Seawater Injection Research Articles

When nitrate treatment wins the battle against microbial reservoir souring but loses the war

The injection of seawater into a hydrocarbon reservoir (seawater flooding), as an oil recovery method, triggers microbial reservoir souring, through which microorganisms consume sulfate ions and produce hydrogen sulfide, which is hazardous, corrosive, and detrimental to the environment if enters production wells. A strategy to mitigate this problem is to add nitrate or nitrite to the injection seawater, also known as nitrate or nitrite treatment. This study investigates nitrate treatment in a simulated real-world sector scale hydrocarbon reservoir in the Danish North Sea through a non-isothermal multi-phase multi-component bio-chemical model and field observations. The common expectation is that the higher the concentration of nitrate or nitrite in the injection seawater the less hydrogen sulfide production. However, the results of this study show that slowing down the microorganisms (or mitigation through nitrate treatment) may cause higher hydrogen sulfide production from production wells. Put differently, not only the total amount of hydrogen sulfide generated inside the reservoir matters, but also the location of the generation zone and its distance from production wells matter. Therefore, it is possible that insufficient amounts of nitrate cause the generation zone to move toward the production wells. Hence, more hydrogen sulfide is produced during the lifetime of the reservoir. Moreover, considering laboratory and field scale measurements, in the presence of coupled multi-physics processes, the growth rates at the field scale are significantly lower than those observed in the laboratory experiments, under in-situ conditions, utilizing actual reservoir fluid samples.

The study of the effect of flooding process in Neft Dashlary field on parameters of aggressive medium

The paper reviews the damage effect of aggressive medium occurring as a result of sea water injection for the maintenance of reservoir pressure and production in Neft Dashlary field, which is in a long-term development, as well as the treatment of bottomhole zone with various agents, biological contamination and hydrogen sulphide (H2S) arising due to the bacterial activity on the works towards the consolidation of well bottomhole zone. Depending on the contact degree of cement stone with aggressive medium its corrosion probability is defined. Corrosion activity increases fast when well product contains small amount of H2S gas. According to the gas law, the gas solubility in fluids including in water is in direct proportion to the pressure. Small amount of H2S gas in produced water has a great effect on corrosion activity. On the basis of the studies of rock-operation data, it was specified that the degree of the consolidation of well bottomhole zone carried out in the well of IX horizons and Low Kirmaki suite is inversely proportional to the amount of H2S. Thus, in the zones with great amount of H2S, the efficiency degree is low, and in the zones with small amount – high. These zones and the efficiency degree are reflected in the current maps of development of IX horizon and Low Kirmaki suite of the field.

Re-Injection of Formation Water and Sea Water to Increase Oil Recovery from Sandstone Rocks: A Laboratory Experiment Under Room Conditions

Laboratory tests and field applications show that low-salinity water flooding could lead to significant reduction of residual oil saturation. There has been a growing interest with increasing number of low-salinity water flooding studies. However, there are few quantitative studies on the effect of using sea-water injections on oil recovery. As oil production continues, a drop-in reservoir pressure will occur due to the loss of reservoir fluids, and this drop-in pressure will lead to a decrease in oil production. The reservoir pressure is maintained by the water injection process. Where sea-water is injected into the aquifer area below the oil area to support the tank pressure. This study presents a laboratory investigation of the effect of salinity injection water on oil recovery, permeability, and relative permeability in the water flooding process. This study was conducted using several samples of sandstone saturated with oil by placing them in the reservoir conditions by placing them in a vacuum oven to ensure complete saturation of the samples with oil and then extracting the oil from them using liquid permeability where the samples are injected. With the formation water until reaching the recovery plateau and obtaining an average reading, the flow, permeability and pressure difference are measured, as well as the relative permeability and recovery factor, then the samples are injected again with sea water and the new results are recorded through seawater injection. The results of this study showed an increase in oil recovery with decrease in residual oil saturation and increase in the recovery factor.

