Oil Swelling Research Articles

Flory‐Huggins solution theory for heavy oils

AbstractThe addition of a solvent to heavy crude oil causes reduction in its viscosity and facilitates extraction. Existing data on swelling of oil in the presence of solvent in vapour form have been analyzed using the Flory‐Huggins theory. The model uses volume fractions and hence problems related to an appropriate average molecular weight of oil to use in the calculations are avoided. The data expressed in terms of swelling as a function of solvent partial pressure fit well with the model when the solvent vapour can condense and is miscible with oil or immiscible with oil or even when condensation is not possible. We are also able to predict when phase separation can occur (which we take to be asphaltene precipitation) in the solution although the above experiments have not looked at this aspect.

Design and properties of high-performance polyamide 6/fluoroelastomer blends by electron-induced reactive processing

In recent years, electron-induced reactive processing (EIReP) has emerged as a state-of-the-art technology to modify and develop several kinds of polymeric materials. EIReP uses the spatial and temporal tuneable energy input by high energy electrons during melt mixing process in order to precisely control the desired chemical reactions and processability. Motivated by the successful development of high performance polyolefin based compounds by EIReP, we report herein for the first time the successful preparation of high-performance polyamide 6/fluoroelastomer (50/50, w/w) blends. Relationships between EIReP process parameters (non-reactive mixing time, dose per revolution, electron energy), morphology and properties of blends were established. The blends were prepared using a range of absorbed dose (12.5, 17.5 and 25kGy) while keeping constant values of electron energy (1.5MeV), dose per revolution (17.2kGy/rpm), temperature (230°C) and rotor speed (60rpm). The EIReP-modified blends exhibited excellent mechanical properties and outstanding oil swelling resistance along with good thermal stability. For example, volume swell of the blends was only 5–8% in IRM oil at 150°C for 72h, which was found to be the lowest amongst this type of rubber-plastic blends reported. The improved properties of these blends were explained with the help of interfacial tension between the phase components and electron-induced long-chain branching.

Effects of Nanoparticles on Gas Production, Viscosity Reduction, and Foam Formation during Nanofluid Alternating Gas Injection in Low and High Permeable Carbonate Reservoirs

AbstractSome carbonate reservoirs are low‐permeable and mixed‐wet to oil‐wet. Application of enhanced recovery methods to decrease residual oil saturation is the main challenge in such reservoirs. Water‐flooding is not an appropriate method to improve the recovery due to the wettability of carbonate reservoirs. Water alternating gas (WAG) injection is used as another method but it faces some problems. To enhance the performance of the WAG method, the wettability of rock should be changed and mobility of the injected gas should be controlled.In our previous study (Moradi et al.[32]), to improve the WAG‐EOR process and overcome the problems, we developed the nanofluid‐alternating gas (NWAG) approach by adding nanoparticles to the aqueous phase. Our study indicated that the NWAG process could improve oil recovery in comparison to the conventional WAG method in different core samples with different lithology and permeability. In this study, core‐flooding experiments, dynamic foam generation, and viscosity measurement were performed to investigate the effect of nanoparticles on gas production, viscosity reduction, and possibility of foam formation in the NWAG process. The results indicated that the gas production was decreased in the NWAG process. In addition, viscosity of produced oil was lower in the NWAG process; CO2 dissolved in the oil and led to oil swelling and oil viscosity reduction. Oil recovery was higher in the samples with lower permeability due to the formation of foam in the porous media. Foam formation increased viscosity and controlled mobility, which led to better sweep efficiency.

Effect of flue gas and n-hexane on heavy oil properties in steam flooding process

