Kozeny. Dissolution zones around the injectors are calculated as well as their impact on permeability and injectivity increase. Special considerations are made regarding the mass of calcite that can potentially precipitate in the production system (i.e. scale management). This contibution extends the knowledge about the impacts of calcite dissolution and re-precipitation on CO2 WAG operations in deep carbonate reservoirs. The novelty lies on the investigation of the effects of cross-flow between layers and gravity segregation on the scale deposition. Moreover, this model extends our previous work on twodimensional simulation by including the vertical heterogeneity. We show how reactions proceed in layer of different properties and what are the risks of scale deposition at well perforations for a given vertical profile of initial porosity and permeability.

CO2-WAG (Water-Alternating-Gas) has been applied in offshore Brazilian oilfields to improve recovery rates and mitigate the environmental impact that venting produced CO2 would bring. Although CO2 is highly miscible in oil under these reservoirs conditions, this gas is also extremely mobile, and its speciation in the aqueous phase drives reactions with carbonates that can cause severe inorganic scaling problems in production systems. It is crucial, therefore, to effectively design CO2-WAG operations for mobility control and, consequently, enhance reservoir performance, CO2 utilization and flow assurance. This paper addresses the design optimization of coupled CO2-EOR and storage operations applied to the Brazilian Pre-salt offshore context (reservoir properties, infrastructure, regulatory framework and economic characteristics), examining the trade-offs of project profitability, CO2 utilization and calcite scale risk. Several compositional simulations of miscible WAG scenarios were performed and key design parameters were optimized using statistical sampling and evolutionary algorithms. Aqueous and mineral reactions were included in the calculations, allowing us to quantify the calcite mass that can potentially deposit in the perforations and production system. The results showed how optimizing WAG operations can significantly improve the economics and the scale management of oil production from carbonate reservoirs. The optimal WAG design greatly increased incremental NPV per volume of CO2 stored and reduced calcite scale risk by simply rearranging the WAG slugs in a tapered manner. Here we demonstrate that this methodology can be used to determine how to recycle CO2 in a given field for better economics and lower carbon footprint, doing so without triggering calcite mineral deposition to the point of permanent jeopardy of production wells and facilities operability. Therefore, the workflow integrates critical challenges that are correlated, yet often addressed independently, supporting the complex decision-making of CO2-EOR operational design in carbonate reservoirs.

We investigate how efficiently oil can be recovered from a carbonate rock during surfactant based enhanced oil recovery (EOR) at the core-scale, particularly when chemical processes change wettability, and analyse how geological heterogeneities, observed at the next larger scale (centimetre to decimetre) impacts the effectiveness of surfactant-based EOR at the inter-well scale. To quantify how heterogeneity across scales impacts surfactant flooding, we combine laboratory experiments with simulation studies at the core- and inter-well scale. We first analysed a series of surfactant imbibition experiments at different surfactant concentrations (from 0 to 3 wt. %) using reservoir cores from the Wakamuk field, a carbonate reservoir in Indonesia. We then built a 3D simulation model of the laboratory experiment and matched the experimental data to identify the key physical mechanisms (e.g., reduction in interfacial tension (IFT) and wettability alteration) that lead to increased oil recovery. Next, we parametrised the surfactant models using assisted history-matching methods to calibrate the relative permeability and capillary pressure curves as a function of surfactant concentration. These models were then deployed in high-resolution simulations at the inter-well scale. These simulations captured the small-scale geological heterogeneities that are typical for a carbonate reservoir system, e.g., the Shuaiba formation in the Middle East, but are not resolved in field-scale models. Our core-scale simulations demonstrate a change from co- to counter-current flow in the laboratory experiments and indicate that the resulting increase in oil recovery is due to a combination of IFT reduction, wettability alteration from oil- to water-wet, and capillary pressure restoration; these processes need to be captured adequately at the inter-well scale model. The increase in surfactant concentration above the critical micelle concentration (CMC) (i.e., from 1 to 3 wt. %) triggered the capillary pressure restoration and dominated recovery at the early-time. The changes in relative permeability and capillary curves during the surfactant floods were best modelled using a concentration-based interpolation. There is uncertainty when calibrating surfactant models using laboratory experiments. A key question hence is if geological heterogeneity at the inter-well scale masks these uncertainties. Results from our high-resolution simulations show that large-scale heterogeneity impacts recovery predictions, but it is the coarsening of the grid, not the upscaling of permeability, that dominates the error in field-scale recovery predictions during surfactant based EOR. Indeed, the error arising from numerical dispersion during grid coarsening can be as large as the error arising when selecting an inaccurately configured surfactant model due to the lack of quality experimental data. Hence appropriate grid refinement, possibly using adaptive grid refinement, needs to be considered when setting up a surfactant based EOR simulation, along with the appropriate configuration of the surfactant model itself.

Summary The evidence from the produced-brine chemistry suggests that the Gyda field has experienced a variety of geochemical reactions caused by the high temperature and initial calcium (Ca) concentration, and so it is worth reviewing the produced-water data set and studying what in-situ geochemical reactions may be taking place. Produced-brine-chemistry data from 16 wells in the Gyda field are plotted and analyzed in combination with general geological information and the reservoir description. A 1D reactive-transport model is developed to identify the possible geochemical reactions occurring within the reservoir triggered by seawater injection, and then extended with the inclusion of thermal modeling and also to be a 2D vertical-cross-section model. Three possible classes of formation-water composition in different regions of the Gyda field have been identified by analysis of the produced-water data set. Anhydrite and barite precipitation are the two dominant mineral reactions taking place deep within the reservoir. Magnesium (Mg) stripping may be a result of multicomponent ion exchange (MIE), dolomite precipitation, or a combination of both. Reservoir temperature is lowered during cold-water injection. The solubility of anhydrite increases at lower temperature, and anhydrite will gradually dissolve in response to the movement of the temperature front, which is much slower than the formation/injection-water mixing front. The extent of mineral precipitation within the reservoir can be reduced by the heterogeneity; the modeling shows that the extent of ion stripping caused by mineral reactions in the reservoir is greatest when simulating a single uniform layer. Brine mixing and the occurrence of geochemical reactions caused by vertical mixing are not observable, even when assigning a high vertical permeability in a heterogeneous model. Thermal modeling is included to evaluate the effect of nonisothermal processes and heat transport on the geochemical reactions, especially the anhydrite mineral reaction. We have investigated how the difference in horizontal permeability in the two layers affects brine mixing of formation and injection water and geochemical reactions.