The interplay between microbial reservoir souring and barite scale formation in hydrocarbon reservoirs

The injection of seawater into a hydrocarbon reservoir (seawater flooding) as a secondary or tertiary oil recovery method is associated with two possibly significant challenges. First, the formation and deposition of various types of scale may happen due to incompatibility between the injection seawater and formation brine. Especially, the addition of sulfate ions may trigger the formation of various types of sulfate scales (e.g., barium sulfate, strontium sulfate, and calcium sulfate). Second, microbial reservoir souring may happen due to the activation of Sulfate Reducing Bacteria (SRBs), which reduce sulfate ions to hydrogen sulfide. This is mainly a result of a drop in temperature in the reservoir, the addition of sulfate from the seawater to the reservoir, and the presence of Dissolved Organic Carbon (DOC) coming from reservoir hydrocarbon. Since both these processes include the consumption of sulfate ions, a competition is expected to happen between them. Especially, there is a concern about whether an efficient mitigation strategy for souring (e.g., nitrate treatment) will result in less consumption of sulfate ions and in turn more formation of sulfate scales. This study tests this theory and investigates the effect of souring intensity and mitigation on the severity of barite scale formation inside the reservoir. In this study, a non-isothermal multi-component bio-chemical model to simultaneously simulate both the processes is developed. Several simulation cases in one and two dimensions are investigated in different conditions in order to study the effect of three influential parameters, namely sulfate ion concentration in the injection sweater, the DOC content of the reservoir hydrocarbon, and injection flow rate on barite scale formation, microbial reservoir souring, nitrate treatment, and the interplay among them. The results show that the effect of barite scale formation on reservoir souring is small (a maximum of 4 percent reduction in the total generated hydrogen sulfide) whereas reservoir souring and nitrate treatment significantly influence barite formation. Depending on the case, the presence of souring can cause a complete removal of barite scale especially around the production well (positive effect) or a maximum of 8 times increase in barite scale amount around the production well (negative effect). Moreover, in all cases, with a more efficient nitrate treatment, although less hydrogen sulfide is generated inside the reservoir (up to a full removal of souring), the generation zone moves closer to the production well. Therefore, an insufficient nitrate treatment may cause an earlier hydrogen sulfide production from the production well (up to twice as early). Several other trends observed in the set of results are also presented in this paper.

Removal of High-Concentration Sulfate from Seawater by Ettringite Precipitation

Due to the worldwide scarcity of fresh water, seawater becomes an alternative base fluid in hydraulic fracturing for oil and gas production. However, the injection of seawater that contains high concentration of sulfate will induce the scale formation and thus reduce hydrocarbon production. One of the most effective ways to solve this problem is to remove sulfate ions from seawater before fracturing application. The objective of this study is to develop an effective and environment-friendly approach to remove sulfate ions from seawater based on coprecipitation of SO42− with NaAlO2 and CaO as ettringite (Ca6Al2(SO4)3(OH)12·26H2O). Residual sulfate concentration in treated seawater was determined when NaAlO2 and CaO dosed at different molar ratios to sulfate. Results showed the efficiency of sulfate removal was more than 90% (4290 ppm to ∼400 ppm) when Al : Ca : S = 2 : 6 : 1. It was found the sulfate precipitation completed in 15 mins with stirring under an alkaline condition (pH ≈ 12) and was not affected by temperature (15°C to 45°C). Increasing the Na+ concentration from 0 to 25,000 ppm in waters resulted in the increment of residual sulfate concentration from 250 to ∼600 ppm, decreasing the removal efficiency. Besides, the analysis of Ca2+ and Mg2+ in treated seawater showed the Ca2+ concentrations were on the similar level as that before the treatment and Mg2+ was removed in the precipitation process, which is beneficial to the application of the treated seawater. The morphology and element analysis of the collected precipitates showed that the ettringites were in a layered shape with composition between Ca6Al2(SO4)3(OH)12 and Ca4Al2(SO4)(OH)12 at the optimized chemical dosage; therefore, the developed ettringite precipitation method could effectively remove sulfate from seawater without toxic chemicals involved, which benefits seawater hydraulic fracturing in an economic way, and this contributes to water sustainability.

Improved Oil Recovery from Carbonate Reservoirs by Tuning Injection Seawater Composition

In order to improve the adaptability of low-salinity waterflooding technology in some areas where freshwater resources are scarce, we aimed at implementing the low-salinity effect (LSE) in carbonate reservoirs through tuning injection seawater composition. LSE of ion tuning water (ITW) was verified by the results of core flooding tests, obtaining a water-free recovery factor of 50.7% and cumulative oil recovery of 77.2%. The micro mechanisms behind it were revealed via direct force-measuring and Zeta parameter (Zetap) measuring. Our results are expected to provide a new LSW strategy via tuning injection seawater composition in the case of carbonate reservoirs.

