The goal of this research was to study the effect of salinity on the waterflood of initially oil-wet clay-rich sand packs. Two one-foot long sand packs with 8% initial water saturation and 50% porosity were aged in crude oil for two weeks and flooded with either a low salinity (1000 ppm NaCl, pH 6.3) or a high salinity (20000 ppm CaCl, 20000 ppm MgCl, 20000 ppm NaCl, 20000 PPM KCl, pH 6.2) brine. 1D low salinity floods yield an incremental oil recovery of 15% and a significant change in the relative permeability. Initial breakthrough brine analysis showed that the low salinity flood results in more cation exchange activity compared to the high salinity case. A pH change of up to 1.4 point was witnessed for the high salinity case whereas the low salinity case had a 1.1 point pH change. The pH stayed below 7 in both low salinity and high salinity cases. The relative permeability of the low salinity case indicates a more water-wet state than that of the high salinity flood. The 2D study focused on capturing the movement of the water saturation fronts in transparent 2D sand packs via digital recordings. Two-dimensional sand packs of the oil-aged clay-rich sands were constructed in plastic quarter 5-spot models. Secondary water floods were performed. Low salinity flooding yielded higher oil recovery at breakthrough than the high salinity case. There was more areal bypassing in the case of low salinity flooding. It was difficult to pack the 2D cells uniformly which affected the water floods. / text

Petroleum and Geosystems Engineering / Low salinity waterflooding is an emerging enhanced oil recovery (EOR) technique in which the salinity of the injected water is substantially reduced to improve oil recovery over conventional higher salinity waterflooding. Although there are many low salinity experimental results reported in the literature, publications on modeling this process are rare. While there remains some debate about the mechanisms of low salinity waterflooding, the geochemical reactions that control the wetting of crude oil on the rock are likely to be central to a detailed description of the process. Since no comprehensive geochemical-based modeling has been applied in this area, we decided to couple a state-of-the-art geochemical package, IPhreeqc, developed by the United States Geological Survey (USGS) with UTCOMP, the compositional reservoir simulator developed at the Center for Petroleum and Geosystems Engineering in The University of Texas at Austin. A step-by-step algorithm is presented for integrating IPhreeqc with UTCOMP. Through this coupling, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under non-isothermal, non-isobaric and both local-equilibrium and kinetic conditions. Consistent with the literature, there are significant effects of water-soluble hydrocarbon components (e.g., CO2, CH4, and acidic/basic components of the crude) on buffering the aqueous pH and more generally, on the crude oil, brine, and rock reactions. Thermodynamic constrains are used to explicitly include the effect of these water-soluble hydrocarbon components. Hence, this combines the geochemical power of IPhreeqc with the important aspects of hydrocarbon flow and compositional effects to produce a robust, flexible, and accurate integrated tool capable of including the reactions needed to mechanistically model low salinity waterflooding. The geochemical module of UTCOMP-IPhreeqc is further parallelized to enable large scale reservoir simulation applications. We hypothesize that the total ionic strength of the solution is the controlling factor of the wettability alteration due to low salinity waterflooding in sandstone reservoirs. Hence, a model based on the interpolating relative permeability and capillary pressure as a function of total ionic strength is implemented in the UTCOMP-IPhreeqc simulator. We then use our integrated simulator to match and interpret a low salinity experiment published by Kozaki (2012) (conducted on the Berea sandstone core) and the field trial done by BP at the Endicott field (sandstone reservoir). On the other hand, we believe that during the modified salinity waterflooding in carbonate reservoirs, calcite is dissolved and it liberates the adsorbed oil from the surface; hence, fresh surface with the wettability towards more water-wet is created. Therefore, we model wettability to be dynamically altered as a function of calcite dissolution in UTCOMP-IPhreeqc. We then apply our integrated simulator to model not only the oil recovery but also the entire produced ion histories of a recently published coreflood by Chandrasekhar and Mohanty (2013) on a carbonate core. We also couple IPhreeqc with UTCHEM, an in-house research chemical flooding reservoir simulator developed at The University of Texas at Austin, for a mechanistic integrated simulator to model alkaline/surfactant/polymer (ASP) floods. UTCHEM has a comprehensive three phase (water, oil, microemulsion) flash calculation package for the mixture of surfactant and soap as a function of salinity, temperature, and co-solvent concentration. Similar to UTCOMP-IPhreeqc, we parallelize the geochemical module of UTCHEM-IPhreeqc. Finally, we show how apply the integrated tool, UTCHEM-IPhreeqc, to match three different reaction-related chemical flooding processes: ASP flooding in an acidic active crude oil, ASP flooding in a non-acidic crude oil, and alkaline/co-solvent/polymer (ACP) flooding. / text

