An Experimental Study on Percolation Characteristics of a Single-PhaseGas in a Low-Permeability Volcanic Reservoir Under High Pressure
In this paper, we find that with the decrease in the average pore pressure in the process of gas production, both the slippage effect and the stress sensitivity effect will gradually increase; the increase in the slippage effect is significant, while the increase in the stress sensitivity effect is not. In this paper, the Kalamay volcanic gas reservoir of the Junggar Basin in China was selected as the object of our research. The gas reservoir has typical fractured volcanic reservoirs, and the long-term percolation feature remains unclear. To study the percolation characteristics of single- phase gas under high pressure, the experimental method was designed to simulate these characteristics in the process of gas production by measuring the gas flow in the core and the input and output pressure at both ends. We carried out simulation experiments of single-phase gas flow percolation characteristics under high pressure using 11 pieces of vol- canic rock samples in three wells of the study area. The results show that as the core pore pressure increased, the per- meability of low-permeability cores of the volcanic rock decreased significantly at room temperature. However, this decrease became more gradual, which means that the higher the core pore pressure is, the smaller the permeability variation caused by gas slippage is; when the pore pressure is above 10 MPa, the permeability is nearly constant, slip- page effect significantly reduces in the process of gas percolation, so it can be completely ignored under these forma- tion conditions. As the pore pressure decreases, the slippage effect and stress sensitivity effect will gradually increase; when the pore pressure is less than 10 MPa, the permeability appears to increase significantly, and this is especially true for a pressure of 5 MPa. The main cause of this result is the slippage effect of gas seepage during the depletion of the gas reservoir, when the pore pressure is lower than a certain value. The valid stress changes of the core are not large, and the stress sensitivity is not strong, so the slippage effect plays a major role, which leads to an increase in the gas permeability during the late period of certain flow gas production.
Experimental study and mathematical model of nanoparticle transport in porous media
Abstract Two types of polysilicon nanoparticles (PN) were used in oil fields to improve oil recovery and enhance water injection respectively in this work. The physical properties of the nanoparticles were studied experimentally, and pore characteristics of sandstone were investigated by mercury injection experiments. The adsorption experiments of lipophobic and hydrophilic polysilicon nanoparticles (LHPN) were conducted to testify wettability change (from oil wetting to water wetting) of sandstone surface, and the nanoparticles attached to pore walls were observed by a transmission electron microscope (TEM). A mathematical model to describe the nanoparticles transport carried by two-phase flow in random porous media was presented and a numerical simulator was developed to simulate two application examples of the nanoparticles in oilfields. An important discovery is that water-phase permeabilities of these sandstones increase from 1.6 to 2.1 times of their original values. However, there are decreases in their absolute permeabilities because of nanoparticle adsorption on pore surfaces and nanoparticle capture at pore throats. The important parameters such as the distributions of porosities and permeabilities, the changes in water injection capability and oil recovery are obtained successfully by numerical simulation approach. Furthermore, the permeabilities obtained from numerical simulation have a good match with experimental data. The conclusion that polysilicon nanoparticles are effective agents for enhancing water injection capability or improving oil recovery can be safely drawn.
Porosity and hydrocarbon distribution in the North Sea chalk reservoirs
Abstract Since 1970, more than 25 billion barrels of hydrocarbons, in place at reservoir conditions, have been discovered in the North Sea chalk reservoirs. For accurate development drilling, satisfactory reserve estimate and optimal recovery, a precise description of the porosity and hydrocarbon distribution has proved necessary. Because such reservoirs were unknown, it took some time to fully understand their local and regional variation. Based on a 12-year experience of the North Sea chalks and the data from > 180 wells, a basic geological model was established and tested on the other fields in the area and is described in this paper. Thickness variations are due to differential diagenesis as well as depositional factors. Porosity generally decreases downsection and towards the flank as a result of the progressive invasion of rock by oil and subsequent inhibition of chemical compaction. Layering in porosity reflects differences in initial porosity. Hydrocarbon saturation varies with structural elevation and rock type; i.e. depositional facies, mineral content, differential behaviour to early and late diagenesis, pore and pore throat size and morphology, tortuosity. This report is divided into two parts: development of the model and comments on the individual fields.