Heavy-oil reservoirs with thin-pay and bottomwater can be exploited effectively by thermal recovery process assisted by flue gas and n-hexane. The interface properties between flue gas/n-hexane and heavy oil and viscosity reduction of the heavy oil were investigated by laboratory experiments. Steam flooding, flue gas assisted steam flooding, n-hexane assisted flooding and flue gas and n-hexane assisted steam flooding were conducted to research the displacement pressure difference, oil displacement efficiency and component variation of produced and residual oils. The results show that the flue gas dissolving in heavy oil can effectively reduce oil viscosity, increase the flow capability, and make the heavy oil swell. Higher pressure reduces surface tension of heavy oil and gas, and higher temperature increases surface tension. Compared with flue gas, n-hexane can reduce heavy oil viscosity and surface tension more obviously. The flue gas and n-hexane can effectively improve the development effect of the steam flooding. The pressure difference of steam flooding assisted by flue gas and n-hexane is the lowest, the oil production rate is greatest, and the oil recovery efficiency can reach 80%. Flue gas and n-hexane can effectively change crude oil properties. The heavy components, molecular weight of asphaltene and oil viscosity for the produced oil all reduced. The heavy components and molecular weight of asphaltene for the residual oil in sandpacks all increased. The effect of flue gas and n-hexane together on heavy oil is the greatest. The asphaltenes component in the residual oil is not as stable as that in produced oil. The experimental results not only show that flue gas and n-hexane can successfully improve the performance of steam flooding process, but also provide a deep understanding of properties changes of produced and residual oils for the flooding.

Synthesis and evaluation of physicochemical properties of anionic polymeric surfactant derived from Jatropha oil for application in enhanced oil recovery

In this study an attention has been paid to synthesize polymer grafted anionic surfactant (PMES) derived from nonedible vegetable oil (Jatropha) for its application in enhanced oil recovery (EOR). The polymeric surfactant was prepared by reacting acrylamide monomer with methyl ester sulfonate (MES) synthesized from Jatropha oil by free radical polymerization mechanism. Polymeric surfactant with properties of both surfactant and polymer can control the mobility ratio and reduce interfacial tension (IFT), which are desirable for EOR. The synthesized polymeric surfactant was characterized through FTIR, 1H NMR, FESEM, EDX, TGA, DLS analysis. The effectiveness of PMES for chemically enhanced oil recovery process was investigated by measurement of physiochemical properties of its aqueous solution viz. reduction of IFT, wettability alteration and rheological behaviour. Rheological studies shows shear thinning behaviour with apparent viscosity comparable to conventional polymers. The IFT between crude oil and aqueous PMES solution at its critical micelle concentration (CMC) was observed as 2.74mN/m, which was further reduced to 0.37mN/m on addition of 2.5wt% NaCl. Core flooding experiments were conducted in sandpack system, to study the EOR efficiency using the synthesized polymeric surfactant and more than 26% additional recovery was observed after usual water flooding. Higher recoveries at higher temperature were observed because of swelling of crude oil and lowering of IFT.

Compositional modeling of hybrid CO2 EOR with intermediate hydrocarbon solvents to analyze the effect of toluene on asphaltene deposition

Once asphaltenes have been precipitated from oil due to pressure, temperature, or oil composition changes, they can affect reservoir performance by reducing porosity and permeability and altering wettability. Moreover, they can cause plugging of wellbore and surface production facilities. The addition of liquefied petroleum gas (LPG) into the CO2 stream during CO2 flooding reduces oil viscosity, interfacial tension (IFT), and oil swelling, resulting in improved displacement efficiency, but also causes asphaltene precipitation because of a change in oil composition. When toluene is introduced into the LPG and CO2 stream to overcome the limitations of a CO2-LPG flood, it acts as an inhibitor of asphaltene precipitation. This research systematically examines the mechanism of asphaltene precipitation and how to mitigate problems associated with asphaltene deposition based on compositional simulations. Solid deposition model that included adsorption, pore throat plugging, and re-entrainment was considered. A compositional equation of state (EOS) model was developed to analyze the effects of LPG and toluene on asphaltene deposition and formation damage. At the center of reservoir, the amount of asphaltene deposition reached the maximum for 10% LPG-added CO2-LPG flooding, which was 12% higher than that from CO2 flooding. When 1% toluene was added into the CO2-LPG flood, the amount of asphaltene deposited declined by 2%. Oil resistance factor had the same tendency because of porosity reduction due to decreased deposition of asphaltene. Oil recovery for the CO2-LPG flood was enhanced by 4% compared to the CO2 flood, despite an increment in asphaltene deposition, and by 9% for the CO2-LPG-toluene flood. Results from this study indicate that LPG addition causes increased asphaltene deposition, which can be mitigated by using toluene as an inhibitor.

