Inside a continuous chemical reactor, in which phase transitions occur during the reaction, thermodynamic conditions as well as compositions of the process stream are subject to significant spatial and temporal changes. Given that measured information about thermodynamic state variables is only available for the inlet and outlet stream of the reactor, it is currently not possible to determine a spatial distribution of thermodynamic states within the reactor on the basis of measured information via software sensors. As, in particular, exothermic chemical reactions often show temperature peaks which are likely to destroy catalysts and components or adversely affect their service life, this limited information about internal reactor states poses a considerable risk with regard to product quality and process reliability. Therefore, this paper proposes a novel approach in the area of sensor technology which is based on rigorous thermodynamic models and enables a more detailed prediction of the reaction progress in view of avoiding undesired temperature peaks, based on measured process parameters of the input and output streams only.

Low salinity water flooding (LSWF) and preformed particle gel (PPG) have recently drawn great interest from the oil industry. LSWF can only increase displacement efficiency, and it has little or no effect on sweep efficiency whereas PPG can plug fractures and improve sweep efficiency, but they have little effect on displacement efficiency. The coupled method bypasses the limitations of each method when used individually and improves both displacement and sweep efficiency. Polymer gels have been widely applied to plug high permeability streaks or fractures, and to improve sweep efficiency of chase water floods. The oil recovery from fractured reservoirs is usually low, which is usually caused by the existence of areal formation heterogeneity. Combining two methods in one process to enhance oil recovery represents a needed cost savings in the oil industry. Microgels are used as conformance control agents to improve oil sweep efficiency and control excess water production. Low-salinity water flooding (LSWF) is used as a wettability alteration agent in carbonate reservoirs and improves displacement efficiency. We developed a cost-effective, novel, enhanced oil recovery (EOR) technology for carbonate reservoirs by combining the four technologies into one process. The objective of this paper is to provide a comprehensive understanding of the combined technology and to demonstrate how the combining method can improve oil recovery. The oil-wet carbonate cores provided a higher improved oil recovery than water-wet carbonate cores during LSWF compared to traditional bulk gel treatments, PPG forms stronger plugging but will not form an impermeable cake in the fracture surface; therefore, PPG allows low salinity water to penetrate into the matrix, thereby producing more oil from the matrix. Preformed particle gels (PPGs) is a diverting agent that is used to solve the conformance problem in low permeability rich oil zones. It is injected to reduce thief zone permeability and then divert displacing fluid into poorly swept zones. The focus of this study is to see how PPGs, low water salinity, polymer and silica particles perform in porous media by creating flow resistance to injected fluid thereby changing the wettability and enhancing the sweep and displacement efficiency . Silica particles modify the surface wettability and also modify the gel particles strength, LSWF modify the mechanical properties of PPG such as swelling ratio, polymer increase the sweep efficiency of chase water flood and PPG plug the high permeability zones to divert the water flow into low permeability zone to displace the remaining oil.

In tight oil reservoir, the flow channel of fluids is tiny and the boundary layer effect is obvious, resulting in large flow resistance and high threshold pressure gradient. A fractal model for calculating the threshold pressure gradient of tight oil reservoir is established considering the fractal dimension of the pore throat and the tortuosity. In this model, the rock is considered as a capillary bundle with different diameter distribution as obtained from high-pressure mercury injection measurements for tight rocks. The mathematical model expresses the fractal threshold pressure gradient as a function of ultimate shear stress (η0), pore throat fractal dimension (Df), tortuosity fractal dimension (DT), the maximum pore radius (rmax), the characteristic length of the core (L0) and the connate water saturation (Swi). For 27 tight cores obtained from Changqing oilfield, threshold pressure gradients were determined using the established model and compared with experimental results and a good fit was found especially for the rock with lower permeability. The relative error is less than 14% for all the rock tested and is only 1.77% for the cores with permeability in the range of 0.001~0.01mD. This model has the advantage of being able to check the impact of the connate water saturation on the threshold pressure gradient of tight rock, which is usually neglected in previous work. The results show that higher Swi results in largely increased threshold pressure gradient. This fractal model is of great importance in studying of the mechanism of tight oil flow in porous media.

Well cement has been commonly used in wellbore environment, such as wells for oil and gas extraction and CO2 storage formation. For the safety of long-term operation of the wells, leakages in wellbore cement must be sealed. Nanoparticles in various slurries can be used to seal cracks in well cement. This study investigated the feasibility for developing an electrochemical method to inject nanoparticles into well cement not only to repair wellbore leakages and initial defects but also to extract the harmful ions (e.g. chlorides) simultaneously. Various experimental parameters were studied including different surface charges, types and sizes of nanoparticles and the intensity of injecting power supply. The new technology was developed and tested under the lab condition as well as a simulated wellbore condition. Some details for the technology to be used underground from inside of steel casing are under development so that it can be used for repairing the leakage of well cement for the oil and gas industry as well as for CO2 storage formations. Finite element models are being developed to simulate the nanoparticle injection and ionic transport processes of the technology.

Based on contact angle and interfacial tension measurement, this paper concentrated on adding surfactants agent into fracturing fluids to increase oil output after hydraulic fracturing. Cationic, anionic and nonionic surfactants were added into slickwater to perform a serious of one end open (OEO) imbibition experiments at a certain concentration. Scanning electron microscope (SEM) and nuclear magnetic resonance (NMR) method were also applied in the detection before and after the imbibition process. Results demonstrated that core samples changed from oil-wet to intermediate-wet or water-wet after soaked in surfactants, cationic surfactant shows a better performance in changing contact angle while different kinds of surfactants have a similar ability in lowering IFT. In the soaking duration, NMR transverse relaxation time (T2) spectrum showed that oil recovered by counter-current imbibition mainly distributed in intervals of 10-1000 ms while oil remained uncovered mainly distributed in intervals of 0.1-10 ms. T2 spectrum moved towards left side and this indicated that aqueous phase migrate from larger pores to smaller ones. Both laboratory experiments and field applications have indicated that adding surfactants into fracturing fluids can significantly increase oil outputs for tight oil-wet reservoirs. Application of this technology can be a good way to solve low production problems for this type of reservoir.