Oil Swelling Research Articles

Prediction of CO2 Solubility in Oil and the Effects on the Oil Physical Properties

CO2 solubility in oil is a key parameter in CO2 flooding process. It results in oil swelling, increased oil density, and decreased oil viscosity. Laboratory studies needed to cover a wider range of data, and are time consuming, costly, and may be not available or possible in many situations. On the other hand, although various models and correlations are useful in certain situations, they may are not be applicable in many situations. In this study, a new genetic algorithm- (GA)-based technique has been used to develop more reliable correlations to predict CO2 solubility, oil swelling factor (SF), CO2-oil density, and viscosity of CO2-oil mixtures. Based on the Darwinian theory, the GA technique mimics some of the natural process mechanisms. Furthermore, GA-based model correlations recognize all the major parameters that affect each physical property and also well address the effects of CO2 liquefaction pressure. Genetic algorithm-based correlations have been successfully validated with published experimental data. In addition, a comparison of these correlations has been made against widely used correlations in the literature. It has been noted that the GA-based correlations yield more accurate predictions with lower errors than all other correlations tested. Furthermore, unlike other correlations that are applicable to limited data ranges and conditions, GA-based correlations have been validated over a wider range of data.

A chemical modification approach for improving the oil resistance of ethylene–propylene copolymers

The need for a low-cost and weather, high-temperature and oil-resistant rubber is well-established in the market place. Such products have the potential to replace high cost rubbers and/or oil-resistant rubbers that lack weather and high-temperature resistance. The present study aims at increasing the polarity of EP(D)M rubber by chemical modification and cross-linking of EPM copolymer grafted with maleic anhydride (EPM- g-MA). First, it is shown that the oil resistance of rubbers can be predicted using calculated solubility parameters. Next, a variety of modified EPMs has been designed, directed at a high polarity in combination with a relatively low glass transition temperature, and have subsequently been prepared to validate the concepts experimentally. The various modification approaches resulted in (significantly) improved oil resistance and are in fair agreement with the calculated oil swell data. It is concluded that new rubber materials based on EPM- g-MA can be developed, that may replace existing oil-resistant elastomers.

Experimental and Simulation - Assisted Feasibility Study of Gas Injection to Increase Oil Recovery Using a Combination of Semi-VAPEX and GAGD Techniques

Gas injection into heavy oil reservoirs could result in high ultimate recovery of oil. Experimental studies showed that an application of a combined technology of Gas Assisted Gravity Drainage (GAGD) and Vapor Extraction (VAPEX) could increase final oil recovery of a candidate viscous oil reservoir. In this paper the results of laboratory investigation are presented, including Pressure-Volume-Temperature (PVT) studies, physical model experiments and simulation studies to evaluate the gas injection process for heavy oil reservoirs recovery. The study examined the effect of two different gases on viscosity reduction and oil swelling. Physical model tests were carried out to investigate the effect of gas injection on oil recovery. Another study (simulation model) predicted the performance of the reservoir under gas injection in a model. This simulation study was established on a sector of the reservoir.

High‐performance styrenic thermoplastic vulcanizates for long‐term application

AbstractStyrenic thermoplastic vulcanizates (STPVs) were developed for long‐term high‐temperature applications. These STPVs consist of polypropylene as the continuous phase and a crosslinked modified hydrogenated styrenic block copolymer (mHSBC) as the dispersed phase. The present study compared STPVs with conventional TPVs (CTPVs) containing EPDM/PP. The STPVs showed a 20% improvement in solvent resistance after 500 h of immersion in IRM 903 oil at 125°C, and the swelling of oil did not increase with time. The elastic recovery was 50% better than with CTPVs. Tensile property retention was approximately 10% higher after aging for 1440 h at 125°C when compared to CTPVs. These observed property improvements for STPVs relative to conventional TPVs can possibly be explained by the unique morphology of the resulting STPV compounds. These performance characteristics make STPVs more suitable for high‐temperature air and chemical environmental applications. This new TPV technology is expected to bridge the gap between polypropylene/EPDM TPVs and more costly engineering TPVs. © 2007 Wiley Periodicals, Inc. J Appl Polym Sci 2007

Phase Behaviour and Compositional Changes Associated With Residual Oxygen in a Miscible CO/Light Oil Reservoir

