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Viscosity reduction through heat transport from steam to bitumen is one of the most important recovery mechanisms of a steam-assisted gravity drainage (SAGD) process. Both heat convection and conduction contribute to the heat transport. Although conduction is considered as dominant through most of a SAGD process, an understanding of heat convection, especially accurate modeling of a condensate convection velocity, is still limited in the literature. This paper develops a mathematical model for the transient heat transfer beyond a steam chamber boundary in SAGD. A convection velocity is clearly formulated, which requires the coupling of heat transport and pressure diffusion. Calculation results show that in SAGD, convection plays a minor role than conduction. In addition, the relative contribution of convection can be influenced by reservoir formation compressibility, steam chamber boundary advancing velocity, and particularly by a difference between steam injection pressure and reservoir initial pressure. Correlations are regressed to estimate the relative contribution of heat convection (ratio) in the overall heat transfer process during a stabilized production period of SAGD.

The manipulation of a nanoconfined fluid flow is a great challenge and is critical in both fundamental research and practical applications. Compared with chemical or biochemical stimulation, the use of temperature as controllable, physical stimulation possesses huge advantages, such as low cost, easy operation, reversibility, and no contamination. We demonstrate an elegant, simple strategy by which temperature stimulation can readily manipulate the nanoconfined water flow by tuning interfacial and viscous resistances. We show that with an increase in temperature, the water fluidity is decreased in hydrophilic nanopores, whereas it is enhanced by at least four orders of magnitude in hydrophobic nanopores, especially in carbon nanotubes with a controlled size and atomically smooth walls. We attribute these opposing trends to a dramatic difference in varying surface wettability that results from a small temperature variation.

This paper presents an alternative semi-analytical model which is able to integrate PVT properties of gas with dynamic pressure domain during production process. A modified three-region radial composite model is developed to evaluate the gas condensate reservoir, taking account of different gas flow behaviors and pressure dependent properties, such as the compressibility factor. The governing equation of the pressure diffusion process is highly nonlinear due to the complex dependence of coefficients on pressure. The linearization of the non-linear partial differential equation describing the complicated gas flowing in a reservoir is handled by application of reasonable definitions of pseudo-pressure and pseudo-time for each region, which is integrated into the reservoir system through physical continuity of changing phases with PVT properties. Modified forms of total compressibility factor are proposed by valid theoretical developments. Results show that gas compositions of a gas condensate reservoir have significant effects on the fluid flow behaviors. Different proportions of C 5 , C 6 and C 7 + are simulated with constant makeup of C O 2 , N 2 and C 1 ∼ 4 , showing that small changes in composition of heavier components make distinct differences in the flow behaviors, as reflected on the liquids dropout curves. In addition, total compressibility factor varies with fluid compositions instead of remaining constant in a gas condensate reservoir. Through integrating PVT behaviors, the three-region model is able to accurately describe transient pressure behaviors of a production well in a gas condensate reservoir, which clearly characterizes three regions on the pressure derivative curves. A series of sensitivity studies are conducted to analyze the differences among the three regions.

Viscosity reduction through solvent dissolution into heavy oil is one of the most important recovery mechanisms of a vapour extraction (VAPEX) process. Existing analytical models can neither accurately describe the mass transfer between solvent vapour and heavy oil nor predict the solvent chamber evolution. Simulation models are confounded by numerical dispersion and have a difficulty in accurately characterizing fluid properties in VAPEX. This study first develops a mass transfer model to describe a dynamic heavy oil–solvent mixing process. This model is then incorporated into a VAPEX model to estimate solvent chamber development and an oil production rate. Diffusivity is determined through history matching theoretically calculated and experimentally measured cumulative oil production data. It is found that both constant and variable diffusivities can achieve excellent match in cumulative oil production data. However, their respective characterization of the fluid properties in the VAPEX transition zone is very different. This study also proposes a method to convert constant diffusivity into its equivalent variable diffusivity for VAPEX by using some regressed correlations. Moreover, the back-calculated effective diffusivity is found to be about 10–30 times of the corresponding molecular diffusivity measured in the laboratory. This article is protected by copyright. All rights reserved

Steam-assisted gravity drainage (SAGD) is one of the most popular approaches for oil sands recovery. In this study, an accurate and simple heat efficiency calculation model is presented by modeling transient heat transfer involving the flow of both hot condensate and mobile initial water in oil sands. A 2-D numerical simulation procedure is proposed to calculate temperature distribution ahead of the steam chamber edge in SAGD. A new heat efficiency model is proposed to estimate heat efficiency in SAGD by using the temperature distribution obtained from the 2-D numerical simulation. Results indicate that convection dominates the heat transfer ahead of the steam chamber edge which is induced by condensate and initial water flow in oil sands. On the basis of these studies, abundant analysis shows that the heat efficiency of SAGD can be improved by using moderate steam injection pressures for the reservoir scenarios from 1 to 10 darcy permeability.