Genesis of the Danping bauxite deposit in northern Guizhou, Southwest China: Constraints from in-situ elemental and sulfur isotope analyses in pyrite

The super large bauxite deposit known as the Danping deposit is hosted in the Dazhuyuan formation, Lower Permian, and is located in northern Guizhou (Southwest China). The geochemical signatures of five generations of pyrite from Danping have been identified, and their genesis has been constrained by analyzing their geochemical signatures. Oolitic pyrite (Py-O), which has two sub-generations, occurs in the upper part of the oolitic bauxite. Typically, Py-O2 has a core and rim structure, where the core may contain altered primary Py-O1. While Py-M appears as occurs in the form of interstitial material in the lower part of the oolitic bauxite, Py-C is cubic in shape and is reported in the earthy bauxite. Moreover, Py-Q is found in the Qixia formation. Py-M has a Co/Ni ratio of ∼ 1 and a δ34SV-CDT value of ∼ 0 ‰, thus suggesting a magmatic hydrothermal origin. The primary Py-O1 has a uniform geochemical composition. The reformed Py-O1 and the core of Py-O2 have considerably lower δ34S values of −19.15 ‰ to −4.72 ‰, indicating that a brief pulse of seawater injection can result in the replacement of Py-O1 and the formation of Py-O2. Py-M, Py-O and Py-Q all have positive Ce anomalies, while Py-C has negative Ce anomalies. These contrasting characteristics demonstrate that the original aluminous rock series was largely deposited in an oxidic environment, while the earthy bauxite was formed in a reducing environment. Lithium, Sc and Ga are positively correlated with one another, reflecting their similar geochemical behavior during sedimentary–weathering processes. Py-M has higher contents of Li, Sc and Ga, implying that magmatic fluids contributed to the presence of critical metals even in the weathering conditions.

The Effect of Blending Polymeric and Phosphonate Scale Inhibitors on Fluid/Fluid and Rock/Fluid Interactions: A Comprehensive Experimental and Theoretical Study

Summary Using seawater or engineered water to inject into oil formations can cause inorganic scaling, such as calcium sulfate, barium sulfate, and strontium sulfate. These scales may clog pore throats and limit production. Scale inhibitor (SI) squeeze treatment reduces inorganic scaling and improves oil recovery. Chemical compounds called SIs suppress or delay mineral scaling. SIs fall into two categories, each with its own mechanism. Most polymeric inhibitors impede nucleation, whereas phosphonate SIs deform crystal formation. The oil and gas industry now uses a fixed mixture of these inhibitors to maximize all inhibition mechanisms. However, the impact of blended SIs on fluid/fluid and rock/fluid interactions has not been addressed. This study aims to evaluate the efficiency of blended SIs when dealing with three well-known mineral scales all together. In this study, first, the process of mineral scale formation was simulated using PHREEQC (pH-REdox-EQuilibrium), and the impact of temperature and mixing ratios was investigated. Then, by choosing a proper temperature and mixing ratio, the effect of polymeric and phosphonate SIs blending on barium, calcium, and strontium sulfate inhibition is examined. Additionally, fluid/fluid interactions and rock/fluid interactions were studied via interfacial tension and contact angle measurements. The influence of seawater mixing ratio on calcium, strontium, and barium sulfate saturation indices is medium, low, and very low, respectively, but the effect on the amount of scale precipitation is very high, high, and low for the scales indicated. This adds to the fact that barium takes precedence in scale formation, and its presence may affect the other two scales, but calcium ions have barely any effect on barite formation. Moreover, the results show a positive synergistic effect of SIs blend on sulfate scale mitigation. However, this positive figure completely depends on the concentration of phosphonate SI for calcium and strontium sulfate, while the positive synergy exists at all concentrations of phosphonate SIs for barium sulfate. Moreover, SIs could lower the water/oil/rock contact angle by 10° on average and make it more water wet. Same enhanced results have been achieved for interfacial tension by adding SIs, reducing by 8 dynes/cm on average. It is worth noting that the interfacial tension and contact angle measurements are unaffected by the synergistic action of SIs mixing. The results of coreflooding experiments substantiate the effectiveness of SIs and show 8 and 45% permeability reduction for injection of seawater with and without SIs on two different core samples, respectively. For the first time in a sulfate scaling system, this work investigates the copresence of barite, celestite, and anhydrite against a wide range of blending SI concentrations. Based on the results, it is derived that the presence of all three sulfate scales undoubtedly affect the quantity of each scale’s precipitation and the efficacy of SIs.