Experimental investigation of tertiary CO2 injection for enhanced heavy oil recovery

The recovery efficiency of primary production for heavy oil reservoirs is generally poor meaning that significant quantities of oil still remain in place. Waterflood has been, and continues to be, the first intervention method for oil recovery in many oil reservoirs. However, heavy oil is considerably more viscous than water and hence, a significant fraction of the oil is bypassed by waterflood. In this study, we present the results of two coreflood experiments which have been performed under reservoir conditions to investigate the potential of tertiary CO2 injection for heavy oil recovery. In addition, the mechanisms involved in this process and their impacts on the efficiency of oil recovery are identified and discussed. The same crude oil and gas were used to prepare live oil for both experiments. Despite the difference in the viscosity of oil samples, secondary waterflood showed relatively similar behavior in both experiments and 22% and 24% of the initial oil were recovered after 2 and 1.1 pore volumes (PVs) of water injection in the first and second experiments, respectively. The oil production results show that tertiary CO2 injection recovered 23% of the remaining oil after 6 PVs of injection in the first experiment and after 3 PVs of injection in the second experiment. Another waterflood followed the tertiary CO2 injection which recovered 14% of the remaining oil in both experiments.The main mechanisms contributing to oil recovery by CO2 injection are the oil viscosity reduction by CO2 dissolution, the liberation of methane from oil, oil swelling, and the extraction of hydrocarbons by CO2. The results imply that viscous fingering dominates the flow of water or CO2 for heavy oil recovery. The compositional analysis of the core effluent shows that tertiary injection of CO2 alters the physical properties of heavy oil in the core and a higher quality oil (e.g. lower density and viscosity) than the original oil in place is recovered by CO2 injection. It is also discussed that CO2 can diffuse into the oil surrounded by water. The transport of CO2 into the oil results in the oil being saturated and this leads to the nucleation of a CO2−rich phase among the trapped oil ganglia. By continuing CO2 injection, the nucleated CO2−rich phase grows further and causes oil swelling by the extraction of light and intermediate components of the oil.

Performance evaluation of water-swelling and oil-swelling elastomers

Swelling elastomers are special polymers that increase in volume when exposed to water or oil. They have been successfully deployed in oil and gas wells for isolation of water-producing zones, partial replacement of cementing, slimming down of wells, and so on. Performance appraisal and design modifications cannot be attempted without knowledge of material response under specific field conditions. Results from an experimental investigation are presented here about the behavior of two commercial elastomers, one water swelling and one oil swelling. Of the one-month total testing time, one set of samples (for each elastomer type) was tested under acid for one day, and the other set without any acid exposure. Readings were taken at different stages of swelling to record the variation in volume, thickness, and hardness of elastomer samples. Test parameters were set to match existing conditions in a regional oil well. These results can be used to assess performance of elastomers under given well conditions and for modeling and simulation of seal behavior.

Features of rubber swelling in transformer oil, according to NMR data

NMR spectroscopy, NMR relaxation, and NMR with a pulsed magnetic field gradient methods are used to study the swelling of the elastomers based on ethylene-propylene rubber, butadiene-nitrile rubber, and fluororubber SKF-26 in transformer oil. Components corresponding to the fractions of oil and polymer network are identified. It is shown that the affinity of the polymers toward transformer oil displays an increase in the orderly sequence of ethylene-propylene rubber, fluororubber, and butadiene-nitrile rubber; the stability of the polymers towards carbon tetrachloride falls in the same sequence. Based on an analysis of the spin–spin relaxation time depending on the degree of swelling, it is found that fluororubber elastomers are characterized by the formation of a polymer network that prevents further sorption, In contrast, elastomer based on ethylene-propylene rubber gives no indication of the formation of a rigid polymer network.

Simulation of carbonated water injection coreflood experiments: An insight into the wettability effect

In this paper, our previously developed model (simulator) has been used to simulate and study a different CWI coreflood experiment from the literature performed in a mixed-wet sandstone core. The developed model that was based on mass transfer kinetics had been used before to simulate a coreflood experiment performed in a water-wet sandstone rock. In this paper, a different procedure has been applied for the simulation of CWI in the mixed-wet core. That is, in contrast to the water-wet coreflood test where only mass transfer parameter was tuned, here, both mass transfer parameter and relative permeability curves have been obtained through a history matching experiment applying our genetic algorithm (GA) based optimization program. Furthermore, using the simulation results, it has been observed that in addition to oil swelling and contrary to the water-wet core, wettability alteration is also an important recovery mechanism for the mixed-wet core. The potential of CO2 storage during the mixed-wet CWI coreflood experiment has also been investigated. The results obtained in this paper can help to crosscheck and verify the performance of the developed simulator and also to explore its generic capability. Moreover, the results of this paper give an insight into different recovery mechanisms contributing during CWI coreflood experiments.