In a vapor extraction (VAPEX) process, a vaporized solvent (such as light alkanes) is injected underground to dilute and recover heavy oil. A solvent chamber forms due to the depletion of oil, and goes through three phases: rising, spreading, and falling phases during a VAPEX process. Existing analytical models of VAPEX can only roughly estimate an oil production rate but are unable to accurately describe the solvent chamber evolution. Simulation models are somewhat unreliable due to extremely small physical diffusivity and relatively large numerical dispersion. This study develops a comprehensive mathematical model for the VAPEX process to characterize a transition zone and describe the solvent chamber evolution. Major recovery mechanisms occurring in the transition zone such as dynamic mass transfer, gravity drainage, multiphase flow, and surface renewal are accounted for in the model. Modeling results show that the solvent concentration in the transition zone grows slower at the top than at the bottom while rather stable at the middle along the drainage surface. In addition, it is found that a stabilized oil production rate depends on the square root of a heavy oil–solvent effective diffusion coefficient. Moreover, this new VAPEX model can accurately describe the relationship between oil production rates and diffusion coefficients in different scales thanks to the absence of numerical dispersion.

Jing Liang,1,* Xinfeng Jia,2,* Kun Wang,3,* Niankun Zhao4 1Department of Oncology, Tianjin Binhai New Area Dagang Hospital, Tianjin 300270, China; 2Geriatrics Department, Tianjin Civil Affairs Bureau Geriatric Hospital, Tianjin 300111, China; 3Department of Genitourinary Oncology, Tianjin Medical University Cancer Institute and Hospital, National Clinical Research Center for Cancer, Key Laboratory of Cancer Prevention and Therapy, Tianjin, Tianjin’s Clinical Research Center for Cancer, Tianjin 300030, China; 4Department of Internal Medicine, Tianjin Binhai New Area Dagang Hospital, Tianjin 300270, China *These authors contributed equally tothis work Objectives: The transcription factor EB (TFEB), a member of the micropthalmia family, has been found to be associated with autophagy and upregulated in some kinds of tumors. However, very few studies focused on TFEB in colorectal cancer (CRC). TFEB expression status and its relevance to clinical features in CRC would be analyzed in this study.Materials and methods: Real-time PCR, Western blot, and immunohistological staining were used to evaluate TFEB expression in CRC tissues and adjacent normal tissues, and the role of TFEB in CRC cell lines was investigated in vitro and in vivo.Results: TFEB was expressed at lower level in CRC tissues than normal in both mRNA and protein level. However, there were significantly positive correlations between TFEB expression in cancer tissues and malignant progression of CRC. Cancers with TFEB overexpression always had deeper infiltration and higher lymphatic metastasis rate. Furthermore, patients with high TFEB levels always had poor survival, and higher TFEB expression could be a predictor of survival in multivariate analysis. Meanwhile, knockdown TFEB by shRNA or knockout TFEB by sgRNA in CRC cell lines could significantly inhibit cell proliferation and migration in amino acid-free medium. In addition, we found a positive relationship between TFEB and Beclin1 expression, and silencing TFEB inhibited Beclin1 expression in CRC cells.Conclusion: TFEB expression correlated with aggressive clinical features in CRC, and higher TFEB expression could be a prognostic factor and potential treatment target of CRC. Keywords: TFEB, colorectal cancer, clinicopathologic variables, prognostic factor, Beclin1

In a cyclic solvent injection (CSI) process, a vaporized solvent is cyclically injected, soaked, and released to produce heavy oil. Through this process the operating pressure is increased and decreased periodically. This causes a dynamic fluid flow across a heavy oil–solvent mixing zone, leading to a convective mass transfer in addition to molecular diffusion. This study aims at modeling the effect of convection on the heavy oil–solvent mass transfer in the transition zone of the CSI process. A convection–diffusion mathematical model is developed and semi-analytically solved. It consists of two sub-models, a pressure model and a solvent concentration model, and considers realistic viscosity and convection velocity profiles. Three practical injection and production schemes are modeled in order to provide some meaningful suggestions for the CSI field applications from the viewpoint of mass transport. Results show that convection can significantly enhance solvent dissolution during the injection period and accelerate solvent exsolution during the production period. In addition, it is also found that a smaller solvent injection rate does not make a big difference in the solvent dissolution for a long injection period. Moreover, during the production period, solvent exsolution induces a sharp pressure gradient that is believed to be a key factor for foamy-oil flow. It causes a viscosified front and solvent “inverse” diffusion that results in several rounds of foam-oil flow. Finally, a considerable amount of solvent remains dissolved in heavy oil at the end of the production period when the reservoir pressure is depleted, and is difficult to be retrieved in a short time.