Abstract Concern about the effects of global greenhouse gases has made people aware of the need to reduce the atmospheric concentration of industrial waste gas. Alberta, as the centre of Canada's petroleum industry, is strongly impacted by the politics of greenhouse gases. One way Alberta can achieve the goals of the Kyoto Protocol is to capture CO2 from stack gases and to inject it into oil reservoirs to enhance recovery while sequestering at least a portion of the CO2. This paper will concentrate on oil from the Swan Hills Formation reservoir operated by Devon Oil Corporation. The phase behaviour of different concentrations of CO2/O2 mixtures injected into the Swan Hills reservoir was investigated. Two PVT (Pressure-Volume-Temperature) apparatus were used to visually observe phases and to determine bubble points and swelling of the oil rich phase. The PVT measurements were performed to develop a basic understanding of the phase behaviour for the CO2 / O2 /oil system. The composition of oxidized oil was predicted using a previously developed low temperature oxidation model coupled with phase equilibrium calculations. Introduction Carbon dioxide flooding is a well established enhanced oil recovery process in regions where CO2 is available. Canada has been slow to implement CO2 floods due to the lack of natural sources. However, the public's concern with greenhouse gas emissions and Canada's support for the Kyoto Protocol provide sufficient environmental incentives to allow for the application of CO2 floodingas a combined EOR/sequestration process. Capturing the CO2 from stack gas is an expensive process and the actual cost will depend on the purity of the CO2 stream that is required. Oxygen is an important factor as its impurity can modify the native oil properties through low temperature oxidation reactions, promotion of corrosion in the injection and production piping and alter the phase behaviour of the reservoir fluids. The study described in this paper will examine how oxygen is consumed in the reservoir, and it will concentrate on the impact of oxidation reactions with regard to the composition and emulsification characteristics of the oil. Lee(1) studied the phase behaviour and displacement efficiency of a carbon dioxide-hydrocarbon system which consisted of various mixtures of n-pentane/n-hexane. The results demonstrated that multiple phase behaviour involving two liquids with and without a vapour phase occurred during carbon dioxide injection in low temperature reservoirs. A number of studies on the effectiveness of carbon dioxide displacement under miscible and immiscible conditions have been reported by Wilburn et al.(2), Dyer et al.(3), Srivastava and Huang(4, 5) and Srivastava et.al.(6). The results showed that CO2 /oil miscibility could be developed and that the swelling behaviour depended on the chemical composition of the oil. Wilburn et al.(2) also found that miscibility is strongly dependent on the volatility or boiling point distribution of the oil. Dyer et al.(3) investigated the phase behaviour of typical Saskatchewan heavy oils with carbon dioxide. Their study was divided into two categories: stock tank oil and reservoir oil, which were mixed with CO2 in different ratios. Parameters studied included viscosity, density, swelling factor and gas-oil ratio (GOR).

Screening Criteria for Carbon Dioxide Huff 'n' Puff Operations

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100044, "Screening Criteria for Carbon Dioxide Huff ‘n’ Puff Operations," by L. Mohammed- Singh, SPE, Petrotrin, and A.K. Singhal, SPE, and S. Sim, SPE, Alberta Research Council, prepared for the 2006 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 22-26 April. The full-length paper reviews design and performance data on 16 CO2 huff ‘n’ puff projects in the Forest Reserve oil field of Trinidad and Tobago from the past 20 years. Huff ‘n’ puff operations essentially are near-wellbore stimulation techniques that can lead to increased oil recovery by removal of productivity damage, reduced oil viscosity, increased dissolved-gas content, oil swelling, and vaporization of lighter oil components. Introduction The first huff ‘n’ puff experimental project in Trinidad and Tobago was conducted in 1984 in the Forest Reserve oil field. For the Forest Reserve reservoirs with medium-to-heavy crude oils, viscosity reduction and oil swelling aided by gravity drainage and water encroachment are believed to be the most significant mechanisms contributing to increases in oil recovery. The literature contains many screening criteria for enhanced-oil-recovery processes. However, for CO2 huff ‘n’ puff operations, these are generally included in those for immiscible gas-flooding applications. The full-length paper proposes screening criteria for huff ‘n’ puff operations on the basis of results from the Forest Reserve oil field and other published field tests. Reservoir Description The Forest Reserve oil field contains multiple, stacked, complex deltaic reservoirs. The rock and fluid properties of the four reservoirs (targets for huff ‘n’ puff operations) are listed in Table 1 in the full-length paper. Oil gravity ranges from 14 to 25°API, with in-situ viscosities of 12 to 3,000 cp. Reservoirs are solution-gas drive with contributions from water influx. Operations and Production Response CO2 was compressed to 1,000 psi and injected until desired slug volumes were achieved. Wells were shut in, left to soak for 3 to 5 days, and back flowed. Wells were subjected to several cycles (5 cycles maximum). A total of 2,092 MMcf of CO2 was injected and 101,635 bbl of oil recovered from the 16 wells tested. Responses varied from none to a maximum of 12,000 bbl in one cycle. The production cycle generally lasted more than 6 months and as much as several years in some wells. An average of 6,300 bbl per well was recovered, with one well achieving 31,000 bbl. Some of the wells that showed good responses were in downdip locations and possibly benefited from water influx and gravity drainage during the puff phase. Updip wells that yielded good recoveries also were near faults, which may have helped in providing containment and efficient capture of the mobilized oil. Five wells experienced mechanical difficulties and were excluded from the following analyses.