Waterflooding has been used for many decades as a way of recovering oil from petroleum reservoirs. Historically the salinity of the injection water has not been regarded as a key variable in determining the amount of oil recovered. In recent years, however, evidence of increased oil recovery by injection of low salinity water has been observed in laboratories and fields. The technique is getting wider attention in the oil industry because it is more cost-effective than other EOR techniques. The present work demonstrates the synergy of low salinity water flooding and polymer flooding in the laboratory scale. The use of low salinity polymer solution in polymer flooding has significant benefits because considerably lower amount of polymer is required to make the solution of a target viscosity. Low salinity polymer flooding can also increase oil recovery by lowering residual oil saturation and achieve faster oil recovery by improving sweep efficiency. Several coreflood experiments were conducted to study the efficiency of low salinity water flooding and low salinity polymer flooding in mixed-wet Berea sandstone cores. All the core samples were aged with a crude oil at 90oC for 30-60 days before the tests. All the polymer floods were conducted in the tertiary mode. A synthetic formation brine (33,800 ppm) was chosen for high salinity water and a NaCl brine (1,000 ppm) for low salinity water. Medium molecular weight HPAM polymer, FlopaamTM 3330S was used due to the low/moderate permeability of the Berea sandstone cores used in this study. Coreflood tests indicate that injection of low salinity polymer solution reduces residual oil saturation by 5-10% over that of the high salinity waterflood. A part of the residual saturation reduction is due to low salinity and this reduction is achieved in less pore volumes of injection in the presence of polymers. Effluent ion analysis from both low salinity water flooding and low salinity polymer flooding showed a slight increase in divalent cation concentrations after the polymer breakthrough. Cation bridging may play a role in oil wettability and low salinity injection desorbs some of these cations. / text

The effect of brine ionic composition on oil recovery was studied for a limestone reservoir rock at a high temperature. Contact angle, imbibition, core flood and ion analysis were used to find the brines that improve oil recovery and the associated mechanisms. Contact angle experiments showed that modified seawater containing Mg[superscript 2+] and SO4[superscript 2-] and diluted seawater change aged oil-wet calcite plates to more water-wet conditions. Seawater with Ca[superscript 2+], but without Mg[superscript 2+] or SO₄[superscript 2-] was unsuccessful in changing calcite wettability. Modified seawater containing Mg[superscript 2+] and SO₄[superscript 2-], and diluted seawater spontaneously imbibe into the originally oil-wet limestone cores. Modified seawater containing extra SO₄[superscript 2-] and diluted seawater improve oil recovery from 40% OOIP (for formation brine waterflood) to about 80% OOIP in both secondary and tertiary modes. The residual oil saturation to modified brine injection is approximately 20%. Multi ion exchange and mineral dissolution are responsible for desorption of organic acid groups which lead to more water-wet conditions. Further research is needed for scale-up of these mechanisms from cores to reservoirs. / text