Degradable fiber can temporarily plug a natural fracture or artificial fracture. It has been successfully applied in the stimulated reservoir volume (SRV) fracturing or re-fracturing of unconventional reservoirs. Based on the classical analytical stress field equation, a new mathematical model is established in this paper to model the crack reorientation path after injecting fiber diversion fluid according to the tensile failure criterion. Factors influencing the diverting radius are intensively analyzed through numerical simulation. The results indicate that the horizontal stress difference, fracturing fluid viscosity, and injection time (fracturing fluid volume) have larger effects on the diverting radius than do the formation permeability (1–50 mD) and bottomhole pressure (90–160 MPa). The simulation results are successfully verified, matching well with the experimental data from the true tri-axial fracture reorientation tests in the laboratory. The model is successfully applied to the heterogeneous carbonate reservoirs in northwest China.

Solvent-based heavy oil recovery techniques, such as vapour extraction (VAPEX) and cyclic solvent injection (CSI), have been attracting increasing attention in the past two decades.VAPEX suffers from slow mass transfer and inefficient gravity drainage.CSI is a solventhuff-and-puff processand its production period is usually much shorter in comparison with the solvent injection and soaking periods, limiting the average oil production rate over theentireprocess.Thispaperproposesanewprocess,dynamicsolventprocess(DSP),toexploitthemeritsofVAPEX(continuousproduction)andCSI (stronger driving force) and reduce their respective limitations (inefficient gravity drainage and periodic production). DSP is a cyclic process and each cycle consists of two periods: a stable pressure period and a pressure reduction period, through which solvent is cyclically injected and oil is continuously produced. A set of laboratory experiments were performed to validate and analyze the DSP process. During the pressure reduction periodofDSP,afoamyoil flowphenomenonwasobservedwhenthepressurereachedtheso-calledpseudo-bubblepoint.Thefoamyoil flownotonly enhanced the oil production but also improved mass transfer due to the enlarged oil–solvent contact area. Experimental results showed that the oil production rates of VAPEX and CSI were respectively enhanced by 57–123% and 17–99% by DSP with different well configurations.

This paper presents a new enhanced heavy oil recovery (EHOR) process, Cyclic Production with Continuous Solvent Injection (CPCSI). In this process, a vapourized solvent near its dew point is continuously injected into the reservoir to maintain reservoir pressure and also supply extra gas drive to flush the diluted oil out through an injector that is located on the top of the reservoir; while a producer, which is located at the bottom of the reservoir, is operated in a shut-in/open cyclic way. A series of experiments have been conducted to evaluate the CPCSI performance. The recovery factors (RFs) are up to 85% of original oil in place (OOIP) in 1-D tests, and the RF is improved by 11% by using the 2-D lateral CPCSI, compared with the traditional 2-D lateral VAPEX. Well configurations and the producer shut-in/open scenarios are key optimization factors that affect the CPCSI performance. Experimental results show that the foamy oil flow and solvent trap are the two major EHOR mechanisms for enhancing the oil production rate during the production period. In comparison with continuous injection process, such as vapour extraction (VAPEX), and cyclic injection process, such as cyclic solvent injection (CSI), CPCSI offers free gas driving, and the reservoir pressure is maintained during the producer opening period so that the diluted oil viscosity is kept low. This work shows that CPCSI could be an alternative optimization production scenario for applying solvent based in situ EHOR techniques for heavy oil reservoirs in Western Canada.

Super oxide anion had been known as a critical role in a phagocytic cell when microorganisms invade inside. However, this radical seldom need for a clean environment such in a developed country. Moreover, this agent sometimes triggered as serious factor in the site of inflammation. There are many papers which concerned newly found anti-oxidative substances. However, many reports only focused on the molecular basis in vitro, how oxidative stress damaged the human tissue. The key factor for oxidative stress needs to be discussed first for immunological standpoint, such as armed reduction treaty. In other words, minimum armed force is necessary for an invasion by outer or inner irregular cells. On the basis of phagocytic function of the cell in vivo, we tried to access anti-oxidative activity by employing peritoneal murine macrophage and human monocyte. So, the purpose of this study is to establish a conventional but tailor made system for which is useful for evaluating the anti-oxidative activity to different constition. Especially in human peripheral monocyte, the sample was tested each constitution such in granulocyte rich type and lymphocyte rich typ. In order to establish the direct estimation by phagocytic cell, a murine peritoneal exudates cell suspension was obtained after one week of oral administration with anti-oxidative sample. The samples we selected were traditional Chinese medicine, Shi-Quan-Da-Bu-Tang (SDT), Bu-Zong-Ye-Qi-Tang (BYT) and Shao-Chin-Rong-Tang sCRT), Agaricus, Chlorella, and Propolis. The amount of generated super oxide anion was calculated through measuring the optical density change of this supernatant using cytochrome-C which was reduced by generated super oxide anion in the phagocytic cell. The generated super oxide anion after administration of Agaricus, Chlorella, SDT, BYT, sCRT and Propolis were 2.64, 1.95, 1.24, 1.25, 2.88, 2.55 × 10﹣5 mmol/ml, respectively, whereas 2.85 × 10﹣5 mmol/ml in control group. The fermented sample from SDT, BYT, sCRT and microfied Propolis were also tested and the value of super oxide anion were 0.62, 0.84, 1.50 and 2.55 × 10﹣5 mmol/ml, respectively. In this report, we discussed the direct method for measuring the generated super oxide anion of macrophages, especially from different constitution.