Diffusion coefficients and oil swelling factors of carbon dioxide, methane, ethane, propane, and their mixtures in heavy oil

In this paper, a newly developed dynamic pendant drop volume analysis (DPDVA) method is applied to measure the diffusion coefficients and oil swelling factors of four pure solvents (carbon dioxide, methane, ethane, and propane) and three solvent mixtures (mixture #1: 70 mole% carbon dioxide + 30 mole% propane, mixture #2: 70 mole% methane + 30 mole% propane, and mixture #3: 70 mole% ethane + 30 mole% propane) in Lloydminster heavy oil in the pressure range of 0.4–14.0 MPa and at T = 23.9 °C. The experimental results show that both the diffusion coefficient and the oil swelling factor of a heavy oil–solvent system increase with pressure. In particular, the diffusion coefficients and oil swelling factors of propane and ethane in heavy oil at pressures slightly lower than their respective vapour pressures are relatively large ( D ≥ 0.680 × 10 −9 m 2/s, f sw ≥ 1.314). It is also found that the apparent diffusion coefficients and the apparent oil swelling factors of the three solvent mixtures at pressures slightly below their respective dew-point pressures are large ( D a ≥ 0.706 × 10 −9 m 2/s, f sw ≥ 1.351). The experimental results clearly indicate that there exist certain correlations among the diffusion coefficient, oil swelling factor, solubility, and viscosity of a heavy oil–solvent system. Further experimental and theoretical studies are needed to determine these correlations.

Laboratory Investigation of Enhanced Light-Oil Recovery By CO/Flue Gas Huff-n-Puff Process

Abstract This paper focuses on phase behaviour measurements with reservoir oil-CO2 mixtures and on coreflooding tests in the huffn- puff mode to characterize the system, determine the influential mechanisms, and supply data for simulation of the field implementation. The results indicate that significant amounts of CO2 could dissolve in the oil, which caused oil swelling and viscosity reduction. During the puff cycle, the oil retained CO2 preferentially to methane; thus, the beneficial swelling and viscosity effects were maintained over an extended portion of this cycle. Corefloods were performed to investigate the effect of waterflood residual oil saturation and injection gas composition (CO2 and enriched flue gas) on oil recovery. Incremental oil recovery was observed to be sensitive to waterflood residual oil saturation and to the process application scheme. Coreflooding results suggest that the huff-n-puff process may be more suitable to oil-wet than water-wet reservoirs. Introduction Various technologies have been applied in tertiary oil recovery processes, such as gas miscible/immiscible injection and chemical flooding. Among these enhanced oil recovery (EOR) methods, the huff-n-puff process has been reported to be economic at an oil price of less than US$20/STB and CO2 costs of US$40/ton(1). For example, it was shown in a flue-gas huff-n-puff project(2)that oil production rates stabilized, and the project proved to be cost effective with small investment requirements and low operating costs. In another case(3), the CO2 huff-n-puff process was not successful in increasing incremental oil recovery. However, there were reduced water-handling and electrical requirements during the injection, soak, and flow phases, which were beneficial to the project. There is increasing interest in CO2/flue-gas huff-n-puff injection into single wells because the process is relatively easy to apply and does not require a large initial capital outlay. The process typically begins with the injection of a slug of gas into a single well. This is followed by a shut-in or soak period to allow the gas to dissolve into the oil, swell its volume, and reduce its viscosity. The same well is then returned to production and the response is monitored. In reservoirs with poor inter-well communication, this single-well approach may be one of the best ways, and sometimes the only way, to accelerate response in underperforming wells. Since miscibility between the reservoir oil and injected gas is not a requirement of the huff-n-puff process, it is well suited for low pressure reservoirs and for gases with high minimum miscibility pressures such as flue gas. The mechanisms involved in the production of oil during gas huff-n-puff are diverse and complex. The following mechanisms have been mentioned in the literature(4–6):oil viscosity reduction;oil swelling;solution gas drive;relative permeability hysteresis due to reduced water saturation, drainage/imbibition, and wettability alternation;repressurization;gas diffusion and mass transfer; and,interfacial tension reduction in the zone near the wellbore. The purpose of this work is to investigate the potential for applying the CO2 huff-n-puff process in a medium-gravity oil reservoir in Saskatchewan.

