Solvent injection recovery processes were introduced as a more energy-efficient and environmentally friendly alternative to Steam injection processes. However, BTX chemicals (Benzene, Toluene, and Xylene), commonly used for crude oil recovery due to their strong solvency and low asphaltene precipitation, are acutely toxic and harmful to the environment. These chemicals are easily soluble in water causing groundwater contamination. This paper evaluates the recovery efficiency of two green solvents, Limonene, and beta-pinene, on two samples of Californian heavy oil (C1 has an 874.8 cP viscosity and C2 has 178500 cP viscosity). On both C1 and C2, 5 core flood experiments were conducted, in total 10 experiments were run. CO2, limonene, and Beta-pinene were tested as solvents on both oils. Limonene and beta-pinene were both chosen due to their ready availability in the State of California. Both these solvents are plant-derived, non-toxic, and biodegradable. They also have much higher flash points than BTX solvents allowing for safer handling. They have been either injected as sole solvents or co-injected with CO2 during the experiments. Limonene and beta-pinene were injected at 2 mL/min while CO2 was injected at 2000 ml/min with a back pressure of 45-55 psi. Core packs were prepared by filling the pore space of Ottawa sand with 60% PV oil samples and 40% PV water by volume. Produced oil and water samples were collected every 20 min during the experiments. Thermogravimetric analyses (TGA/DSC) were conducted on these samples to identify oil, water, and solvent percentages. Because CO2 is insoluble in these types of high viscosity crude oils, CO2 flooding resulted in immiscibility with almost no oil production. Since both limonene and beta-pinene are aromatic solvents, by sole limonene or beta-pinene injection miscible flooding was achieved. Limonene achieved 35 and 23 vol. % oil recovery from a total of 60% oil for C1 and C2 respectively while Pinene achieved 31 and 27 vol. %. Co-injections of green solvents with CO2 are expected to yield higher recovery due to the presence of two active drive mechanisms namely miscible and immiscible. Co-injection of limonene and CO2 provided the greatest recovery with 45 vol. %, however, recovery efficiencies of pinene and CO2 had comparable recoveries with that of pinene possibly due to phase trapping. Produced samples analysis showed that oil percentages in produced samples were higher for Limonene than Pinene. Our results indicated that limonene and beta-pinene are very promising solvents for heavy oil recovery. Because these solvents are citrus-based, they are both easy to handle and non-toxic. Hence, we believe that our study can be a breakthrough for many heavy oil and bitumen reservoirs all around the world.

Global oil consumption is predicted to increase by 15% from 2021 to 2050. The increasing oil demand and decreasing conventional oil supply force us to find alternate energy supplies. The key to this problem lies with the vast untapped heavy oil and bitumen resources. In this study, we investigate the effectiveness of an environmentally friendly solvent, limonene, in recovering heavy oil. Three core flood experiments representing three different recovery methods were carried out. These include steam flooding (E1), solvent flooding (E2), and solvent-steam co-injections (E3). The green solvent, limonene, is a citrus-based non-toxic solvent. It was chosen due to its high organic solvency and ready availability. Throughout the experiments, steam was injected at a cold water equivalent of 18 ml/min, while limonene was injected at 2 ml/min. The experiments were run with a back pressure of 45-55 psi. The core pack was prepared by filling the pore space of Ottawa sand with a 60% heavy oil sample and 40% water by volume (including water percentage in oil). Produced oil and water samples were collected every 20 min during the experiments. These samples were further analyzed by emulsion characterization to determine emulsion stability and oil quality. Spent rock analyses were done to calculate the displacement efficiency of each of the experiments. In addition, an economic analysis was done to determine the optimal recovery method. Spent rock analysis showed that a sole injection of limonene (E2) had the highest oil recovery. This confirms the high organic solvency of limonene achieved miscible flooding producing about 46 vol % from a total of 60 vol % initial oil. Steam flooding (E1), on the other hand, did not perform as well, producing around 29 vol %. The post-mortem sample from E1 indicated asphaltene precipitation which could have lowered oil recovery. Co-injection of limonene and steam was expected to yield the highest recovery due to the presence of two active drive mechanisms, thermal and miscible flooding. However, it performed comparatively less (41 vol %) than a sole injection of limonene (E2). This is further explained with emulsion characterization results. Experiments involving steam (E1 and E2) revealed strong emulsions in the oil produced, indicating a lower quality. Furthermore, it was seen that the solvent-steam process produced weaker emulsions compared to steam flooding alone. On the other hand, solvent flooding (E2) produced high-quality oil with little to no emulsions. These results along with the economic analysis, indicate that the optimal recovery method would be solvent flooding (E2). Our results prove that limonene is a promising organic solvent. Limonene is non-toxic, readily available, and safe to handle. As a result, it can be a safe green alternative to commonly used toxic organic solvents such as toluene.

Oil-based drilling fluids (OBDF) can enhance wellbore stability in water-sensitive reservoirs and protect metal surfaces of drilling equipment to minimize corrosion due to H2S and CO2. Components of OBDF include oil as the continuous phase and water as the dispersed phase, in conjunction with viscosifiers, emulsifiers, filtration control agents, and weighting materials. Two of the most common types of continuous phases in oil-based drilling fluids are diesel and mineral oil. Mineral oil is less toxic than diesel, and oil retention properties of OBDF with mineral oil are less than OBDF with diesel. Organophilic clays are clay minerals that have been treated with oil-wetting agents, which will make the clay oil-dispersible. Organophilic clays mixed in OBDF do not exhibit same viscosity or suspension characteristics as in water-based drilling fluids, because electrical interaction between particles is minimal, making it difficult to build viscosity and gel strength in high pressure and high temperature (HP/HT) wellbore conditions. A new mineral-oil-based drilling fluids (MOBDF) proposed was obtained by the successful replacement of conventional organophilic clay with a novel polymer. Conventional organophilic clay and novel polymer were aged at 150°F for 16 hours. To evaluate the alteration of the wettability caused by the MBDOF and its components, surface tension and contact-angle measurements were made in the laboratory. With similar weight proportions, the apparent and kinetic viscosities of organophilic clay and cross-linked polymer were also compared. Rheological properties and filtration characteristics tests were conducted using a rotational viscometer and a HP/HT filter press, under three simulated wellbore conditions (140°F/ 300 psi, 190°F/300 psi, and 250°F/500 psi). Filter cake is formed due to positive pressure between OBDF and pore throats pressure. As a barrier between wellbore and formation, it can minimize solids and fluids invasion. Core flooding test was conducted to evaluate permeability of the filter cakes and CT scan was used to measure the density distribution of the filter cakes. Emulsion droplets formed by mixing MOBDF filtrate fluids with formation water were observed to analyze emulsion plugging damage. Experimental results show that the novel polymer has a promising future of practical application, by providing thermal stability and stable rheological properties for MOBDF in HP/HT conditions. It also brings lower filtration volume, higher quality filter cake and slightly greater emulsion plugging damage to formations than organophilic clay-based drilling fluids.