【正文】 PART II Petroleum TechnologyLesson 4 Reservoir ManagementAs we have seen, the production of oil and gas up the wellbore and through the surface facilities requires a continuous source of energy. The energy to drive this system is contained in the pressed rock and fluids found in the reservoir. Reservoir management is the management of that energy, to maximize the economic recovery of hydrocarbons. This chapter presents an overview of some basic concepts regarding the properties of reservoir rocks and fluids. We shall do this from the perspective of the production or reservoir engineer, who is concerned with how the reservoir rock and fluids behave as production occurs, and with how this behavior affects ultimate recovery. We shall then outline the types of natural reservoir energy responsible for production, and give some examples of the performance characteristics of the primary drive mechanisms. Next, we shall point out the techniques used to enhance the recovery of hydrocarbons, whereby we attempt to alter the physical forces that control the movement of oil within the reservoir. Finally, we will give a brief introduction to reservoir simulation. Basic Properties of Reservoir Rocks and FluidsIn order for a geological formation to form a mercial reservoir for hydrocarbons, the rock must exhibit two basic properties: porosity and permeability. Porosity is the void space within the reservoir rock, which is filled with water and (hopefully) hydrocarbons. Permeability is the ability of the rock, a porous medium, to transmit fluids. The hydrocarbons that share the porosity with formation water are typically plex mixtures, that change their properties when subjected to the changes in pressure and temperature acpanying production. PorosityPorosity is defined as the percentage or fraction of void space to bulk volume of rock. If the sedimentary particles of a rock were of uniform size and packing, as shown in figure , the calculation of porosity would be a simple exercise in solid geometry. Of course, actual reservoir rock is a much more plicated mixture of particles, and its porosity must be measured directly from core samples or estimated by well log analysis. The proportion and distribution of void space in a reservoir rock can be modified by the processes of cementation, solution, fracturing, and recrystallization. In reservoir engineering, primary porosity refers to the void spaces remaining after the solidification of particles into the rock matrix. Secondary porosity is caused by solution channels, fractures, and vugs (large cavities) in the bulk volume of the matrix, and is developed subsequent to the deposition of the rock. Where both types of porosity exist, the system is referred to as a dual porosity system. The production sequence of a dual porosity system may be very different from that of a primary porosity system. Table gives a generalrange of reservoir rock matrix porosities. Generally, reservoir rock matrix porosities in the lower ranges are of mercial interest only when a secondary porosity system is present.Table Rock matrix porositiesNegligible05%Poor510%Fair1015%Good1520%Very good2025%Usually, the porosity enters into our reservoir calculations in estimating hydrocarbon volume in place in the reservoir. Its fractional value is multiplied by the bulk volume of the reservoir rock, and by the hydrocarbon fluid saturation (equal to one minus the water saturation) to determine the hydrocarbon pore volume. We are interested in porosity not only to determine the oil or gas in place at any given time and point in the reservoir, but also in any porosity variation (and corresponding permeability variation) across the field, which we must consider in selecting the best location for development wells. Usually the porosity of the reservoir rock remains constant during production. In some cases, however, the porosity may actually decrease as the reservoir pressure drops during production, to a degree that can be significant in its effect on recovery. This happens when the formation is extremely pressible. In some loosely consolidated oil sands, such as the Bachaquero field, Venezuela, the paction of the reservoir as reservoir fluids are removed accounts for more than 50% of total oil recovery (Merle et al. 1976). Porosity changes of this type must be taken into account in our reservoir analysis. PermeabilityPermeability is a measure of the ability of a porous medium to transmit fluids. The oilfield unit of measurement, the darcy, is named after a nineteenth century French engineer who established that the velocity of flow through a sandpacked filter was directly proportional to the difference in pressure across the Filter and inversely proportional to the length of the filter. His work was ultimately applied to linear flow through reservoir rock and to radial flow into a wellbore. One darcy is defined as the permeability that will permit a fluid of one centipoise viscosity to flow at a rate of one cubic centimeter per second through a crosssectional area of one square centimeter when the pressure gradient is one atmosphere per centimeter (Muskat 1937). Figure shows a schematic of how this quantity is measured. Permeability is a property of the porous medium only, and absolute permeability is its value when the porous medium is saturated with single fluid phase.Darcy39。s definition of permeability was for a porous medium, which was 100 saturated with the flowing fluid, water. Hydrocarbon reservoirs normally have two and perhaps three phases present: both water and oil。 or water and gas。 or water, oil, and gas sharing the pore space of the rock. It has been found that having more than one phase present in the pores reduces the ability of the rock to transmit any one of the fluid phases. For this reason, we define the effective permeability as the permeability to one phase when there is more than one phase present in the pore space. I