Experimental study of secondary and tertiary modes combined low salinity water and polymer flooding in sandstone porous media

AbstractCombined low salinity water (LSW) and polymer (LSP) flooding is the most attractive method of enhanced oil recovery (EOR). Considerable research has investigated effective mechanisms of LSP flooding. In this study, 10 laboratory core flood tests were carried out to evaluate the effects of LSW injection into samples without any clay particles, the timing of LSW injection, and the advantages of adding polymer to the injection water for EOR. Secondary and tertiary LSW injections were performed on sandpack samples with different wettability states and water salinity. Tertiary LSW injection after secondary synthetic seawater (SSW) injection in oil‐wet samples resulted in 13% more oil recovery, while the water‐wet sample showed no effect on the oil recovery. Secondary LSW injection in oil‐wet porous media improved oil recovery by 8% of the original oil in place (OOIP) more than secondary SSW injection. Tertiary LSP flooding after secondary SSW injection in the oil‐wet sample provided a recovery of 67.3% of OOIP, while secondary LSW injection followed by tertiary LSP flooding yielded the maximum ultimate oil recovery of about 77% of OOIP. The findings showed that the positive EOR effects of LSW and LSP flooding were the results of wettability alteration, pH increase, improved mobility ratio, better sweep efficiency, and oil redistribution. In addition, results showed that wettability alteration is possible without the presence of clay particles. The findings of this study can help for a better understanding of fluid propagation through the porous media and an investigation of delays in reaching ultimate oil recovery.

Geochemical investigation of electrical conductivity and electrical double layer based wettability alteration during engineered water injection in carbonates

The injection of engineered water to increase the oil recovery from carbonates is increasingly becoming popular due to its reduced environmental impact and low cost of operation. However, the related variation in electric properties of rock and fluid with this technique is still ambiguous and needs thorough investigation. This study explores the variation in electrical conductivity, ion mobility, electrical double layer thickness, and the related oil recovery with the change in water composition from a geochemical perspective. In this study, we implemented an improved wettability alteration model based on the variation in electrical conductivity with a Matlab-IPhreeqc coupled simulator, to model the electrical conductivity, ion mobility, and electrical double layer (EDL) thickness. The variation in concentration of the ionic species obtained from the geochemical model is used to determine the electrical conductivity. This electrical conductivity-based wettability modification is dynamically simulated in the transport model. The model is validated with experimental coreflood data conducted on carbonates by simulating the electrical conductivity measurements reported in the literature. From the findings, it is evident that the formation temperature, sulfate concentration, and dilution of injected seawater has a noticeable effect on electrical conductivity during engineered water injection. It is important to mention that the EDL thickness is the main parameter affected by the change in electrical conductivity. In consequence, it is suggested to inject high-temperature water in carbonate reservoirs because it will increase ion mobility. This increase in ion mobility will enhance the EDL thickness and water film will become stabilized. Moreover, seawater dilution decreases electrical conductivity while spiking of sulfate concentration increases the activity of sulfate ions. However, the concentration of sulfate ions must be controlled as a wettability alteration agent, as it can cause the formation and precipitation of calcium sulfate. Furthermore, the variation in electrical conductivity and EDL thickness caused by the injection of seawater and diluted seawater increased the recovery of oil by approximately 16–21% in the selected case study.