Experimental investigation of the influence of supercritical carbon dioxide and supercritical nitrogen injection on tertiary live-oil recovery

Generally, there are different enhanced oil recovery (EOR) methods. One of the most promising EOR method is the gas injection especially carbon dioxide (CO2) injection since it introduce several unique characteristic desired for higher tertiary oil recovery. In this study, the performance and feasibility of supercritical carbon dioxide (SC-CO2) and supercritical nitrogen (SC-N2) injection to enhanced oil recovery was investigated. In this regard, swelling tests and core flooding experiments were performed to find out whether the injections of these gases are efficient to recover trapped oil in the reservoir. Based on the experimental results, the possible active mechanisms were discussed on both displacements. The results of swelling tests showed that SC-CO2 yields the swelling factor up to about 35%, while the oil swelling factor by SC-N2 is just about 8%. The core-flooding experimental results demonstrated that SC-CO2 injection could recover 15.8% of the original oil in place (OOIP), while SC-N2 injection ultimate oil recovery would be up to 8.7% of the OOIP.

A Review of CO2-Enhanced Oil Recovery with a Simulated Sensitivity Analysis

This paper reports on a comprehensive study of the CO2-EOR (Enhanced oil recovery) process, a detailed literature review and a numerical modelling study. According to past studies, CO2 injection can recover additional oil from reservoirs by reservoir pressure increment, oil swelling, the reduction of oil viscosity and density and the vaporization of oil hydrocarbons. Therefore, CO2-EOR can be used to enhance the two major oil recovery mechanisms in the field: miscible and immiscible oil recovery, which can be further increased by increasing the amount of CO2 injected, applying innovative flood design and well placement, improving the mobility ratio, extending miscibility, and controlling reservoir depth and temperature. A 3-D numerical model was developed using the CO2-Prophet simulator to examine the effective factors in the CO2-EOR process. According to that, in pure CO2 injection, oil production generally exhibits increasing trends with increasing CO2 injection rate and volume (in HCPV (Hydrocarbon pore volume)) and reservoir temperature. In the WAG (Water alternating gas) process, oil production generally increases with increasing CO2 and water injection rates, the total amount of flood injected in HCPV and the distance between the injection wells, and reduces with WAG flood ratio and initial reservoir pressure. Compared to other factors, the water injection rate creates the minimum influence on oil production, and the CO2 injection rate, flood volume and distance between the flood wells have almost equally important influence on oil production.

Experimental investigation of CO2 huff-n-puff process for enhancing oil recovery in tight reservoirs

Due to the feature of tight formation, the primary oil recovery is usually very low and leaves substantial oil still in place. This fact results in a strong motivation of applying an enhancing oil recovery (EOR) method to further increase the oil recovery. In the present work, CO2 huff-n-puff process as a potential EOR method for tight oils was experimentally investigated in 0.3md cores. The visual tests proved that the oil swelling factor and CO2 solubility increased with pressure. The core tests indicated that CO2 huff-puff process is a viable technique to promote tight oil recovery. The magnitude of oil recovery is strongly dependent on CO2 pressure, the oil recovery can reach 30.9% at 16MPa in our experiment. Compared multi- to single-cyclic operation, the oil recovery is further increased by 10% by a four-cycle operation. However, after two cycles, the oil recovery significantly dropped. Differential production pressure (ΔP) is the dominant parameter for tight oil recovery in CO2 huff-puff process. This work is supposed to provide some necessary clues for pilot design.