Diffusion/dispersion coefficient and flow velocity in an advection-diffusion mass-transfer process have both been commonly considered as constant mean values in most previous studies, which may be reasonable in incompressible fluid flow with a constant viscosity. However, this assumption may not be applicable for some cyclic processes, such as huff-n-puff CO"2 injection and cyclic solvent injection in heavy oil enhanced oil recovery (EOR) processes, in which both the diffusion coefficient and flow velocity vary with time and space. This paper develops two novel one-dimensional (1D) advection-diffusion mathematical models: one model considers a constant diffusion coefficient and a variable flow velocity, and the other one considers both parameters as variables. Semi-analytical solutions to both new models are developed through the Laplace transformation and a special approximation scheme to the variable diffusion coefficient and flow velocity. The semi-analytical results are validated by an analytical solution to a special advection-diffusion case as well as the numerical solutions. It is found that the concentration distribution for the constant and variable diffusion coefficients has quite different shapes. The flow velocity can play a much larger role than the diffusion coefficient does in the crude oil-solvent mass-transfer process, implying the pressure gradient between the solvent chamber and the crude oil zone can greatly enhance the solvent dissolution into the crude oil. Gravity force might hinder the mixing process of crude oil and solvent in some cases of solvent-based EOR methods.

The production rate in classical vapor extraction (VAPEX) is far too low for the process to be considered commercially viable. This is largely because the classical process utilizes forces of buoyancy and mass transfer by diffusion and dispersion to distribute the solvent and gravity to drain the diluted oil to the producer. This article presents a new well pattern Tee-SVX which may enhance the oil-flow rate by two to ten times over that of the classical approach. In the new well pattern, additional horizontal injectors, perpendicular to the injector and the producer in Classical VAPEX, are placed in the topmost region of a reservoir. The oil-rate-enhancement mechanism for this new well pattern involves two features. First, the operation pressure of the top injectors is set slightly higher than the bottom injector pressure. This facilitates a downward driving force to assist gravity drainage of diluted oil to the producer. Second, the supplementary injectors generate an additional diluted oil profile perpendicular to the diluted oil profile of the Classical VAPEX process. Therefore, in the new well pattern, the heavy oil is solvent contacted and diluted in both vertical planes (one plane perpendicular to and the other parallel to the horizontal producer), whereas in Classical VAPEX, the heavy oil is diluted in only one. A series of numerical simulations were conducted to evaluate this process. In order to obtain reliable evaluation results, the numerical dispersion was eliminated through extrapolating the simulation results at different grid sizes to an infinitesimal grid size (Δy → 0). The simulation results suggest that the oil-flow rate can be enhanced two to ten times greater than that with Classical VAPEX, depending on the well spacing of the top injectors. For example, for a well spacing of the top horizontal injectors of 120 m, the oil-flow rate from the original producers will be 5.5 times higher than that of Classical VAPEX. For thinner reservoirs, the Tee-SVX can enhance the oil-production rate higher compared with Classical VAPEX. For reservoirs with a small gas cap, Lateral-SVX with vertical injector is quite effective.

Solvent vapour extraction (VAPEX) has shown great potential to recover heavy oil reserves. However, the application of the VAPEX technique is limited by its low oil production rate, which is caused by the slow mass transfer and inefficient gravity drainage. Hence, increasing the heavy oil–solvent mixing process and introducing more production mechanisms are imperative to enhance the performance of VAPEX. This paper proposes a new process, namely enhanced VAPEX, in which the solvent-chamber pressure is dynamically operated rather than constantly maintained throughout the production process. During the enhanced VAPEX process, pressure in the solvent chamber is cyclically depleted to induced foamy oil flow, which not only adds oil production but also increases contact area. In addition, a high-pressure non-condensable gas is applied to induce fingering phenomenon, which enlarges the heavy oil–solvent contact area. The enhanced VAPEX process is experimentally evaluated in this study. It is found that gas fingers can penetrate deep into the oil zone. In addition, foamy oil flow not only increases oil production but also improves mass transfer. Experimental results show that the oil production rate of the conventional VAPEX process was increased by 182% by the enhanced VAPEX process.