Summary Vapor/liquid-equilibria (VLE) calculations, particularly involving the phase behavior of carbon dioxide (CO2) and hydrogen sulfide (H2S), are used in scale-prediction modeling. In this work, the impact of VLE calculations for CO2- and H2S-rich gas phases and for acid- and sour-gas mixtures on scale-prediction calculations is evaluated. Three equations of state (EOSs)—Soave-Redlich-Kwong (SRK) (Soave 1972), Peng-Robinson (PR) (Peng and Robinson 1976), and Valderrama-Patel-Teja (VPT) (Valderrama 1990)—are implemented in the Heriot-Watt model and used in VLE calculations. The solubility of single-component CO2 and H2S in water and the solubility of a gas mixture in water were compared with experimental data in terms of the absolute relative deviation (ARD). The solubility data were then used in PHREEQC (USGS 2016) to calculate the impact of using different EOSs on carbonate and sulfide scales, particularly on calcium carbonate (CaCO3) and iron sulfide (FeS). Average ARDs of 6.04, 4.10, and 3.77% between experimental and calculated values for CO2 solubility in water were obtained for the SRK, PR, and VPT EOSs, respectively. Similarly, for H2S solubility in water, average ARDs of 6.49, 6.66, and 6.48% were obtained for each EOS, respectively. For the solubility of sour- and acid-gas mixtures in water, average ARDs of 13.92, 13.25, and 10.78% were obtained, respectively. It has thus been concluded that the VPT EOS performs better than the SRK and PR EOSs in VLE calculations for the analyzed data. The errors introduced in VLE calculations have been found to impact the calculation of the amount of CaCO3 precipitated, with consequences for scale-inhibitor selection. Higher deviations were found in the amount of CaCO3 precipitation for gas mixtures when compared with a single-component, CO2-rich phase. Furthermore, the large errors occurring in VLE calculations for H2S solubility have not been found to impact the calculation of the amount of FeS precipitated when H2S is in excess with respect to Fe2+. In addition to this, a case study that was performed by use of formation-water data from the Brazilian presalt revealed that the choice of EOS can cause errors of 6 kg of precipitate during each day of production. Scale-prediction calculations carried out with PHREEQC demonstrate that VLE calculations can have a high impact on mineral precipitation. Thus, it is recommended that the best VLE model available should always be used for scale-prediction modeling, particularly when mixtures of gases are present.

In this proposed CO 2 injection system, brine is extracted from the target storage aquifer by means of a lateral horizontal completion located near the top of the formation. It should be noted that the brine is not lifted to the surface. An Electrical Submersible Pump (ESP) is used to extract the brine and boost its pressure, before it is mixed with CO 2 that is injected down the vertical section of the well. The mixing takes place in the vertical section of the well below the upper lateral. The CO 2 –brine mix is then injected into the same formation through a lower lateral. A down-hole tool would be used to maximise agitation and contact area between CO 2 and brine in the vertical mixing section of the well, which may be tens to hundreds of metres long, depending on the thickness of the formation. The advantages of this method are that there is little overall pressure increase, because CO 2 is mixed with brine extracted from the formation, and also the extracted brine is already at high pressure when it is mixed with the CO 2 , greatly increasing the solubility of CO 2 and reducing the volume of brine required. Energy is not expended lifting the brine to surface nor is there any concern about handling large volumes of acidic brine in the surface equipment. In this study, in addition to the concept of the down-hole mixing (DHM) method which is presented, the application of the DHM method in a hypothetical storage site (Lincolnshire—Smith et al., 2012) is also examined. The calculations are performed to identify the optimum rates of water extraction and injection of dissolved CO 2 in brine.

When CO2 is injected into an aquifer, the injected CO2 is generally colder than the reservoir rock; this results in thermal gradients along the flow path. The temperature variation has an impact on CO2 solubility and the kinetics of any mineral reactions. Core flood experiments and associated reactive transport simulations were conducted to analyse thermal effects during CO2 injection in a dolomitic limestone aquifer and to quantify how CO2 solubility and mineral reactivity are affected. The experiments were conducted by injecting acidified brine into an Edwards Limestone core sample. A back pressure of 400 psi and injection rates of 30 mL/hr and 300 mL/hr were used. A range of temperatures from 21 °C to 70 °C were examined. Changes in the outlet fluid composition and changes in porosity and permeability were analysed. A compositional simulation model was used to further analyse the experiments. The simulations were history-matched to the experimental data by changing the reactive surface area and the kinetic rate parameter. The calibrated model was then used to test the sensitivity to CO2 injection rate and temperature. The impact of temperature on CO2-induced mineral reactions was observed from changes in mineral volume, porosity and permeability. The reaction rate constants estimated from the outlet solution concentrations are much lower than existing data for individual minerals. The estimated specific surface areas for carbonate minerals are in reasonable agreement with published values. The numerical investigations showed that at the lower temperatures, despite the reaction rates being slower, the solubility of the minerals was higher, and so as a result of these competing effects, moderately elevated calcium and magnesium concentrations were observed in the effluent. At higher temperatures, the solubilities of the minerals were lower, but now the reactions rates were higher, so similar effluent concentrations could be achieved. However, at higher flow rates, characterized by a lower Damköhler number, the residence times were shorter, and so lower effluent concentrations were observed. Additionally, the solubilities of calcite and dolomite varied to different extents with temperature, and so the calcium to magnesium molar ratio in the effluent brine increased with increasing temperature. The change in mineral composition during CO2 injection varies between the near well zone and the deeper reservoir. Near the well where the temperatures will be lower, solubilities are elevated, but the kinetic reaction rates and residence times will be lower, somewhat limiting dissolution. Deeper in the aquifer the solubilities will be reduced and residence times will be longer, enabling an equilibrium to be established. Modelling is thus required to connect these flow regimes.

Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation. This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C. This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions. The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator. A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible in situ geochemical reactions (precipitation, dissolution, ion exchange) and account for observed ion trends. The model predicts that the process, which is beneficial in terms of reducing the scale risk, is more pronounced at higher temperatures. It has been observed previously that high temperature (130°C) chalk reservoirs may act as natural sulphate reduction plants during seawater flooding, reducing sulphate scaling and souring risks, and so reducing the operating costs (scale squeeze treatment frequency, chemical volumes) of these fields. This work illustrates new evidence of magnesium depletion and sulphate retardation above levels expected for just brine/brine interactions for a 130° C sandstone reservoir with the implication that the geochemical reactions may lead to reduced operating costs (in terms of squeeze treatment volumes and treatment frequencies) in sandstone reservoirs with low carbonate mineral content that are undergoing seawater flooding.

WAG (Water-Alternating-Gas) schemes have been applied in Brazilian carbonate reservoirs aiming to minimize residual oil saturation and gas flaring by recycling CO2 naturally being produced alongside hydrocarbon gas. However, applying WAG injection in highly reactive and heterogeneous carbonate rocks can potentially create severe scaling problems. This work develops a reactive transport simulation-based workflow to evaluate the impact of key WAG design parameters on oil recovery, scale deposition risk and CO2 storage to support multi-objective decision-making. Compositional simulations of WAG scenarios were performed as part of a sensitivity study followed by statistical analysis in order to quantify to what extent the outcomes of interest are sensitive to variations on four WAG design parameters: WAG ratio, CO2 concentration in the injection gas stream, injection rate and solvent slug-size. We established an Equation-of-State (EoS) using PVT data, a representative geochemical model and well constrains designed to control production of injected fluids. Scale risk was assessed by calcite changes around the wells, precipitation in well tubing and surface facilities, and water breakthrough. Results of this study showed that values of calcite rate constant (Ksp) and reactive surface area (A0) assigned in numerical simulations can impact relative calcite changes in the reservoir. Using reactive surface areas from BET studies of crushed rocks can lead to prediction of unrealistic amounts of calcite dissolution. Cases with lower values of (Ksp×A0) appeared to be more numerically stable and more consistent with dissolution/precipitation rates of silicate minerals. Simulation results also suggested that calcite dissolution close to injection wells and precipitation in production wells and surface facilities become more severe as CO2 concentration in injection gas and WAG ratio increases. Based on the design variables and reservoir conditions studied, the most to least crucial factors affecting oil recovery were: CO2 concentration in the injection gas stream, injection rate, WAG ratio and solvent slug-size. From a storage perspective, the impact of the design variables had considerably more impact, with the most influential factor being again CO2 concentration in the injection gas stream, followed by WAG ratio, injection rate and solvent slug-size. Optimization study results suggested that low WAG ratio values combined with low to intermediate gas slug sizes could result in superior profitability and CO2 storage outcomes for this pilot. Ultimately, we demonstrate the importance of integrating multiphase miscible displacement with geochemical reactions while modeling complex CO2-EOR in carbonate reservoirs and address how key design parameters impact our desired outcomes, knowledge that promotes a more robust decision-making framework.

Approximately 20,000 metric tons of CO2 were injected in the top sequence of the Mississippian age carbonate reservoir to evaluate potential for CO2 Enhanced Oil Recovery (EOR) and to estimate potential of transitioning to geologic CO2 storage through EOR. This paper focuses on tracking of CO2 plume movement in the reservoir using results of reservoir fluid chemical composition monitoring, CO2 plume and injection impact delineation, and studying effects of faults and naturally occurring fractures on fluid movement at the Wellington Field. We found that one of 12 identified and mapped faults worked as a partial barrier to CO2 movement and the associated damage zone and fracture network performed as a flow conduit, determining CO2 flow paths.

CO2-WAG injection has been applied in offshore Brazilian carbonate reservoirs aiming to improve oil recovery and promote a safe destination to CO2 naturally being produced alongside with hydrocarbon gas. A gas re-utilisation strategy can potentially lead to multiple benefits: residual oil saturation reduction, maintenance of reservoir pressure, avoidance of gas flaring and development of the infrastructure and expertise necessary to make CO2 storage more accessible once oil production is complete, paving the path for a low carbon future, whereas mature basins can be a potential hub for Carbon Capture, Utilisation and Storage (CCUS). This study aims to develop a methodology to design CO2-WAG projects that not only achieve a high Net Present Value (NPV) but also maximizes the capacity and safety of geological CO2 storage.