Investigation of Surface Charge at the Mineral/Brine Interface: Implications for Wettability Alteration

The reservoir rock ismade up of differentminerals which contribute to the overall formation wettability. These minerals in their natural state differ in chemistry and structure, and thus behave differently in an environment of varying composition and salinity. These have direct implications for enhanced oil recovery due to water flooding, or wettability alteration due to long-term exposure to brine. With the reservoir rock being a complex system of multiple minerals, the control of wettability alterations becomes difficult to manage. One of the dominant mechanisms responsible for wettability alteration is the mineral surface charge, which is dependent on pH, and fluid composition (salt type and salinity). For the first time, the surface charge development of barite, dolomite, and feldspar minerals in their native reservoir environments (accounting for the formation brine complexity) is presented. Also, the effect of oilfield operations (induced pH change) on minerals’ surface charge development is studied. This was achieved by using the zeta potential measurements. The zeta potential results show that barite and dolomite minerals possess positively charge surfaces in formation water and seawater, with feldspar having a near-zero surface charge. Furthermore, the surface charge development is controlled by the H+/OH− (pH), electrical double-layer effect, as well as ion adsorption on the mineral’s surfaces. These findings provide key insights into the role of fluid environment (pH, composition) and oilfield operations on mineral surface charge development. In addition, the results show that careful tuning of pH with seawater injection could serve as an operational strategy to control the mineral surface charge. This is important as negatively charged surfaces negate wettability alteration due to polar crude oil components. Also, the design of an ion-engineered fluid to control the surface charge of minerals was implemented, and the results show that reduction in the Ca2+ concentration holds the key to the surface charge modifications. Surface charge modifications as evidenced in this study play a critical role in the control of wettability alteration to enhance production.

Xigaze ophiolite (South Tibet) records complex melt-fluid-peridotite interaction in the crust-mantle transition zone beneath oceanic slow-ultraslow spreading centers

The formation and evolution of the crust-mantle transition zone (CMTZ) under oceanic slow-ultraslow spreading centers, compared with the well-documented examples that developed under fast spreading centers, remain largely unknown due to the lack of suitable targets. In this study, we systematically examine the CMTZ of the Xigaze ophiolite in the Yarlung Zangbo suture zone (south Tibet). This ophiolite represents a rare lithospheric fragment produced in oceanic slow-ultraslow spreading settings. We conduct detailed field mapping and petrological as well as geochemical studies on the CMTZ in the Dazhuka massif, the easternmost segment of the Xigaze ophiolite. Our aim is to characterize the lithological architecture and associated melt-fluid-peridotite interaction history of the CMTZ. The CMTZ (~1800 m thick) in the Dazhuka ophiolite consists of 4 subzones with complex lithological associations. They range successively from clinopyroxene-rich harzburgite with weak metasomatism and without amphibole in Zone 1 (the bottom) to clinopyroxene-poor harzburgite with strong melt impregnation and more amphibole in Zone 3 (the upper part, with Zone 2 transitional harzburgite in between), all cut by a wealth of dyke rocks (gabbro, dolerite and dunite). The Al2O3 contents decrease consistently in whole-rock (2.97–0.57 wt%), orthopyroxene (4.99–0.85 wt%) and clinopyroxene (5.25–1.22 wt%) for the harzburgites from Zones 1–3, contrary to the trends for the spinel Cr# (0.17–0.65) and clinopyroxene Li/Y, and bulk rare earth element (REE), Pb and Sr contents. The plagioclase-bearing peridotite (commonly enclosed in layered gabbro) in Zone 4 (the top) has remarkably elevated TiO2 contents (0.12–0.34 wt%) and Cr# values (0.45–0.53) in spinel, suggesting equilibration and strongest interaction with MORB-like melts among the CMTZ. The troctolite in Zone 4 has olivine Mg# (80.6–84.2) and NiO (0.37–0.45 wt%) and spinel Cr# (0.68–0.73). The fluid-mobile elements (U, Pb, Sr and Li) in both whole rock and clinopyroxene as well as amphibole abundances increase consistently from Zones 1–4, implying that the interaction of the mantle rocks with hydrothermal fluids became increasingly intensive from bottom to top of the CMTZ.These vertical variations collectively suggest the complex melt-fluid-peridotite interaction during the upward movement of deeply sourced melts and the downward penetration of seawater. We propose that such interactions are ultimately controlled by the relative slow spreading rates, where the less melt supply and very thin or even missing oceanic crust facilitate the downward seawater injection and enhance pervasive fluid metasomatism. This may represent a suitable explanation for the CMTZ with intriguing lithological and chemical heterogeneity under many other active or fossil oceanic slow-ultraslow spreading environments.