Cyclic solvent injection (CSI) process takes advantage of solution-gas drive and foamy oil flow for the oil production. However, it suffers from the solvent liberation during the production period. This results in an increased viscosity of the oil and its mobility loss. 0How to recover the partially diluted heavy oil becomes a key challenge for a CSI process. This paper first experimentally studies the conventional CSI processes with a one-well configuration, in which the solvent injector is alternately used the oil producer, and a two-well configuration, in which the solvent injector and oil producer are placed horizontally apart. It is found that during the one-well CSI test, some foamy oil that remains in the solvent chamber at the end of the production period of a previous cycle is pushed back by the injected solvent during the injection period of the next cycle. Such a back-and-forth movement of oil is not observed in the two-well CSI test. In addition, it is found that the oil saturation and oil relative permeability inside the solvent chamber are increased due to the foamy oil flow during the production period. Based on this fact, a new process, namely gasflooding-assisted cyclic solvent injection (GA-CSI), is proposed to enhance the performance of the CSI process. In this new process, a gasflooding slug is applied after the pressure depletion process to produce the partially diluted foamy oil in the solvent chamber. Results show that the GA-CSI process can increase the oil production rate by over 3 times, in comparison with the conventional CSI process.

Diffusion-convection mass-transfer process in porous medium is one of the major enhanced oil recovery (EOR) mechanisms of Vapor extraction (VAPEX). Previous work tried Fick’s Law to model the diffusion process, and mostly assumes the diffusion coefficient as a constant in the equation. However, the diffusion coefficient factually is a function of concentration, and thus the effect of its gradient should be included in the governing equation. In addition, bulk flow exist during the VAPEX especially during the solvent chamber rising phase, hence the process may be a diffusion-convection process rather than a pure diffusion process as presumed in previous works. This paper proposes a new one-dimensional (1D) VAPEX mathematical model on the basis of diffusion–convection equation, gravity-based fluid flow equation (Darcy’s law), and mass-conservation equation. The model is directed at a vertical thin cylindrical VAPEX process with injector and producer both setted at the bottom. The solvent chamber is considered as a two-phase area and the oil in it is completely saturated, while the matiral beyond the chamber is thought as in liquid phase. First, the diffusion-convection model is developed to obtain the concentration distribution in the transition zone; the boundary between solvent chamber and transiton zone is seen as moving with time. Second, the drainage velocity of the saturated oil in solvent chamber is calculated and combined with the mass conservation equation, to model the saturation of the oil phase changing with time. On the basis of the saturation model the oil production rate can be obtained. The recovery factor profile is divided into two distinct stages: solvent diluting-dominated stage and saturated oil flowing-dominated stage. During the first stage, it is found the solvent chamber growing rate tends to be constant; the oil production rate is proportional to the square root of permeability, which constists with the existing VAPEX theoretical model. During the second stage, the production rate is linearly related to the 1.1–1.3 power of the model length rather than the square root of it. This agrees perfectly with the lab observations in previous work.

Solvent-based EOR techniques, such as vapour extraction (VAPEX) and miscible/near-miscible flooding, have been studied and applied in petroleum industry. Diffusion–convection mass-transfer process is one of the most important EOR mechanisms in these techniques. This paper develops an accurate semi-analytical solution to a 1-D diffusion-convection mass-transfer model. The velocity term in the diffusion–convection equation has been assumed as a constant in previous works. This assumption is actually not valid in the solvent-based miscible flooding, since the velocity is a function of local viscosity and density, both of which depend on the local concentration. In this study, the spatially and temporally varying convection velocity is rigorously simulated through an accurate semi-analytical approach. First, we consider a sequence of time steps. In each time step, the convection velocity varies with space. Then the spatially varying velocity profile is divided into multiple sections. The velocity profile in each section is approximated with a linear function, so that the analytical solution for the diffusion-convection equation in each section can be obtained in Laplace domain. Then, the solutions in all sections are couped together and solved to obtain the mass-transfer rate through which the concentration distribution can be computed. Finally, a new convection velocity profile can be acquired by using Darcy's law for the next time step. The semianalytical solution is validated by an analytical solution for a special hyperbolic velocity case. In comparison with the numerical solution, the semi-analytical result is free from truncation error and numerical dispersion, thus it is more accurate and more reliable in computing the concentration distributions. The proposed method can be used in streamline simulation, or coupled with other functions to improve the simulation of solvent-based EOR techniques.