Low Salinity Water Flooding (LSWF) is an emergent technology developed to increase oil recovery. Many laboratory tests of LSWF have been carried out since the 1990's, but modelling at the reservoir scale is less well reported. Various descriptions of the functional relationship between salt concentration and relative permeability have been presented in the literature, as have the differences in the effective salinity range over which salt content takes effect. This paper focuses on these properties and their impact on the fractional flow of LSWF. We present observations that help characterise the flow behaviour in a more general form, simplifying the interpretation of results. We explain how numerical or physical diffusion of salt affects the velocity of the waterflood front, and how this can be predicted from fractional flow analysis. We have considered various linear and non-linear shapes of the function relating salinity to relative permeability and different effective salinity ranges using a numerical simulator applied at the reservoir scale. The results are compared to fractional flow theory in which both salt and water movement is assumed to be shock-like in nature. We observe that diffusion of the salt front is an important process that affects the fractional flow behaviour depending on the effective salinity range. The simulator solution matches the analytical predictions from fractional flow analysis under the condition that the mid-point of the effective salinity range is at the mid-point between the formation and injected salt concentrations. However, an effective behaviour similar to adsorption/desorption occurs when these mid-point concentrations are not coincidental. The outcome is that the fronts representing high and low salinity water travel with altered velocities and at different saturations. We find that we can predict this behaviour from the input data alone as an augmented form of the fractional flow theory including the concept of retardation or acceleration as occurs for adsorption and desorption for other injectants. We use the analytical solution to the advection-diffusion equation and find that the changes in behaviour depends on the Peclet number. The result of our work is that we have produced an updated form of the fractional flow model of LSWF, to include the impact of salt front diffusion on the movement of fluids. A new factor is introduced, similar to adsorption in polymer flooding. We have developed a new mathematical formula, empirically, to estimate the magnitude of this factor. The new form can be used to modify the effects that numerical or physical diffusion have on the breakthrough times of high and low salinity water fronts during LSFW. This will improve predictive ability and also reduce the requirement for full simulation.

Barium Sulphate (BaSO4) scale deposition is a serious problem encountered in oilfield operations. The precipitation of BaSO4 scale has been studied mainly for fields under water flooding. On the other hand, polymer flooding is a mature Enhanced Oil Recovery (EOR) method that has been applied successfully in many fields. This study investigates the effect of polymer flooding and salinity variations on oil Recovery Factor (RF) and on brine mixing and BaSO4 precipitation in porous media and the scale risk in producers. Reservoir simulation has been used to carry out the study. We have performed simulations using a reactive transport simulator and heterogeneous 2D areal and vertical models and a field scale 3D model. Data from literature have been utilized to define parameters that control polymer viscosity, polymer adsorption and barium (Ba2+) and sulphate (SO42-) concentrations. We have also studied the effect of injecting a low salinity water as the make-up brine for the polymer slug to see its impact on oil recovery and BaSO4 precipitation. The study shows that the injection of a viscous polymer slug reduces the mixing between injected and formation brines and so reduces the amount of BaSO4 deposition in the reservoir compared to a normal water flood. This reduction is not large and its effect on reservoir permeability is marginal. However, importantly the viscous polymer delays the breakthrough of injected water and hence the precipitation of BaSO4 at the wellbore. Including the effect of polymer adsorption makes the polymer front move slower than the SO42- front, and this accelerates BaSO4 precipitation at the wellbore and increases the total precipitation compared to the case without adsorption. A low salinity polymer slug, which contains low SO42- concentration, improves polymer viscosity, which enhances oil recovery, and reduces and delays the amount of BaSO4 deposition in the formation and in the producers. The behaviour of brine mixing is different under polymer flooding compared to normal water flooding. This work shows for the first time that this impacts the amount of BaSO4 scale that precipitates in the reservoir, and thus the timing and amount of potential scale deposition in the wellbore.

Carbonate and sulphide scales can form in CO2 and/or H2S-rich environments in a process which we refer to as "auto-scaling", i.e. these scales form in the produced brine due to a change in conditions such as pressure and temperature, not due to brine mixing. Particularly in production systems, carbonate and sulphide scales can form due to the evolution of CO2 and H2S from the aqueous phase to the gas phase caused by a pressure decrease. Carbonate scale formation in this manner is broadly understood; however, there are details of precisely how this occurs in auto-scaling processes which are not widely appreciated.Measuring the water composition at surface locations (e.g. at the separator) does not give a full indication per se of the amount of scale that has precipitated upstream of the sampling point. However, the composition of the water before precipitation occurs is required for predicting the scaling potential of the system, and this information is seldom available. In this paper, we propose a model that accounts for this issue, and that accurately calculates the carbonate and sulphide scaling profiles in CO2 and/or H2S-rich production systems by knowing only commonly available surface data – i.e. pressure, temperature, and fluid compositions (water, gas, and oil). A rigorous workflow which can do this calculation using any aqueous scale prediction model along with a PVT Model has already been published by the authors (Verri et al, 2017a). The current paper describes a new model to do these calculations which also includes an approach for estimating both the "correct" scaling case within a range of cases up to the "worst case" carbonate scaling scenario.A scale prediction model has been developed to include a three-phase flash algorithm (using the Peng-Robinson Equation of State) coupled with an aqueous electrolyte model (using the Pitzer equations as the activity model). This model is used to run a demonstration example showing the procedure to calculate accurate auto-scaling profiles in CO2 and/or H2S-rich production systems, which is based on building a sensitivity analysis on the ions directly involved in precipitation reactions. We also note that auto-scaling profiles in production systems are commonly obtained by sectioning the production system – either by parameterising depth with pressure and temperature, or by selecting specific locations (e.g. DHSV, wellhead, etc.). Then, established guidelines to treat scale (or not) based on the calculated saturation ratios and precipitated masses of scale can be applied. We show that such an approach is not optimal and that it can lead to under or over-estimation of scale treatments. Furthermore, building on our previous method (Verri et al 2017a) we propose an approach to model the cumulative amount of scale formed under full equilibrium conditions, which is not dependent on how the production system is sectioned. By doing so, the correct amount of scale formed in the production system is always calculated, thus avoiding non-optimum scale treatments.Our approach focuses on calculating the correct auto-scaling profiles in CO2 and/or H2S-rich production systems, and on correctly interpreting the results obtained by thermodynamic modelling and it can be easily integrated with commonly available scale prediction software.