Utilisation of maleic anhydride and epoxidised soyabean oil as compatibilisers for NBR/EPDM blends reinforced with modified and unmodified polypropylene fibres

PurposeTo evaluate the performance of the compatibiliser of epoxidised soyabean oil‐free fatty acid prepared on the NBR/EPDM blends compared with maleic anhydride and also to explore the effect of loading the compatibiliser NBR/EPDM rubber blend with unmodified and modified polypropylene fibres on the mechanical properties of the blend.Design/methodology/approachTo achieve desirable rheological and physico‐mechanical properties of NBR/EPDM rubber blend, various compositions were made by incorporating different doses of the compatibiliser of epoxidised soyabean oil‐free fatty acid prepared and maleic anhydride to form NBR/EPDM blends. The effect of loading the compatibiliser rubber blend with unmodified and modified polypropylene fibres on the mechanical properties of the blend was investigated.FindingsThe incorporation of epoxidised soyabean oil‐free fatty acid or maleic anhydride into NBR/EPDM blend greatly enhanced their compatibility improved the rheological, as well as physical properties of rubber blends. The addition of NBR to EPDM improved the motor oil swelling resistance of EPDM. Blending of the two individual rubbers without a compatibiliser generally exhibited a non‐synergistic effect with respect to the physical properties. The strain energy, tensile strength, Young's modulus and strain at yield varied linearly with composition in the presence of compatibiliser, but deviated from linearity in the absence of compatibiliser. Reinforcement of the NBR/EPDM blend with modified polypropylene fibres enhanced the physical properties more significantly than with the unmodified ones.Research limitations/implicationsThe compatibiliser of epoxidised soyabean oil was prepared by reacting in situ soyabean oil‐free fatty acid with per‐acetic acid.Practical implicationsThe method developed provided a simple and practical solution to improving the rheological and physico‐mechanical properties of the NBR/EPDM rubber blend.Originality/valueThe method for enhancing rheological and physico‐mechanical properties of NBR/EPDM rubber blend loaded with modified polypropylene fibres was very important and showed a synergistic effect and could find numerous applications in the rubber and plastic industries.

New Experimental Method for Measuring Gas Diffusivity in Heavy Oil by the Dynamic Pendant Drop Volume Analysis (DPDVA)

This paper presents a new experimental method and its computational scheme for measuring gas diffusivity in heavy oil at high pressures and elevated temperatures by the dynamic pendant drop volume analysis (DPDVA). In the experiment, a see-through windowed high-pressure cell is first filled with a test gas at a prespecified pressure and temperature. Then, a heavy oil sample is introduced by using a syringe pump to form a pendant drop inside the pressure cell. Due to the oil swelling effect, the subsequent dissolution of the gas into the pendant oil drop causes its volume to increase until the saturation state is reached. The sequential digital images of the dynamic pendant oil drop are acquired and analyzed by applying computer-aided image acquisition and processing techniques to measure the oil drop volumes at different times. A mass-transfer model is developed theoretically to describe the diffusion process of the gas into the pendant heavy oil drop. This model is numerically solved by applying the semidiscrete Galerkin finite element method. The volume of the dynamic pendant oil drop is calculated from the numerically predicted transient gas concentration distribution inside the pendant oil drop. The gas diffusivity in heavy oil and the swelling factor of gas-saturated heavy oil are, thus, determined by finding the best fit of the theoretically calculated volumes of the dynamic pendant oil drop to the experimentally measured data. This novel experimental technique is applied to measure CO2 diffusivities in a heavy oil sample and the swelling factors of a CO2-saturated heavy oil at P = 2, 3, 4, 5, and 6 MPa and T = 23.9 °C.