An Electrokinetic Study of Amino Acid and Potential-Determining Ions for Enhanced Waterflooding in Carbonate Reservoirs

Summary Reservoir rock wettability plays an important role in waterflooding especially in fractured carbonate reservoirs because oil recovery tends to be inefficient from the mixed-wet or oil-wet rock matrix. Improved oil recovery has been observed by adjusting the concentrations of potential-determining ions (PDIs) to alter the wettability of carbonate rocks. Our previous study showed that the oil recovery from carbonate reservoirs by waterflooding can be enhanced by the addition of glycine, the simplest amino acid. The interaction of glycine anion and oil-wet carbonate surfaces was confirmed in contact angle measurements and yielded the incremental oil recovery in imbibition experiments. This paper presents a surface complexation model (SCM) for the interaction between glycine and oil-wet carbonate surfaces that considers the impact of temperature, pH, salinity, and the concentrations of PDIs. The proposed SCM was tuned based on the zeta potential (ZP) data reported for synthetic calcite in glycine solutions. The tuned model predicts that the strong affinity of glycine for the oil-wet carbonate surface causes the carboxylic acids to desorb from the surface. The concentration of adsorbed carboxylic acids was in qualitative agreement with the water-wetting state of carbonate rocks inferred from the reported contact angle and spontaneous imbibition experiments. Moreover, the model indicates that glycine’s performance as a wettability alteration agent improves significantly at high temperatures. It also suggests that enhanced oil recovery (EOR) by formation brine (FB) with 1 to 3 wt% glycine at high temperatures should be similar to the injection of low-salinity seawater (LSW). The proposed SCM supports glycine’s potential to change the wettability of oil-wet carbonates at high salinity, high hardness, and high temperature.

Effects of the Reservoir Environment and Oilfield Operations on the Iron Mineral Surface Charge Development: An Insight into Their Role in Wettability Alteration

Iron minerals are hydrophobic minerals predominately found in sandstone formations with their role in wettability alteration not fully understood. With the reservoir rock being a complex system of multiple minerals, the control of wettability alterations becomes difficult to manage due to the different surface chemistry of constituent minerals. This study presents for the first time the surface charge development of pyrite, magnetite, and hematite minerals in native reservoir environments and the effect of oilfield operations such as acidizing, water injection, polymerization, surfactant flooding, and alkaline flooding on iron minerals, surface charge development. This was achieved using zeta potential measurement, which depicts the type of surface charge and infers the propensity of precipitation. The experimental results show that pyrite, magnetite, and hematite behave similarly under reservoir conditions with all the minerals being positively charged although pyrite and hematite are negatively charged in seawater (SW). Results also show that the surface charge development is controlled by the electrical double-layer effect and ion adsorption on the mineral surfaces. These findings provide key insights into the role of iron minerals in wettability alteration as they provide surfaces that serve as a precursor for polar crude component adsorption. Also, the design of an ion-engineered fluid to control the surface charge of iron minerals was implemented, and the results showed that they behave differently. Furthermore, the effect of low-salinity water on the mineral surface charge was examined. The findings revealed that low-salinity water can produce a negatively charged surface, however, cannot mitigate the iron mineral precipitation challenge as the observed zeta potential values are near zero. Finally, slug and continuous injection of the ethylenediaminetetraacetic acid chelating agent was implemented as an iron mineral precipitation control strategy, with the continuous injection observed to significantly improve the colloidal stability of the iron minerals in the reservoir native state and after SW injection.

Time-Lapse CSEM Monitoring: Correlating the Anomalous Transverse Resistance with SoPhiH Maps

The CSEM method, which is frequently used as a risk-reduction tool in hydrocarbon exploration, is finally moving to a new frontier: reservoir monitoring and surveillance. In the present work, we present a CSEM time-lapse interpretation workflow. One essential aspect of our workflow is the demonstration of the linear relationship between the anomalous transverse resistance, an attribute extracted from CSEM data inversion, and the SoPhiH attribute, which is estimated from fluid-flow simulators. Consequently, it is possible to reliably estimate SoPhiH maps from CSEM time-lapse surveys using such a relationship. We demonstrate our workflow’s effectiveness in the mature Marlim oilfield by simulating the CSEM time-lapse response after 30 and 40 years of seawater injection and detecting the remaining sweet spots in the reservoir. The Marlim reservoirs are analogous to several turbidite reservoirs worldwide, which can also be appraised with the proposed workflow. The prediction of SoPhiH maps by using CSEM data inversion can significantly improve reservoir time-lapse characterization.