TARIM is the largest basin abundant in carbonate reservoirs in China. Acid fracturing is the main technology for exploration and development in TARIM carbonate reservoirs, which featured with great depth (4500–7200m), high temperature (250–320F Degrees) and extreme heterogeneity due to fracture formation. If the azimuths of natural fractures and in-situ stress match the azimuth of fracture-and-cavern area from the well, the acid fracturing treatment would generate good effect in general; otherwise, the effect will be non-ideal. A novel diversion acid fracturing (acidizing) technology, which combines fracture reorientation technology and fluid diversion technology, has been developed to solve the problem. When hydraulic fractures are initiated and extended in unfavorable direction, the fracture reorientation technology utilizing DCF (Degradable Cleaning Fluid, with great block efficiency and high compressive strength) can be adopted to temporarily block the fracture and ensure the hydraulic fracture would reorientate in advantageous direction. DCF is a mixture of TDF (temperature-degradable fibers), which would remain stable at 260 Degrees Fahrenheit while degrade thoroughly at 280 Degrees F, and soluble particles. By using visco-elastic surfactant based self-diversion acid, the fluid diversion technology could achieve deep penetration and efficient acid placement. Well YM204 has no production before stimulation. The azimuth of maximum principal stress is about NE45 Degrees. FMI data shows that natural fractures in Ordovician carbonate formation are oriented at NW315-SE135 Degrees while there is a fracture-and-cavern area about 150m to the northeast of the wellbore according to the seismic lateral prediction. Thus, acid fracturing treatment combining fracture reorientation technology and fluid diversion technology was conducted in this well. Post-treatment evaluation indicates that the fracture-and-cavern area has been connected to the wellbore and the output remained over 100t/d of oil and 7000m3/d of gas.

In this paper several polycrystalline molecules with sulfonate groups and some of their metal complexes, including DL-homocysteic acid (DLH) and its Sr- and Cu-complexes, pyridine-3-sulphonic acid and its Co- and Ni-complexes, sulfanilic acid and L-cysteic acid were investigated using THz time-domain methods at room temperature. The results of THz absorption spectra show that the molecules have characteristic bands in the region of 0.2-2.7 THz (6-90 cm(-1)). THz technique can be used to distinguish different molecules with sulfonate groups and to determine the bonding of metal ions and the changes of hydrogen bond networks. In the THz region DLH has three bands: 1.61, 1.93 and 2.02 THz; and 0.85, 1.23 and 1.73 THz for Sr-DLH complex, 1.94 THz for Cu-DLH complex, respectively. The absorption bands of pyridine-3-sulphonic acid are located at 0.81, 1.66 and 2.34 THz; the bands at 0.96, 1.70 and 2.38 THz for its Co-complex, 0.76, 1.26 and 1.87 THz for its Ni-complex. Sulphanilic acid has three bands: 0.97, 1.46 and 2.05 THz; and the absorption bands of l-cysteic acid are at 0.82, 1.62, 1.87 and 2.07 THz, respectively. The THz absorption spectra after complexation are different from the ligands, which indicate the bonding of metal ions and the changes of hydrogen bond networks. M-O and other vibrations appear in the FIR region for those metal-ligand complexes. The bands in the THz region were assigned to the rocking, torsion, rotation, wagging and other modes of different groups in the molecules. Preliminary assignments of the bands were carried out using Gaussian program calculation.

As a new technology, the terahertz technology had made a great progress in security inspection and medical field. This paper shows the application of the terahertz time-domain spectroscopy (THz-TDS) technology on cosmetic testing. We obtain the THz spectra of three kinds of usual cosmetics powders. Two kind of powder have an obvious absorption peak at 1.14 THz, but the third one has no absorption peak. The positions of absorption peaks in the infrared spectra of three kinds of powders are approximately identical. These results show that THz-TDS technology has the advantage and potential application on the cosmetic testing. In addition, we also measure some solid and liquid cosmetic components, such as Titanium-dioxide, Magnesium Stearate, Kaolin, Glycerol, etc. THz spectra of their refractive index and absorption coefficient are obtained experimentally. We are trying to establish the fingerprint spectra database of cosmetic components for further research and application.