Produced water chemical compositional data are collected from a carbonate reservoir which had been flooded by North Seawater for more than 20 years, so there is an opportunity to analyse the large amount of produced water data collected, understand the brine/brine and brine/rock interactions and explore the impact factors behind them. In some publications, core flood experimental tests were performed with chalk cores or carbonate columns in order to make an understanding of possible chemical reactions occurring triggered by injected water with different composition (Seawater, low salinity water or any other brine). However, most of the time the laboratory conditions where core flooding experiments are implemented cannot fully simulate the real reservoir conditions. Therefore, in this study, with the help of the valuable produced water dataset and some basic reservoir properties, a one-dimensional reactive transport model is developed to identify what in situ reactions were taking place in the carbonate reservoir triggered by seawater injection.From the perspective of reservoir mineralogy, calcite, as the dominant mineral in the carbonate reservoir, is relatively more chemically reactive than quartz and feldspar which are usually found in sandstone. Whether calcite is initially and dominantly present in the carbonate reservoir rock is dissolved under seawater flooding or not is the first key issue we focused on. The effects of calcite dissolution on the sulphate scaling reactions due to incompatible brine mixing and the potential occurrence of carbonate mineral precipitation induced by calcite dissolution are investigated and discussed in detail. The comparison of simulation results from the isothermal model and the non-isothermal model show the important role of temperature during geochemical processes. The partitioning of CO2 from the hydrocarbon phase into injected brine was considered through calculation of the composition of reacted seawater equilibrated with the CO2 gas phase with fixed partial pressure (equivalent with CO2 content), then subsequently the impact of CO2 interactions on the calcite, dolomite and huntite mineral reactions are studied and explained. We also use calculation results from the model to match the observed field data to demonstrate the possibility of ion exchange occurring in the chalk reservoir.

Calcium carbonate (CaCO3) scale can form through an "auto-scaling" process in production systems with a CO2-rich environment due to fluid (water/oil/gas) depressurisation. Thermodynamic modelling is used to estimate the amount and severity of CaCO3 scale precipitation in this context in order to design scale inhibitor or other types of treatments. However, field experience has indicated that thermodynamic calculations often lead to an overestimation of the calcite scale problem. One possible source of this discrepancy may be due to kinetic effects; i.e. that the calcite is somewhat oversaturated (Saturation Ratio, SR >1) but the driving force is not sufficiently large and so the deposition is kinetically "slow". The industry response to this situation has been to come up with some simple heuristics based on field observations, and "rules of thumb" have been developed to account for this apparent overestimation of calcite deposition. The central objective of this paper is to try to address the problem of using such an arbitrary field procedure for calcite scale prediction by introducing the kinetics of calcite deposition in a thermodynamically consistent manner. We view the calcite auto-scaling system as one which moves from SR < 1 (non scaling) incrementally to one that is slightly supersaturated (SR slightly > 1). By making the deposition rate a function of SR, this would give slow rate of deposition initially, but as the system moved into the more scaling regime in the production system (SR > 1) then the deposition rate would increase. However, throughout the system, this kinetic formulation must limit correctly (i.e. it must be consistent with) the underlying equilibrium thermodynamics of the full brine/oil/gas system. Thus, we replace the idea of using heuristic estimates of when calcite scaling occurs by one where an estimate (or measurement) of the kinetics is made; indeed, a range of kinetics rates can easily be run to give an envelope of calcite scaling profiles in the wellbore and throughout the production system. In this paper, we present a model that incorporates a fully consistent kinetic formulation into a general thermodynamic scale prediction model. This model can then calculates scaling profiles in production systems considering both kinetic and thermodynamic effects. In particular, a rate law for the precipitation of CaCO3 based on the respective degree of super-saturation is coupled with the Heriot-Watt FAST Scale Prediction model (HW FAST). HW FAST uses the Pitzer equations and the Peng-Robinson Equation of State to model, respectively, the aqueous and hydrocarbon phases (gas and oil), and it has been developed to calculate CaCO3 scaling profiles caused by a de-pressurisation effect in CO2-rich production systems. First, we present an equilibrium thermodynamic example calculation showing that CaCO3 scale precipitates in CO2-rich production systems due to a de-pressurisation effect, and that precipitation is more severe topsides where the pressure is low than it is downhole where the pressure is high. It is explained that the amount of scale precipitated in this auto-scaling process must be plotted as a cumulative amount, in order to avoid the calculation of a potentially misleading scaling profile. This calculation is then repeated, but also considering kinetic effects for systems with varying temperatures and water flowrates. In the example presented here, we show that this system with sufficiently "low" water flowrates can be approximated by a thermodynamic calculation, and that systems with "high water" flowrates must take kinetic effects into consideration. This scaling profile can then be used to more accurately design scale inhibitor treatments, thus avoiding under or over-treatments (e.g. opting for continuous scale inhibitor injection instead of the more expensive squeeze treatment). Our approach focuses on calculating the correct scaling profile in auto-scaling processes, both qualitatively and quantitatively, by coupling a kinetic formulation to a thermodynamic model, and it can be readily extended to other auto-scaling processes. Further, our kinetic model can be easily integrated with commonly available scale prediction software.

The conventional method for describing transport of solutes such as salt, polymer and tracers is to use the mass conservation law. In simulation of this law for Low Salinity Water Flooding (LSWF), the effective salinity range defines how salt affects the mobility of water and appears to be crucial for controlling fluid movement. In this study, we examined the non-linear feedback between salt concentration movement and the low salinity water front as a function of physical and numerical dispersion, in combination with the effective salinity range, and we investigated how the front speeds were altered. We examined a numerical model of the mass conservation law to simulate LSWF at the reservoir scale. The cell sizes and the time steps were chosen to control the numerical dispersion coefficient in place of physical diffusion. A range of diffusion coefficients was considered along with various representations of the effective salinity range and the function that controls the effect that salt has mobility. The latter has been shown to be variable in the literature. We compared simulations to the analytical solution of solute transport obtained for the diffusion-advection equation assuming a fixed flowing velocity. We observed that the salinity front moved faster than was predicted by the analytical solution and this effect was increased the further the effective salinity range was set below the connate water salinity. In this case, the higher salt concentrations lay in the faster moving water (the connate water front), which also speeded up. This was very much a dispersion related effect, with the variation of velocity growing as the salt concentration spread out. By implementing many numerical tests, we obtained a modification to the advection term in the conventional mass conservation law of solute transport. This term depends on the Peclet number, the velocities of the high and low salinity fronts and the effective salinity as a proportion to the connate water salinity. In an advection-diffusion system, these factors usually affect only the advection term (the front velocity), while the diffusion term is unchanged. From numerical tests, we can now rapidly predict the movement of the salt front by this newly derived modification of the analytical solution.