Synthesis of polystyrene-silica nanoparticles via RAFT emulsifier-free emulsion polymerization

Polystyrene-silica (PS-co-RAFT-SiO2) nanoparticles were synthesized via reversible addition-fragmentation chain-transfer (RAFT) emulsifier-free emulsion polymerization using poly (styrenesulfonate-sodium)-RAFT agent (macro-RAFT agent). The effects of macro-RAFT agent to initiator ratio on monomer conversion, particle size, particle size distribution, grafting efficiency and silica encapsulation efficiency were investigated. The particle size decreased with increasing macro-RAFT agent to initiator ratio ([R]:[I]). The PS-co-RAFT-SiO2 nanoparticles exhibited a size range of 23–56nm with a narrow size distribution for all polymerizations, ⩾99% monomer conversion was achieved. The PS-co-RAFT-SiO2 nanoparticles showed spherical particles with a core-shell morphology as confirmed by TEM photographs. The PS-co-RAFT-SiO2 nanocomposite could be used as filler in natural rubber. Accordingly, NR/PS-R-SiO2 blends had improved thermal and mechanical properties, and also exhibited good oil swelling resistance.

Experimental investigation of the use of the dimethyl ether/polymer hybrid as a novel enhanced oil recovery method

Injection of dimethyl ether (DME) dissolved in water can enhance the recovery efficiency with respect to water flooding. In this Shell Proprietary Technology, DME partitions from water into the oil; decreases oil viscosity and increases its volume, and mobilizes the trapped oil again. In this work, DME-enhanced water flooding is combined with polymer and considered for cases in which a favorable mobility control between water and oil does not exist. In order to reduce the remaining oil, slugs of the mixed solution of DME and polymer were injected into the cores containing oil and then followed by injection of a chase fluid. This recovery method benefits both (a) from the presence of polymer, and the oil viscosity reduction caused by DME dissolution and (b) from oil swelling due to DME dissolution. It appears from experimental data that the injectivity of a DME/polymer (DMEP) solution is higher than the injectivity of a polymer solution without DME; this indicates the presence of DME can reduce the viscosifying effect of the polymer. The main experimental observations are: (1) a higher oil recovery is obtained from continuous DMEP flooding than from continuous DME–brine flooding, (2) the presence of polymer in the DME slug and in the chase phase reduced the remaining oil after a finite slug injection, and (3) a larger DME slug and mobility control of the chase phase can improve the oil recovery after a finite slug injection. In summary, the experiments show that combining polymer and DME improves the ultimate recovery significantly and shortens the duration of oil production.

Experimental study of the properties of brake pad using egg shell particles–Gum Arabic composites

This experimental study investigated the properties of eco-friendly (biodegradable) brake pad using egg shell (ES) particles and Gum Arabic (GA) as the binder in order to replace asbestos and formaldehyde resin which are carcinogenic in nature and not biodegradable. The brake pad formulation was produced by varying the GA from 3 to 18 wt%. The following properties were tested: wear rate, hardness values, compressive strength, thickness swelling in water and SAE oil, thermal resistance and specific gravity. The microstructure of the brake pad showed that fair bonding was achieved with the formulations from 15 to 18 wt% of GA. The sample with 18 wt% of GA in ES particles gave the best properties. The temperature of maximal decomposition of ES particles was higher than asbestos and many agro-wastes currently used in the production of brake pad materials. The results obtained at 18 wt% of GA in ES particles formulation compared favourably with the commercial brake pad. Hence, the developed brake pad can be us...

Numerical simulation of CO2 huff-n-puff in complex fracture networks of unconventional liquid reservoirs

Horizontal drilling and hydraulic fracturing produce Unconventional Liquid Reservoirs (ULRs) economically. One of the characteristics of the ULRs is high production declining rate, and thus enhanced oil recovery techniques such as Huff-n-Puff will ensue. In addition, the existence of complex fracture network has been proven by both field and simulation work. This study investigated the potential of CO2 huff-n-puff in ULRs with complex fracture networks. Two fracture characterization techniques for complex fracture network such as fractal-based, and microseismic-based were applied to reduce uncertainties of fracture networks and thus improve the accuracy of simulation input. In order to study complex CO2 recovery mechanism, lab-measured data was upscaled to the field-scale, and then used for evaluating production performance of a simple fracture network. Detailed sensitivity analysis showed that diffusion in the field scale is negligible compared with other recovery mechanisms such as oil swelling, gas expansion, viscosity reduction, etc. The following comparison between dual continuum and the explicit fracture modeling approaches highlights the importance of heterogeneity due to the explicit fractures. Dual continuum models yields less accurate pressure behavior than explicit discrete fracture models even though production behavior could be history matched.