Solvent vapour extraction (VAPEX) process is an economically viable, technically sound, and environmentally friendly in-situ heavy oil recovery method to exploit tremendous heavy oil and bitumen reserves. In this recovery process, significant heavy oil viscosity reduction is achieved through sufficient solvent dissolution and possible asphaltene precipitation. Over the past two decades, several researchers have carefully studied the effects of some major factors on the VAPEX process, such as the test pressure, reservoir porosity and permeability, solvent and heavy oil types, well configuration, and connate water saturation. However, it is unclear how waterflooding and solvent injection will affect a typical VAPEX process. In this paper, waterflooding and solvent injection effects are experimentally studied by using a visual rectangular sand-packed high-pressure VAPEX physical model with a low permeability. The physical model is packed and then saturated with a heavy oil sample at the connate water saturation. Pure propane and a mixture of n-butane and methane are used as respective solvents to extract two different heavy oil samples. The waterflooding effect is examined by performing a series of VAPEX tests with the initial waterflooding, prior to the subsequent solvent injection/soaking. In addition to the visual observation of the solvent chamber evolution, the heavy oil production rate, produced solvent–oil ratio, and asphaltene content of the produced heavy oil are measured during the waterflooding and solvent injection/soaking. It is found that the initial waterflooding causes an oil production reduction in the subsequent solvent injection. Also solvent breakthrough occurs earlier and a small amount of water is produced afterwards. This is because the initial waterflooding creates some low-resistance channels for the injected solvent to bypass the untouched heavy oil. As a result, the heavy oil is not diluted enough to be produced during the subsequent solvent injection/soaking. In the absence of waterflooding, however, solvent injection alone can increase the heavy oil production in comparison with the solvent-soaking process. Moreover, it is visually observed that solvent injection leads to less asphaltene deposition onto the porous media. This is quantitatively verified by a higher measured asphaltene content of the produced heavy oil at a higher solvent injection rate.

Solvent-based in-situ enhance oil recovery (EOR) techniques are extensively studied to improve oil recovery factors (RFs) for heavy oil reservoirs. Continuous injection, such as vapour extraction (VAPEX), and cyclic injection, such as cyclic solvent injection (CSI) are two main categories of solvent EOR techniques. The production rates of VAPEX are low in field tests. CSI does not show exciting results due to the quick reservoir pressure depletion and the sudden reservoir energy loss, which causes the oil to regain its viscosity. A new enhanced heavy oil recovery technique, cyclic production with continuous solvent injection (CPCSI), is proposed in this paper. In this process, a vapour solvent is continuously injected into the reservoir to maintain reservoir pressure and also supply extra gas drive to flood the diluted oil out through an injector that is located on the top of the reservoir, while a producer, which is located at the bottom of the reservoir, is operated in a shut-in/open cyclic way. A series of experiments have been conducted to validate the CPCSI performance by using different sand-pack models with 4¬-5 Darcy permeability, and saturated with Western Canada heavy oil sample. Gaseous propane is continuously injected through an injector at a constant pressure, which is below the dew point pressure, and producer was operated with a cycle of 50-minute-shut-in/10-minute-open period. Experimental results show that, the oil is diluted and drained down by gravity during shut-in period, then produced in producer opening period by solution gas drive and gas flush. In comparison with VAPEX and CSI, CPCSI offers free gas driving, and still keeps oil diluted in the well opening period and produced by the gas flush. The RFs are up to 85% of OOIP in 1-D tests. Also, shorter height model has highest average production rate in comparison with others. Test results are also validated by 2-D physical model, in which the RF is improved by 11% by using the lateral CPCSI compared with classic lateral VAPEX. Well configurations and the shut-in/open scenarios are key optimization factors that affect CPCSI performance. This work shows that CPCSI could be an alternative optimization production scenario for applying solvent based in-situ EOR techniques for Western Canada heavy oil reservoirs.

In a cyclic solvent injection (CSI) process, a solvent gas is cyclically injected, soaked, and released to produce heavy oil. Through this process the operating pressure is decreased and increased cyclically. This causes a dynamically changing pressure gradient across the solvent–oil mixing zone, leading to a convective mixing of solvent and oil in addition to molecular diffusion. This study aims at modeling the effect of pressure gradient-induced convection on the solvent–oil mixing process in the transition zone. A diffusion–convection model is developed to simulate the dynamic solvent–oil mass transfer in the transition zone during the CSI process. This model consists of two sub-models: a pressure model and a solvent concentration model. The pressure model considers the effect of a practical viscosity profile and the concentration model considers the effect of a dynamic convective mass transfer velocity. These two models are coupled through the convection velocity and oil viscosity across the transition zone. The entire model is semi-analytically solved, in which a piecewise linear approximation scheme is applied for the variable convection velocity and viscosity in the transition zone. Results show that during the solvent injection period, convection can significantly enhance the mixing of solvent and heavy oil. Larger solvent injection rates can be more efficient for heavy oil–solvent mass transfer. In addition, it is found that considerable solvent remains in the oil zone at the end of the production period, and this part of solvent is difficult to retrieve within a short time period.