Injection of low-salinity water showed high potentials in improving oil recovery when compared to high-salinity water. However, the optimum water salinity and conditions are uncertain, due to the lack of understanding the mechanisms of fluid-rock interactions. The main objective of this study is to examine the potential and efficiency of low-salinity water in secondary and tertiary oil recovery for sandstone reservoirs. Similarly, this study aims to help in understanding the dominant mechanisms that aid in improving oil recovery by low-salinity waterflooding. Furthermore, the impact of cation type in injected brines on oil recovery was investigated. Coreflood experiments were conducted to determine the effect of water salinity and chemistry on oil recovery in the secondary and tertiary modes. The contact angle technique was used to study the impact of water salinity and composition on rock wettability. Moreover, the zeta potential at oil/brine and brine/rock interfaces was measured to explain the mechanism causing rock wettability alteration and improving oil recovery. Deionized water and different brines (from 500 to 174,000 mg/l), as well as single cation solutions were tested. Two types of crude oil with different properties and composition were used. Berea sandstone cores were utilized in the coreflood experiments. Coreflood tests indicated that injection of deionized water in the secondary mode resulted in significant oil recovery, up to 22% improvement, compared to seawater flooding. However, no more oil was recovered in the tertiary mode. In addition, injection of NaCl solution increased the oil recovery compared to injection of CaCl2 or MgCl2 at the same concentration. Contact angle results demonstrated that low-salinity water has an impact on the rock wettability; the more reduction in water salinity, the more a water-wet rock surface is produced. In addition, NaCl solutions made the rock more water-wet compared to CaCl2 or MgCl2 at the same concentration. Low-salinity water and NaCl solutions showed a highly negative charge at rock/brine and oil/brine interfaces by zeta potential measurements, which results in greater repulsive forces between the oil and rock surface. This leads to double-layer expansion and water-wet systems. These results demonstrate that the double-layer expansion is a primary mechanism of improving oil recovery when water chemical composition is manipulated.

Overfishing of natural fisheries is a global issue that is becoming more urgent as the human population increases exponentially. According to the Food and Agriculture Organization of the United Nations, over 70% of the world's seafood species are fully exploited or depleted. This high demand for seafood protein is not going away; and, in fact, an astonishing one out of five people in this world depend on this source of protein. Traditional aquaculture practices use pond and flow-through systems which are often responsible for discharging pollutants into the environment. Furthermore, aquacultural feeds often contain high levels of fish protein, so the demand on wild fisheries is not completely eased. Even though traditional aquaculture has these drawbacks, there is a significant movement towards more sustainable practices. For example, implementing recirculating aquaculture systems (RAS) maximizes the reuse of culture water which decreases water demand and minimizes the levels of pollutants being discharged to the environment. And, alternative proteins (e.g., soy bean) are replacing the fish and seafood proteins in aquaculture diets. Accordingly, the research described in this dissertation focused on maximizing the reuse of freshwater fish effluent to culture marine shrimp. More specifically, by using suspended-growth biological reactors to treat a tilapia effluent waste stream and to generate microbial flocs that could be used to support shrimp culture. This RAS technology will decrease water consumption by increasing the amount of recycled water and will also improve effluent water quality. The biomass generated in the bioreactors could be used to feed shrimp with an alternative source of protein. Treating fish effluent to be reused to culture shrimp while producing this alternative feed, could significantly decrease operational costs and make these operations more sustainable. Understanding which ions are critical for the survival and normal growth of marine shrimp in freshwater effluents is essential. It is also very important to understand how to convert an effluent's organic matter into food for shrimp. Results from studies revealed that the marine shrimp, Litopenaeus vannamei, can be raised in freshwater effluent when supplemented with specific ions and wet microbial flocs fed directly to shrimp can enhance growth in shrimp fed a restricted ration of commercial feed. The treatability of the tilapia effluent using suspended-growth, biological reactors and nutritional analysis of the generated biomass were also reported. Carbon supplementation enhanced reactor performance and microbial floc generation. These microbial flocs also proved to be a superior feed ingredient when dried and incorporated into a pellet feed. / Ph. D.

