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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.

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.

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.

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.

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.

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%.