The dissolution of CO 2 in brine (solubility trapping) is one of the most secure and permanent trapping mechanisms when considering CO 2 geological storage. In addition, CO 2 dissolution in brine is an important mechanism of CO 2 enhanced oil recovery as it improves sweep efficiency and increases oil displacement. Currently, there is a range of experimental methods that has been used to measure CO 2 solubility in brine and a critical review of these methods is presented here. Several different geochemical models that can be used to calculate CO 2 solubility in brine are also reviewed and the importance of selecting the correct equation of state (EoS) is addressed. Furthermore, the validity of the experimental results was ascertained through a comparison of the published experimental results with those produced through geochemical modeling. The geochemical modeling software, HydraFLASH, can be used to accurately calculate CO 2 solubilities under a number of conditions provided the correct EoS is selected. For the purpose of CO 2 ‐water systems, the Valderrama‐Patel‐Teja EoS is the most accurate as it is designed to be used for systems containing polar and non‐polar compounds. The published experimental results were compared with those obtained through the geochemical modeling, to ascertain the most accurate means of measuring CO 2 solubility. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd

The Pembina Cardium CO2 Monitoring Pilot was used as a test site to determine the relative roles of trapping mechanisms. Two methods to assess this distribution are presented. A geochemical approach using empirical data from the site was used to determine the phase distribution of CO2 at a number of production wells that were sampled monthly during a two-year CO2 injection pilot. In addition, a simplified reservoir simulation was performed. Results indicate that significant amounts of CO2 are stored in the oil phase thus reducing the amount of CO2 available as a buoyant free phase and hence increasing storage security.

Carbonate reservoirs store more than 50% of the earth hydrocarbon reserves with mostly mixed wettability. Water injection in these reservoirs likely results in low recovery due to uneven water movement. In the past years, it has been noticed that Low Salinity Water Flooding (LSWF) regularly led to incremental recovery. Some of the possible Enhanced Oil Recovery LSWF mechanisms on the relation of the injected fluid composition and orginal reservoir fluids.In this study the effects of altering the concentration of the injected Sulphate ions on pH, CO2, calcite dissolution and its impact on oil recovery in carbonates are investigated. Ca2+, Mg2+ and SO-4 2are determining ions to the carbonate surface which impact the surface charge of the rock (Zhang, 2006). The adsorption of the determining ions having conflicting charges Ca2+ and SO4 -2 on the carbonate rock surface is dependent on the relative concentration and equilibrium. An increase in pH causes a reaction with the acidic components of the oil which improves reservoir in-situ surfactants. This study describes LSWF five spots simulation model with 4 producers and one injector. A 3D homogeneous reservoir was built using CMG simulators specifically the compositional simulator GEM. The basic data used to build the model like PVT data, crude composition, injected and connate water geochemical compositions were collected from several case studies conducted in a carbonate reservoir. From the simulation results, pH was found to increase during the interaction between low salinity brine and reservoir rocks. The results show that dissolution of carbonate minerals can occur and this will alter the composition of the injected low salinity brine, the concentration of divalent ions on rock surface and hence the potential of low salinity to improve recovery. Calcite dissolution and indirectly Anhydrite Precipitation is being accelerated and controlled by the CO2 within the residual oil. The study indicates strong bond between pH and CO2 and their effect on oil recovery while preforming LSWF. Enhancements on the injected water composition on a LSWF project based on the recommended chemical reaction controlling factors will enhance the understating of the driving mechanism of the LSWF and improve the oil recovery.

Alkaline-Surfactant-Polymer (ASP) flooding, which is classified as chemical EOR (Enhanced Oil Recovery) technique, has a great potential to recover an additional 10-25% of the oil in place, as demonstrated during various field pilot tests. A typical ASP flooding comprises of three stages: main ASP slug, polymer post slug and finally a water slug. The surfactant reduces the interfacial-tension between the displacing fluid and oil, the alkaline reduces the surfactant adsorption and creates in-situ natural surfactant, and the polymer decreases the water to oil mobility ratio. However, the deposition of inorganic scales directly attributed to geochemical processes during ASP flooding can significantly impact the viability of ASP floods. ASP flooding has economic limitations due to the large volumes of chemicals injected. Therefore, technical and economical feasibility of ASP flooding depends on the effective use of the injected chemicals and slug formulation. The main purpose of this paper is to describe the automatic optimisation of ASP flooding designs using an optimization algorithm, in particular, PSO (Particle Swarm Optimization). The algorithm identifies the most efficient optimum ASP design for a given set of criteria, specifically minimizing the total chemical expense and the scaling risk, and maximizing the oil revenue and NPV (Net Present Value).

The Bunter Sandstone Formation in the UK Southern North Sea has the potential to become an important CO2 storage unit if carbon dioxide capture and storage becomes a widely deployed option for the mitigation of greenhouse gases. A detailed geological model of a region of the Bunter Sandstone consisting of four domed structural closures was created using existing seismic, well log and core data. Compositional simulation of CO2 injection was performed to estimate the storage capacity of domes within the system. The injection was constrained by both pressure and CO2 migration criteria, and the storage efficiencies of the domes (volume of stored CO2 divided by the pore volume of the dome) were calculated when injection ceased. A sensitivity study evaluated the effect of varying the total aquifer volume, reservoir heterogeneity and injection well location. A wide range of storage efficiency values were obtained across the different simulation cases, ranging from 4% (closed dome) to 33% (homogeneous model). Intra-reservoir heterogeneity, specifically in the form of continuous low permeability layers has an important effect on storage capacity in dome-like structures, because it increases the tendency for CO2 to migrate laterally from the storage complex via structural spill points.