Crude oil recovery is related to surface wettability, which is controlled by crude interactions with rock surfaces. Understanding these interactions is associated with studying the complex asphaltenes that (1) are irreversibly deposited from oil-brine interfaces onto reservoir mineral surfaces, (2) are bulky super-molecules and (3) incorporate several chemical groups by stacking aromatic rings together. This is a difficult task because of varying crude oil composition, asphaltene interfacial and chemical activity, and the potential of irreversibly contaminating analytical equipment by such substances. To overcome these challenges, we split the problem into parts by studying how different mono- and poly-functional groups mimic asphaltene interaction with mineral surfaces, such as silica and calcium carbonate. The amine, carboxylate, and sulfate groups were identified as the highest potential functional groups responsible for asphaltene adsorption. Experiments included quartz crystal micro-balance with dissipation, bulk adsorption, and core samples. Adsorption tests for the mono-functional surfactants studied were fully reversible and, therefore, not representative of asphaltenes. Poly-functional compounds demonstrated irreversible adsorption, mimicking asphaltenes, through ion exchange and ion-bridging, depending on the type of functional group, chain length, mineral surface, and brine ionic composition. Poly-amines adsorb irreversibly onto silica and calcium carbonate surfaces regardless of the brine ionic composition or surface charge. However, irreversible adsorption of poly-sulfates and poly-carboxylates onto surfaces requires (1) sufficiently long chains and (2) an abundant presence of calcium ions in solution to allow ion-bringing mechanism. These findings suggest that crudes containing amine groups and long chains of carboxylates or sulfates have a higher tendency to be adsorbed onto surfaces and change wettability. This is important for designing an efficient detachment of asphaltenic oil from rock surfaces, where no complete desorption or drastic wettability change is required. The weakening of asphaltene interactions may be sufficient to induce spontaneous imbibition and consequently increase the efficiency of two-phase displacement. This work emphasizes the importance of understating crude-brine-rock interactions for the purpose of oil recovery. In summary, evaluating potential candidates for deploying enhanced oil recovery, such as low salinity waterflooding, should consider rock and crude types, as successful implementation requires “specific” properties collaborating together to enable incremental oil production

京都大学 / 0048 / 新制・課程博士 / 博士(工学) / 甲第20062号 / 工博第4250号 / 新制||工||1658(附属図書館) / 京都大学大学院工学研究科社会基盤工学専攻 / (主査)教授 寶 馨, 教授 立川 康人, 准教授 佐山 敬洋 / 学位規則第4条第1項該当 / Doctor of Philosophy (Engineering) / Kyoto University / DFAM

Asphaltenic crude oil is a complex fluid containing various components with different chemical properties. When it comes in contact with water, its polar components adsorb at the oil/water interface, reducing the interfacial tension and eventually developing viscoelastic films. The interfacial films impact emulsion stability and adhere to the oil-bearing reservoirs rocks, altering their wettability and thus hindering oil mobilization. Here, we investigate the formation of crude oil/water interfacial films. We measure both the time-dependent shear and extensional interfacial rheology moduli, and we relate it to the chemical composition of the films, highlighting the role of polar aromatic molecules in film formation. Varying chemical composition of the aqueous phase, we show that the properties of the interfacial films depend not only on the concentration of ionic species in water but also on their chemical nature. In particular, we highlight the role of sulfate salt in promoting interfacial viscoelasticity and in altering the composition of fully developed films. To study the rock/fluid interaction, we fabricate mixed-wet capillaries with angular cross-sections inspired by the naturally occurring primary drainage of pore-filling brine by invading crude oil. After employing our novel coating procedure, we experimentally investigate water invasion in mixed-wet capillaries and compare it with predictions of dynamic and quasi-static (Mayer-Stowe-Princen (MSP)) meniscus-invasion models. None of the dynamic models built for uniformly-wet pores can fully describe our experimental data in mixed-wet capillaries. However, the experimental results agree with predictions of MSP theory. To our knowledge, this is the first direct experimental validation of MSP theory under mixed-wet conditions. We confirm the possibility of spontaneous piston-type imbibition with high ($> 90^{\circ}$) advancing contact angles into mixed-wet pores, given that the contact angle is lowered below a critical value that is a function of pore geometry and residual water saturation. In oil reservoirs, injection of specific brines would be required to change the contact angle to values below the imbibition threshold. Finally, we extend our study and introduce a powerful 3D high-speed laser imaging of dynamic fluid flow in angular capillaries and investigate its capability to capture non-equilibrium shapes of fluid interfaces.