Hydrocarbon solvent-based enhanced oil recovery (EOR) techniques, such as vapor extraction (VAPEX) and cyclic solvent injection (CSI), have shown a great potential to recover heavy oil reserves. Solvent dissolution into heavy oil and diluted oil flow are the two main processes of these techniques. VAPEX suffers a low production rate because of the slow mass transfer and inefficient gravity drainage. Although benefited from solution gas drive and foamy oil flow, CSI is bothered with the solvent gas release and viscosity re-increase during the production period, which might seriously slow down the oil production. In this study, it is found that foamy oil flow would generate a foamy oil zone which re-saturated part of the solvent chamber. On the basis of this a phenomenon, this paper proposes a new way to enhance the CSI performance through a three-step pressure control scheme during the production period: first, reduce the model pressure to induce foamy oil flow and foamy oil zone; second, re-increase the model pressure to a preset value; third, maintain a certain pressure difference between injector and producer for gas flooding. This three-step process is called one pressure pulse and it can be consecutively repeated several times during the production period.A series of laboratory experiments have been conducted with a visual rectangular sand-packed physical model. The sandpack permeability is ∼5 Darcy. Propane is used to recover a heavy oil sample with a viscosity of 5,875 cP. Results show that (1) foamy oil could effectively re-saturate the solvent chamber; (2) more pressure pulses would lead to more oil production, while the oil production decreases with pulse number in one cycle; (3) the oil production rate of PP-CSI is 4.37 times of that of conventional CSI, and the final recovery factor of PP-CSI is 17.9% higher than that of CSI. (4) flooding-induced viscous fingering can accelerate the mass-transfer rate; meanwhile, the viscous fingering will not cause an early breakthrough of the solvent chamber.

Solvent-based recovery processes, such as cyclic solvent injection and its variants, have shown a great potential to enhance heavy oil recovery after cold heavy oil production with sands. In such processes, pressure is increased and reduced in a cyclic manner to induce foamy oil flow, which is a key production mechanism. Previous conclusions of foamy oil flow in primary production may have limitations for cyclic processes since the fluid properties and operating conditions are fairly different. This study first conducted an experimental study to visualize the foamy oil flow in a scaled physical model under realistic reservoir conditions. Pseudo-bubble points at different stages of the test are recorded. Then a mathematical model is developed to simulate the experimental observations. This model reasonably couples pressure diffusion and mass transfer together, and considers dynamic properties of gas, foamy oil and diluted oil. Experimental observations show that the oil zone remains relatively stable before pressure drops to a certain level. Afterwards, the oil front moves explosively inwards the solvent chamber, indicating a flow of foamy oil. Theoretical modeling results show that the pressure gradient at the oil-gas zone interface increases from zero at the beginning to a considerable value during a drawdown process. The foamy oil flows only when the pressure gradient reaches a certain level, and a larger drawdown rate tends to result in a higher pressure gradient and a higher pseudo-bubble point. In addition, at the same pressure drawdown rate, the foamy oil flow at a later stage is expected to happen more quickly than at an earlier stage.

Hydrocarbon solvent-based enhanced oil recovery techniques, such as vapor extraction (VAPEX) and cyclic solvent injection (CSI), have showed great potential to recover heavy oil reserves. However, VAPEX suffers from low production rates because of the slow mass transfer and inefficient gravity drainage. CSI benefits from solution gas drive and foamy-oil flow; however, solvent gas release would cause the viscosity of the diluted oil to re-increase to slow down the oil flow. In addition, the oil rate of CSI might be uneconomical due to the long no-production injection/soaking period. This paper proposes a new process, named foamy-oil assisted VAPEX, to enhance the heavy oil recovery. This process applies the same production mode as a traditional VAPEX except the model pressure is reduced cyclically to induce foamy-oil flow. Laboratory experiments are conducted to analyze the new process and compare it with VAPEX under the same well pattern and similar physical conditions. Sandpack permeability is about 5 Darcy. Propane is used to recover a heavy oil sample with a viscosity of 5,875 cP. For VAPEX, model pressure is kept at ~800 kPa. For foamy-oil assisted VAPEX, pressure control in each cycle consists of two periods: a constant pressure period and a pressure reduction period. Results show that a strong foamy-oil flow can be induced through a pressure drawdown, which forms a foamy-oil zone. The foamy-oil flow pushes the solvent-diluted heavy oil inward the solvent chamber, which not only increases the oil production, but also helps solvent to contact the fresh heavy oil and accelerate the mass-transfer process. In the foamy-oil assisted VAPEX, oil that could not be produced in a traditional VAPEX by the gradititional force could be recovered in the foamy-oil assisted VAPEX process by a foamy-oil flow. Compared with a traditional VAPEX, foamy-oil assisted VAPEX can increase the oil production rate by 68.5 % and the final recover factor by 20.4%.