When simulating foam floods, uncertainties exist in both the foam and reservoir parameters however the combination of these uncertainties are rarely incorporated in forecasting. Foam flooding is an effective enhanced oil recovery method that controls mobility, reduces gas relative permeability, delays gas breakthrough and helps improve sweep efficiency. Thus it is often used in highly heterogeneous reservoirs where significant subsurface uncertainties exist. Foam uncertainties exist as (a) foam stability is controlled by a number of factors such as critical water and surfactant concentrations, brine salinity, and oil saturation which are unknown in the subsurface spatially and (b) foam flood simulation requires the accurate description of multiple parameters used in the foam flood models which are unknown. This study quantifies and compares the impact of uncertainties associated with foam model parameters with the heterogeneity of a fractured carbonate reservoir, an analogue to the highly prolific Arab D formation. Foam model parameters are not known a-priori but can be tuned to experimental data, which ideally represent a range of foam regimes and reservoir conditions. Geological heterogeneities in fractured carbonate reservoirs are complex and include, matrix wettability, fracture density/orientation and initial saturation distribution. To quantify uncertainties geological uncertainties in fractured carbonate reservoirs, an automated framework was used to history match the production response of a fractured carbonate field by varying geological parameters. This accounts for the geological uncertainties during a waterflood, which are then combined with foam uncertainties from experimental analysis in the optimisation step, by optimising the mean response of the model to foam flooding across a range of geological and foam scenarios. Our workflow used a combination of Particle Swarm Optimisation for history matching and manual optimisation, the final results of which show a wide range of possible impacts of foam flooding from different but equally well matched reservoirs. The novelty of our work is that it demonstrates how parameters that control foam stability and hence effectiveness in mobility control are related to both foam properties and geological uncertainty. Carrying these uncertainties into foam model properties from core to field scale will translate into considerably more robust estimates of uncertainty when predicting field-scale recovery compared to simulations that only consider uncertainty in the reservoir model.

Vapor/liquid-equilibria (VLE) calculations, particularly involving the phase behavior of carbon dioxide (CO) and hydrogen sulfide (HS), are used in scale-prediction modeling. In this work, the impact of VLE calculations for CO- and HS-rich gas phases and for acid- and sour-gas mixtures on scale-prediction calculations is evaluated. Three equations of state (EOSs) - Soave-Redlich-Kwong (SRK) (Soave 1972), Peng-Robinson (PR) (Peng and Robinson 1976), and Valderrama-Patel-Teja (VPT) (Valderrama 1990)- are implemented in the Heriot-Watt model and used in VLE calculations. The solubility of single-component CO and HS in water and the solubility of a gas mixture in water were compared with experimental data in terms of the absolute relative deviation (ARD). The solubility data were then used in PHREEQC (USGS 2016) to calculate the impact of using different EOSs on carbonate and sulfide scales, particularly on calcium carbonate (CaCO) and iron sulfide (FeS). Average ARDs of 6.04, 4.10, and 3.77% between experimental and calculated values for CO solubility in water were obtained for the SRK, PR, and VPT EOSs, respectively. Similarly, for HS solubility in water, average ARDs of 6.49, 6.66, and 6.48% were obtained for each EOS, respectively. For the solubility of sourand acid-gas mixtures in water, average ARDs of 13.92, 13.25, and 10.78% were obtained, respectively. It has thus been concluded that the VPT EOS performs better than the SRK and PR EOSs in VLE calculations for the analyzed data. The errors introduced in VLE calculations have been found to impact the calculation of the amount of CaCO precipitated, with consequences for scale-inhibitor selection. Higher deviations were found in the amount of CaCO precipitation for gas mixtures when compared with a single-component, CO-rich phase. Furthermore, the large errors occurring in VLE calculations for HS solubility have not been found to impact the calculation of the amount of FeS precipitated when HS is in excess with respect to Fe. In addition to this, a case study that was performed by use of formation-water data from the Brazilian presalt revealed that the choice of EOS can cause errors of 6 kg of precipitate during each day of production. Scale-prediction calculations carried out with PHREEQC demonstrate that VLE calculations can have a high impact on mineral precipitation. Thus, it is recommended that the best VLE model available should always be used for scale-prediction modeling, particularly when mixtures of gases are present.

Carbonate reservoirs are more geochemically reactive than sandstones and can experience big changes in porosity and permeability because of mineral reactions. In this work, we analysed the calcite dissolution and precipitation in chalk reservoirs during injection of seawater and CO2 bearing fluids. We performed reactive transport simulations with injection of seawater, carbonated water, CO2 gas, CO2 SWAG and CO2 WAG. We evaluated the mineral reactions that occur in the injector and producer blocks. Moreover, the calcite dissolution rate was calculated and its relationship with flow rate was investigated. Simulation results showed that during injection of CO2 gas alone, calcite dissolution was fast but limited, and occurred everywhere. On the other hand, for the other injected fluids the dissolution around the injector was continuous and, with the exception of the seawater scenario, precipitation was observed downstream. In addition, the calcite dissolution per injected water pore volumes for both CO2 SWAG and CO2 WAG was higher because of higher dissolution of gaseous CO2 in injected and formation waters. Moreover, the dissolution rate was found to be proportional to the water flow rate which confirms the assumption that calcite kinetics are fast compared to reservoir flow. This knowledge is valuable when planning CO2 WAG projects in carbonate reservoirs. As dissolution rates increase with flow rates, high permeability zones will show faster porosity changes, which may compromise the injector wellbore integrity and may lead to a more severe and growing calcite scaling risk around the producer wellbore.