3-25.水熱/油中改質によるバイオマスの新規高品位原料化法の検討((6)熱分解III,Session 3 バイオマス等)

3-25.水熱/油中改質によるバイオマスの新規高品位原料化法の検討((6)熱分解III,Session 3 バイオマス等)

Effects of Storage and Service on Tire Performance: Oil Component Content and Swelling Behavior

Abstract In order to investigate the effects of storage and service on passenger car tire performance, two separate sets of samples were characterized: (i) tires stored at a temperature of 45–50 °C for different time periods, and (ii) used tires of different mileage. The tires were analyzed with respect to the performance of the tread rubber as manifested in the modulus at 200% elongation, the tensile strength at break, the elongation at break, the hardness, the viscoelasticity of the rubber, swelling, and the oil component content. The change in the properties of the tires as functions of increasing storage time and mileage indicated a marked deterioration in performance. The rate of change in these properties was found to be markedly enhanced by the extra stimuli provided by service, as demonstrated by comparing tires of similar age but different mileage. The results were analyzed and rationalized in terms of the change in the degree of crosslinking and transfer of oil components from the tread rubber to the inner part of the tire or to the surroundings.

Effect of filler loading on cure time and swelling behaviour of SMR L/ENR 25 and SMR L/SBR blends

AbstractThe effect of filler loading on the cure time (t90) and swelling behaviour of SMR L/ENR 25 and SMR L/SBR blends has been studied. Carbon black (N330), silica (Vulcasil C) and calcium carbonate were used as fillers and the loading range was from 0 to 40 phr. Results show that for SMR L/ENR 25 blends the cure time decreases with increasing carbon black loading, whereas silica shows an increasing trend, and calcium carbonate does not show significant changes. For SMR L/SBR blends, the cure time of carbon black, silica and calcium carbonate generally decreases with increasing filler loading. The percentage swelling in toluene and ASTM oil no 3 decreases for both blends with increasing filler loading, with calcium carbonate giving the highest value, followed by silica‐ and carbon black‐filled blends. At a fixed filler loading, SMR L/ENR 25 blend shows a lower percentage swelling than SMR L/SBR blends.© 2003 Society of Chemical Industry

Multicomponent mass transfer across water films during hydrocarbon gas injection

Understanding the dynamics of pore-scale multicomponent gas and oil mass transfer across water films during hydrocarbon gas injection in petroleum reservoirs is important in the design of tertiary oil recovery schemes at the field scale. The water films prevent oil and gas coming into direct contact and, for miscible gas injection, delay the onset of miscibility. We use a pore-scale model to describe the diffusion-controlled mass transfer through the water films. The following different processes are found: (i) rapid oil swelling which results in short times needed to rupture the water films shielding the oil, (ii) slow oil swelling resulting in very long water film rupture times and (iii) both oil swelling and oil shrinking. The rate of oil recovery and the way it is recovered (either by rupturing the water film or being vaporized into the displacing gas) is critically dependent upon the oil and gas compositions, the oil droplet size and the water film thickness. We show cases at the pore scale where the time for gas and oil to be brought into direct contact and reach equilibrium in the presence of water films during miscible gas displacement is so long that water-blocking will adversely affect oil recovery at the field scale.

Solvent swelling studies of Göynük (Kerogen Type-I) and Beypazarı oil shales (Kerogen Type-II) ☆

The volumetric swelling procedure was applied to Göynük and Beypazarı oil shales from Turkey by using 10 solvents and the cross-linking in the macromolecular network of oil shales were investigated using this technique. Results from solvent swelling measurements show that the volumetric solvent swelling of oil shales samples roughly follows the regular solution theory. The theory of solvent swelling of cross-linked polymers developed Flory–Rehner and extension of this theory by Kovac–Peppas was used to calculate number average molecular weight per cross-link of kerogen structure ( M ̄ c ) in oil shale samples. Results indicate no remarkable difference between M ̄ c values for Göynük oil shale (Kerogen Type I) and Beypazarı oil shale (Kerogen Type II).