Experimental Study of Natural Ions and Rock Interactions for Seawater Breakthrough Percentage Monitoring during Offshore Seawater Flooding

Summary Seawater breakthrough percentage monitoring is critical for offshore oil reservoirs because seawater fraction is an important parameter for estimating the severity of many flow assurance issues caused by seawater injection and further developing effective strategies to mitigate the impact of those issues on production. The validation of using natural ions as a tracer to calculate the seawater fraction was investigated systematically by studying the natural chemical composition evolution in porous media using coreflood tests and static bottle tests. The applicable range of ions was discussed based on the interaction between ion and rock. The barium sulfate reactive model was improved by integrating interaction between ions and rock as well as fluid flow effect. The results indicate that chloride and sodium interact with rock, but the influence of the interaction can be minimized to a negligible level because of the high concentrations of chloride and sodium. Thus, chloride and sodium can be used as conservative tracers during the seawater flooding process. However, adsorption/desorption may have a large influence on chloride and sodium concentrations under the scenario that both injection water and formation water have low chloride and sodium content. Bromide shows negligible interaction with rock even at low concentrations and can be regarded as being conservative. The application of a barium and sulfate reaction model in coreflood tests does not work as well as in bottle tests because fluid flow in porous media and ion interaction with rock is not taken into account. Although sulfate and barium adsorption on clay is small, it should not be neglected. The barium sulfate reaction model was improved based on the simulation of ion transport in porous media. Cations (magnesium, calcium, and potassium) are involved in the complicated cation-exchange process, which causes large deviation. Therefore, magnesium, calcium, and potassium are not recommended to calculate seawater fraction. Boron, which exists as anions in formation water and is used as a conservative tracer, has significant interactions with core matrix, and using boron in an ion tracking method directly can significantly underestimate the seawater fraction. The results give guidelines on selecting suitable ions as tracers to determine seawater breakthrough percentages under different production scenarios.

Sulfidogenic Microbial Communities of the Uzen High-Temperature Oil Field in Kazakhstan.

Application of seawater for secondary oil recovery stimulates the development of sulfidogenic bacteria in the oil field leading to microbially influenced corrosion of steel equipment, oil souring, and environmental issues. The aim of this work was to investigate potential sulfide producers in the high-temperature Uzen oil field (Republic of Kazakhstan) exploited with seawater flooding and the possibility of suppressing growth of sulfidogens in both planktonic and biofilm forms. Approaches used in the study included 16S rRNA and dsrAB gene sequencing, scanning electron microscopy, and culture-based techniques. Thermophilic hydrogenotrophic methanogens of the genus Methanothermococcus (phylum Euryarchaeota) predominated in water from the zone not affected by seawater flooding. Methanogens were accompanied by fermentative bacteria of the genera Thermovirga, Defliviitoga, Geotoga, and Thermosipho (phylum Thermotogae), which are potential thiosulfate- or/and sulfur-reducers. In the sulfate- and sulfide-rich formation water, the share of Desulfonauticus sulfate-reducing bacteria (SRB) increased. Thermodesulforhabdus, Thermodesulfobacterium, Desulfotomaculum, Desulfovibrio, and Desulfoglaeba were also detected. Mesophilic denitrifying bacteria of the genera Marinobacter, Halomonas, and Pelobacter inhabited the near-bottom zone of injection wells. Nitrate did not suppress sulfidogenesis in mesophilic enrichments because denitrifiers reduced nitrate to dinitrogen; however, thermophilic denitrifiers produced nitrite, an inhibitor of SRB. Enrichments and a pure culture Desulfovibrio alaskensis Kaz19 formed biofilms highly resistant to biocides. Our results suggest that seawater injection and temperature of the environment determine the composition and functional activity of prokaryotes in the Uzen oil field.