The most common method for preventing downhole oilfield scale formation is by applying a scale inhibitor squeeze treatment. In this process, a scale inhibitor solution is injected down a producer well into the near wellbore formation. Commonly, these scale inhibitor treatments are injected as aqueous solutions. However, there are certain situations where an aqueous based treatment is not desirable, such as where relative permeability effects, water blocking, fluid lifting, chemical penetration or hydrate formation are of major concern. This two-phase flow multi-component, multi-layer, radial near-wellbore simulator is capable of modelling both aqueous and non-aqueous squeeze treatments. It considers the immiscible displacement of non-aqueous and aqueous phases, along with chemical component transport in both phases and mass transfer between both phases, and it is capable of modelling kinetic and equilibrium adsorption and desorption. It has been developed to study and optimise non-aqueous squeeze treatments. Of particular interest is the relationship between scale inhibitor chemical solubility in the carrier and in situ phases, and the choice of phase for the overflush fluid. The relationship can have a very pronounced impact on inhibitor penetration and squeeze lifetimes. Finally, the simulator was used to simulate a series of polymer non-aqueous scale inhibitor squeeze treatments deployed in the Heidrun field in the Norwegian sector of the North Sea. The simulation study consisted in matching the well water cut for the time of the treatments, followed by the derivation of a pseudo-adsorption isotherm, which is used to describe the SI retention in the formation. The initial pseudo-adsorption isotherm, derived from the first field treatment return concentration profile, resulted in very good matches for the other two consecutive treatments.

Long-term containment of CO2 and storage security depends mainly on physical and geochemical trapping mechanisms. Injected CO2 dissolves in the formation fluid and causes a sharp decrease in pH which in turn drives the dissolution and precipitation of minerals. Geochemical modelling is an important tool to understand and predict the behaviour of CO2 reactivity. In this paper three numerical codes, PHREEQC, GEM and TOUGHREACT, are compared with respect to brine – CO2 – rock reactions. Formation water compositions and mineralogies of three sandstone core samples from target CO2-storage formations were used as input for kinetic models. Mineral replacement reactions were observed when CO2 injection was initiated in all scenarios. While PHREEQC and GEM were generally in good agreement, TOUGHREACT gave diverging predictions on two models. It is considered that the discrepancies are caused primarily by the differences in the thermodynamic databases and activity models. The uncertainties in these calculations suggest that appropriate experimental tests should be performed to validate the models, so that they can be used to make predictions at the field scale.

Commingled injection of seawater with produced water is an option for offshore fields submitted to waterflooding. It resolves the problems of produced water disposal and of the reservoir pressure maintenance. The presence of barium (strontium) in the formation water and consequent sulphate scaling with seawater flooding is a wide spread phenomenon. In this case, the produced water also contains some barium, which results in sulphate scaling in injection well during commingled injection with seawater. One of the ways around to avoid injectivity damage during the commingled injection of incompatible waters is using a sulphate reduction plant. Being mounted on sea platform, the plant significantly reduces sulphate concentration in seawater and allows using it for commingled produced water re-injection (PWRI). Low sulphate seawater injection together with PWRI causes low injectivity decline and makes it feasible to apply in offshore waterflood projects. Planning and design of commingled PWRI with low sulphate seawater injection includes choice of the ratio “produced water:seawater”, determination of maximum allowed sulphate concentration in seawater after treatment, and injectivity decline prediction. The reliable design and plan is based on mathematical modelling with well-known model coefficients. In the current paper we derive an analytical model for the co-injection of low sulphate seawater with barium-containing produced water. Reagent and deposit concentrations along with the injectivity index are expressed by explicit formulae. It was found out that bulk sulphate deposition occurs in the 10–20 well radius neighbourhood. The injectivity decline is one order of magnitude higher than the productivity decline under similar reservoir conditions. Calculations for sulphate reduction plant have been performed for six fields of Campos Basin (Brazil).

The fate of carbon dioxide (CO2) injected into a deep saline aquifer depends largely on the geological structure within the aquifer. For example, low permeability layers, such as shales or mudstones, will act as barriers to vertical flow of CO2 gas, whereas high permeability channels may assist the lateral migration of CO2. It is therefore important to include permeability heterogeneity in models for numerical flow simulation As an example of a heterogeneous system, a model of fluvial-incised valley deposits was used. Flow simulations were performed using the generalized equation-of-state model—greenhouse gas software package from Computer Modelling Group, which is a compositional simulator, specially adapted for CO2 storage. The impacts of residual gas and water saturations, gas diffusion in the aqueous phase, hysteresis, and permeability anisotropy on the distribution of CO2 between the gaseous and aqueous phases were examined. Gas diffusion in the aqueous phase was found to significantly enhance solubility trapping of CO2, even when hysteretic trapping of CO2 as a residual phase is taken into account.

The injection of seawater into oil-bearing reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales to the injection and production wells during such operations has been much studied. The current deep water subsea developments offshore West Africa and Brazil have brought into sharp focus the need to manage scale in an effective way. To this end, the challenge of scale control during the lifecycle of water injection, production and onto produced water reinjection has been reviewed for a number of fields by the authors. This outlines the risk assessment process that should be undertaken to select the most economical and effective scale control methodology (which for sulfate-based scale could be seawater injection with scale inhibitor squeeze treatments to maintain production, or sulfate reduction of the injection water - with or without the need to scale inhibitor squeeze). In the case of sulfate reduction, parameters to be investigated include the degree of desulfation required to minimise the scale risk of downhole scale formation, the impact that the degree of fluid mixing will have on the resulting brine (from injection to production) and the impact that the desulfated brine will have on scale control during produced water reinjection. The paper draws upon a wide range of technical inputs to make scale management decisions including: computer modelling techniques (e.g., deposition models that incorporate the kinetics of sulfate scale formation at low supersaturation ratios); reservoir simulation of fluid mixing and reaction; the resulting produced brine chemistry; laboratory generated coreflood data to assess chemical selection for scale inhibitor squeeze and produced water application; and field results that will demonstrate the impact of the type of injection water source on the long term manageability of such deepwater projects. Finally, the paper outlines in detail the particular issues associated with the full economic assessment of low-sulfate water injection versus full sulfate seawater injection.