[pt] O presente trabalho busca discutir mecanismos em pauta na literatura em relação à injeção de água de salinidade otimizada com os resultados de 10 (dez) testes de escoamento bifásico óleo/água para 2 (dois) cenários carbonatos e 1 (um) arenito. O principal objetivo foi estudar o efeito de íons potencialmente determinantes (Ca, Mg, SO4, NaCl), além da temperatura, no fator de recuperação e curvas de permeabilidade relativa óleo-água. Em relação a carbonatos, avaliou-se se Ca/Mg e SO4 tinham algum papel na alteração da molhabilidade da formação e, em caso positivo, se esse efeito era exacerbado em ambiente de baixa salinidade. Em relação a reservatórios areníticos, comparou-se a injeção de água dessulfatada com água do mar diluída. Dos testes de deslocamento realizados em amostras de arenito, observou-se que água do mar diluída, injetada após água do mar dessulfatada foi capaz de, em média, acrescer o FR em 2,8 por cento e em reduzir o Sor de 2,1 por cento. Quanto ao cenário carbonato A de alta temperatura avaliado (95 graus Celsius), observou-se que água otimizada, quando injetada após água dessulfatada, foi capaz de aumentar o FR em 15,3 por cento e diminuir o Sor em 12,1 por cento. Ainda, quando se introduziu água otimizada de forma secundária, observou-se redução no Sor em 4,6 por cento e aumento do FR em 5,9 por cento quando comparado com a injeção usual de água. No carbonato B, injeção da água otimizada após água dessulfatada levou a um acréscimo de 10,1 por cento no FR e diminuição de 7,1 por cento no Sor. Tanto no cenário arenito quanto nos carbonatos, não houve produção adicional de óleo quando injetado água do mar após a injeção de água otimizada. Isso corrobora a ideia de que o fluido customizado permitiria atingir o máximo de eficiência de deslocamento. / [en] The present work seeks to discuss possible mechanisms in the literature based in the results of 10 (ten) oil / water core flooding experiments in 2 (two) carbonate scenarios and 1 (one) sandstone scenario Rock and oil samples from real reservoirs were used in experimental conditions of temperature and pressure close to the field reality. The main objective was to study the effect of Ca, Mg, SO4, NaCl and temperature on the recovery factor and oil-water relative permeability curves.Regarding the carbonate scenario, it was evaluated whether Ca / Mg and SO4 had any role in altering the wettability of the formation and, if so, whether this effect was exacerbated in a low salinity environment. For the sandstone reservoirs, the injection of desulfated water and seawater diluted were compared. From the displacement tests carried out in the sandstone samples, it was observed that the diluted sea water, injected after the desulfated sea water, was able to average increase the RF by 2.8 percent and to reduce the Sor by 2.1 percent. Regarding the hightemperature carbonate scenario evaluated (95 degrees Celsius) it was observed that the optimized water, when injected tertiarily, was able to increase the RF by 15.3 percent and decrease the Sor by 12.1 percent, in comparison to the desulfated seawater. In carbonate B, optimized water injection after desulfated water led to a 10.1 percent increase in the recovery factor and a 7.1 percent decrease in the residual oil saturation. Mainly, in both sandstone and carbonate scenarios, there was no additional oil production when sea water was injected after the optimized water injection. This corroborates the idea that the taylor-designed fluid achieves maximum displacement efficiency.