A new insight into the separation of oil from oil/water emulsion by Fe3O4–SiO2 nanoparticles

Nanofluids have shown their potential in the oil recovery process through surface modification. Due to their surface characteristics, they can apply to improve the oil production from reservoirs by enabling different enhanced recovery mechanisms. The preparation and development of the Fe3O4@SiO2 nanoparticles for the oil recovery process is an innovative and novel approach that influences the oil generation from reservoirs. The performance of the Fe3O4@SiO2 and the other nanofluids (seawater, Fe3O4, and SiO2) in the enhanced oil recovery process is assessed and compared with other flooding scenarios. The Fe3O4@SiO2 NPs achieved the highest oil production rate of 90.2% while Fe3O4 and SiO2 NPs achieved 70.8% and 55.3%, respectively. In contrast, the value achieved for the seawater injection was 76.5%. For the oil recovery process, the Fe3O4 was applied for the inhibition (i.e., decrease) of oil sedimentation, and the SiO2 NPs were applied for wettability alteration and IFT reduction. The experimental results showed that the produced Fe3O4@SiO2 NPs improved the oil recovery rates (90.2%) as well as the synergetic impact of the developed NPs by initiating several mechanisms corresponding to the use of the separate NPs in the micromodel. Moreover, the results exhibited that the reservoir conditions are a crucial function for increasing the oil recovery rates, improving the emulsion stability, and acts as a substantial step for the oil recovery method that applies this particular technique.

Identifying Safety Objectives and Functions for Emergency Shutdown in the Design Phase by Using Functional Modelling

This paper proposes a functional modelling method, called Multilevel Flow Modelling (MFM) for identification of safety objectives and functions of emergency shutdown (ESD) system in the design phase for emergency shutdown safely. Firstly, the required information for designing safety objectives and functions for an emergency shutdown is analysed. The information includes process topology, the initial state of the process, the shutdown objectives, and other constraints, such as design and operational limits of unit operations and hazardous and environmental constraints. Secondly, a procedure is proposed based on the required information by using MFM. The procedure incorporates steps: 1) The MFM model of the process in normal operations are built by following modelling procedures, 2) Initiate states are defined and changing conditions are identified of the process when it shuts down unplanned by using the objective-function tree in the MFM modelling, 3) The goals of the shutdown operation are defined, 4) With the consideration of the shutdown operating goals and changing conditions, the first safety function during shutdown process are identified by using MFM causal reasoning, 5) By using MFM consequence reasoning based on the first identified safety function represented in the MFM model, the rest of the safety functions are identified, and the emergency shutdown procedures are generated. This procedure is demonstrated by designing safety functions in an emergency shut down of a seawater deaeration process in a seawater injection system. The results show that the produced emergency shut down procedure based on the proposed method is feasible and that it can be validated against the real operating procedure.

An experimental study of basalt–seawater–CO2 interaction at 130 °C

Over millions of years, the interaction of marine basalt with percolating seawater in low-temperature ocean floor hydrothermal systems leads to the formation of calcite and aragonite. The presence of these minerals in marine basalts provides evidence for substantial CO2 fixation in these rocks. Here, we report on laboratory experiments to study this process under enhanced CO2 partial pressures (pCO2) at 130 °C. Mid-ocean-ridge-basalt (MORB) glass was reacted with North Atlantic Seawater charged with CO2 in batch experiments lasting up to 7 months. For experiments initiated with seawater charged with ~2.5 bar pCO2, calcite and aragonite are the first carbonate minerals to form, later followed by only aragonite (±siderite and ankerite). For experiments initiated with seawater charged with ~16 bar pCO2, magnesite was the only carbonate mineral observed to form. In total, approximately 20% of the initial CO2 in the reactors was mineralized within five months. This carbonation rate is similar to corresponding rates observed in freshwater-basalt-CO2 interaction experiments and during field experiments of the carbonation of basalts in response to CO2-charged freshwater injections in SW-Iceland. Our experiments thus suggest that CO2-charged seawater injected into submarine basalts will lead to rapid CO2 mineralization. Notably, at pCO2 of tens of bars, magnesite will form, limiting the formation of Mg-rich clays, which might otherwise compete for the Mg cation and pore-space in the submarine basaltic crust. This suggests that the injection of CO2-charged seawater into subsurface basalts can be an efficient and effective approach to the long-term safe mineral storage of anthropogenic carbon.