The influence of spreading coefficient on carbonated water alternating gas injection in a heavy crude oil

The interfacial properties change strongly with temperature and pressure that could influence the displacement of fluids in porous media. The main objective of this study was to measure interfacial tension (IFT) of the binary systems of brine/crude oil/carbon dioxide (CO2) and carbonated brine/crude oil/CO2 at two temperatures and different pressure conditions. Spreading coefficient (SC), which is determined from IFT data, is an important parameter in enhanced oil recovery (EOR) methods, which are based on three phase systems. The spreading or non-spreading (the oil creates to form an immobile half sphere) oil on the water–gas interface is a key factor on determining residual oil saturation during water alternating gas (WAG) injection process. In this work, experimental results on oil swelling and interfacial tension of crude oil, brine/carbonated brine and carbon dioxide systems at the pressure range of 2.76–13.79MPa and two temperatures of 40°C and 50°C is presented. Afterwards, by estimating spreading coefficient of the mentioned systems an optimum condition for the enhanced oil recovery (EOR)-WAG process is proposed.The results indicate that, the equilibrium IFT data of the carbonated brine–crude oil system is lower compared to that of the brine–crude oil system at the same conditions. The interfacial tension of the carbonated brine–crude oil system decreases significantly at higher pressures. In addition to IFT reduction due to the presence of CO2 in water, oil swelling was also observed. In this experimental work, the dynamic oil swelling was monitored as a function of time. The IFT data of the above systems were also used to estimate the spreading coefficient as a function of pressure at both temperature conditions. The estimated spreading coefficient data for the brine/crude oil/CO2 and carbonated brine/crude oil/CO2 systems, indicates that the presence of CO2 in the brine phase, makes the spreading coefficient positive, while this parameter in the brine/oil/CO2 system is negative. This means that oil would be spread on the water phase during carbonated water alternating CO2 injection that consequently could further enhance oil recovery.

Swelling and Viscosity Reduction of Heavy Oil by CO2-Gas Foaming in Immiscible Condition

Summary In this study, foaming of heavy oil generated by depressurization from saturated carbon dioxide (CO2) solution was studied because generating foamy oil has a possibility of developing an enhanced oil recovery (EOR). The experiments were carried out by with a heavy crude oil at CO2 pressure less than 10 MPa and a temperature from 20 to 50 °C. The swellings of the generated foamy oils increased from 36.8 to 47.5% with reducing viscosity ratio from 79 to 42%, comparing with original viscosity. Furthermore, the investigation shows that CO2 microbubbles in the foamy oil started nucleating at pressure less than 8.0 MPa during depressurization from the saturation pressure of 9.97 MPa at 50 °C, and the foamy oil started decreasing the apparent viscosity. By exposing generated foamy oil under the shear rate of 76.8 seconds−1 for 5 minutes, the bubble-volume density profile changes from broadband toward to Gaussian distribution caused by disappearing larger size of gas bubbles, where bubble diameter of the maximum probability density of the bubble-volume distribution reduced from 80 μm to less than 10 μm. However, reduction of viscosity ratio was almost kept even though the distribution was changed; this shows that apparent viscosity strongly depends on the microbubbles sized less than 10 μm in diameter. It was expected that CO2 foamy oil has a potential to improve the recovery ratio of heavy oil by making the residual oil flow out from the immobile zones because of its large apparent swelling and improving mobility in porous oil-flow.

Optimal Design of Low-Temperature Air Injection with Propane for Efficient Recovery of Heavy Oil in Deep Naturally Fractured Reservoirs: Experimental and Numerical Approach

Low-temperature air/solvent injection (LTASI) can be a possibility if injected air/solvent into a fractured reservoir diffuses into the matrix effectively to oxidize oil in it while reducing its viscosity by temperature and solvent dissolution. However, early breakthrough of air with partial consumption of oxygen as a result of the highly conductive nature of the reservoirs is a concern. Once it is controlled by a proper injection scheme and consumption of air injected through efficient diffusion into the matrix, low-temperature air injection (LTAI) can be an alternative technique for heavy-oil recovery from deep naturally fractured reservoirs (NFRs). Limited number of studies on light oils showed that this process was highly dependent upon the oxygen diffusion coefficient and matrix permeability. In this process, oil production is governed by drainage and stripping of light oil components, which have a greater effect on recovery than the swelling of oil. In the present study, static laboratory tests were...