Towards self-lubricated nanocoatings

The microtribological performance of molecularly thick (<10 nm) thermoplastic elastomeric films grafted to a silicon surface was enhanced by adding a minute amount of paraffinic oil, which was adsorbed from vapor phase and held by the rubber matrix. We studied the kinetics of polymer swelling in oil and the formation of polymer gels. We observed that a vast majority of adsorbed oil evaporated from the ultrathin polymer coating leaving a minute amount of oil trapped within the rubber phase. This resulted in a dramatic enhancement of the microtribological performance of the grafted polymer gel layers. These polymer gel layers exhibited a very steady friction response and a small value of the coefficient of friction as well as greater wear-resistance as compared to the initial polymer coating. The performance of polymer gel coatings was much better than the performance of a classic ‘boundary lubricant’ for silicon surfaces, an alkylsilane self-assembled monolayer. The approach proposed demonstrated a new efficient route towards enhanced tribological performance of ultrathin polymer coatings.

Evaluation of the Miscibility and Contribution of Flue Gas to Oil Recovery Under High Pressure Air Injection

Abstract The improvement in the recovery of light oil by high pressure air injection (HPAI) involves a combination of complex processes, each contributing to the overall recovery. One of these processes is the spontaneous ignition of the air-oil mixture with complete oxygen utilization. This process generates flue gases, which are in contact with the reservoir oil at the displacement front. An experimental study was carried out to investigate the mechanism and contribution of miscible displacement, by in situ generated flue gases, to the recovery of light oil in reservoirs undergoing HPAI. The flue gas displacements were carried out on recombined reservoir oil in a slim tube apparatus at a reservoir temperature of 116 º C and pressures ranging from 27.77 MPa (4,028 psi) to 46.06 MPa (6,680 psi). Results show that miscibility could not be achieved between the test oil and flue gases under the test conditions. Experiments conducted between 41.28 MPa (5,987 psi) and 45.04 MPa (6,532 psi), however, gave an indication of near-miscible displacement of the test oil. The flue gases displaced the oil in a forward contacting extraction process, resembling a combined vapourizing/condensing multi-contact gas drive mechanism. The relatively high recovery, high extraction of oil components, and the pattern of flow behind the displacement front, exhibited at high pressures, demonstrate that near-miscible displacement by in situ generated flue gases could significantly contribute to oil recovery in light oil reservoirs undergoing HPAI. Introduction Air injection into high pressure reservoirs is an emerging technology for the enhanced recovery of light oils. It is probably the best hope for improved recovery from the world's ever declining reserves of conventional oil and, in particular, the profitable enhanced recovery of the enormous quantities of residual oil trapped in depleted and mature waterflooded light oil reservoirs(1, 2). Air is the most inexpensive, available gas that can be used to accelerate oil recovery. Air injection is especially applicable in low porosity and low permeability reservoirs where water injectivity is extremely low(3). Apart from providing a better interfacial tension (IFT) response(4), air injectivity is about ten times that of water in terms of reservoir volume(5), making air injection more advantageous than water injection in deep, tight, high pressure reservoirs. A number of successful high pressure air injection projects in light oil reservoirs have been documented in the literature(5–11). Most of these projects have been operating for many years, attesting to their technical and economic success. The improvement in recovery of light oil by HPAI involves a combination of complex processes, each contributing to the overall recovery. These processes include: reservoir pressurization, oil swelling, immiscible gas displacement, and superextraction when operating above the critical point of water. In addition to this, spontaneous oil ignition with complete oxygen utilization(2, 12, 13) and near-miscibility/miscibility of the in situ generated flue gases with the reservoir oil(13) are possible and advantageous processes. Apart from reservoir pressurization, oil swelling, and immiscible gas displacement, the mechanism by which the other processes occur in the reservoir and their contribution to oil recovery have not been discussed in clear terms in the technical literature(14).

Flue Gas Injection for Heavy Oil Recovery

Abstract A majority of heavy oil reservoirs in Saskatchewan are thin and shaly, and are not suitable for thermal recovery methods. For these reservoirs, enhanced oil recovery by an immiscible gas process could potentially recover an additional 200 million m3 of oil. This paper presents the results of a laboratory investigation, including pressure-volume-temperature studies and twodimensional physical model experiments, for evaluating the flue gas injection process for heavy oil recovery. The study examined the effects on viscosity reduction and oil swelling of the presence of O2 and of CO2 content in the flue gas. Physical model tests were carried out to investigate the effects on oil recovery of injection rate, injection mode (vertically downward, vertically upward, and horizontal injection), and slug size. The free-gas mechanism in the flue gas injection process was also studied. Introduction In Saskatchewan and Alberta, there are many thin-pay, heavy and medium oil reservoirs that are unsuitable for thermal recovery techniques. The estimated recovery by primary production and secondary methods is only about 5 - 8% of the initial oil-in-place (IOIP) for the heavy oil reservoirs and about 25% IOIP for the medium oil reservoirs(1). For these reservoirs, enhanced oil recovery (EOR) by an immiscible gas process offers a strong potential to recover more oil. It could, according to previous studies(2–6), recover up to an additional 30% IOIP incremental over that recovered by initial waterflood for some moderately viscous oils. Flue gas injection for heavy oil recovery received a great deal of attention in the 1960s(7, 8). However, it has not been studied in detail. A previous comparative study on immiscible gas injection agents for heavy oil recovery showed that CO2 is the best recovery agent among the three gases tested, and produced gas is slightly more effective than flue gas(9). CO2 has a higher solubility in oil and higher viscosity reduction efficiency than the other two gases. From the theory of fractional flow for viscous fingering(10), it is expected that CO2 will give field applications a better sweep efficiency than the other two gases. However, natural CO2 sources are not available to most oil reservoirs. The cost for CO2 capture from flue gas and other sources may range from $25 to $70/tonne(11). Produced and flue gases are available in large quantities at a much lower cost. With this consideration, produced gas and flue gas can be economically effective agents for heavy oil recovery by immiscible gas injection(9). In a previous study(9), linear coreflood tests were conducted with live and dead Senlac oil/flue gas to compare the relative effectiveness of secondary vs. tertiary flooding and WAG vs. slug injection. In these tests, a total of 0.40 PV flue gas was injected either as a continuous slug in slug floods or in a WAG mode. In secondary tests, gas was injected into the oil-saturated sandpack, whereas in the tertiary injection mode, it was injected into the initially waterflooded core. The WAG tests employed a WAG ratio of 4:1, an even slug size, and a 4-cycle operation.

A New Bimetallic Complex Catalyst for NBR Hydrogenation and Properties of Hydrogenated NBR

A new homogeneous bimetallic catalyst, based on Rh-Ru compounds, for the hydrogenation of acrylonitrile-butadiene copolymer(NBR) has been prepared. This paper described a study of the catalyst preparation and its hydrogenation process of NBR. The hydrogenation catalytic activity and selectivity of this bimetallic catalyst system (BMSC)was compared to two catalysts, RhCl(PPh3)3 and RuCl2(PPh3)3. NBR and hydrogenated NBR(HNBR) have also been characterized by infrared spectrum. The results showed that this new bimetallic complex catalyst offers good catalyst activity and excellent selectivity in NBR hydrogenation process to produce a highly saturated (98%) HNBR without gel formation. In addition, properties of the vulcanized HNBR have high tensile strength, elongation, tear strength and low permanent set. Its hot air ageing performance and oil swell test indicate that this HNBR is as good as those of current commercial products. Moreover, this new bimetallic complex catalyst, in conjunction with metal recovery system developed in this laboratory offers potential economic advantage in industrial applications.

Preparation and properties of thioglycollic acid modified epoxidised natural rubber and its blends with natural rubber

Solution prepared epoxidised natural rubber (ENR) was modified while still in solution with thioglycollic acid (TGA) (0.3 mol phr) to yield a material with 17% conversion of its initial NR epoxide. This material (ENR–TGA) and its blends with natural rubber were black filled and vulcanised using the semi-EV system. The modified ENR material exhibited low tensile strength (4.4 MPa), but showed better resistance to solvent and mineral oil than a similar natural rubber compound. Blending natural rubber with the modified ENR material at a level of 10 parts ENR–TGA phr increased the modulus values by 46%. At the aforementioned blend composition, the hardness and resistance to swelling in solvents and mineral oil were also increased, but the reverse were the case for tensile strength and elongation at break. Cure behaviour and flex-cracking properties of the blends were also studied.