TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe large, naturally fractured reservoir under investigation is unique with its highly heterogeneous carbonate characteristics. The largest hydrocarbon bearing formations are not only naturally fractured, but also have matrix and vuggy porosity. Special relative permeability, capillary pressure, and compressibility relationships were developed to simulated multi-phase flow in this triple porosity system. Well and interference tests were re-analyzed at several stages in the project to provide input to geology on fracture properties and later to condition the fracture properties coming from the geologic model. The calibrated model acceptably matched the historical pressure and the production of oil, water, and gas for the reservoir complex. Nomenclature c c = Composite Compressibility c m = Matrix Compressibility c v = Vug Compressibility VR = Ratio of Vug Porosity to Total Composite Porosity
Inhibiting the rate of hydrate formation with low concentration additives is an economically and environmentally attractive alternative to prevention of hydrates with large doses of methanol. Here, a method for screening possible rate inhibitors is described. In the method, a viscometer is used to follow the development of hydrate formation for water-THF solutions and for water-gas solutions at conditions favoring hydrate formation. The method was applied to about 30 different chemicals, plus binary combinations of many of these chemicals. The best chemical additives included BASF F-127, Mirawet ASC Surfynol-465, sodium dodecyl sulfate(SDS), Mirataine CBS with polyvinylpyrrolidone(PVP), and SDS with PVP. Introduction Natural gas hydrates are ice-like solid structures composed of water and natural gas molecules. The water molecules form cages which encapsulate gas molecules. These structures can form at pressures and temperatures encountered in petroleum operations, jamming drilling strings, or plugging wells and pipelines. For more on natural gas hydrates, see Sloan. Natural gas hydrates are of increasing concern to petroleum engineers as the search for oil and gas take our industry to environments where low temperatures and high pressures exist. Deepwater in the Gulf of Mexico, North Sea, and permafrost regions in Alaska are a few locations where hydrates are often encountered. Hydrate formation or prevention in these areas is costing petroleum companies large amounts of capital and operating expense. Four thermodynamic methods are the most common means for preventing hydrate formation:remove the water from the system;increase the temperature until the system is out of the hydrate formation region for a given pressure;decrease the pressure until the system is out of the hydrate stability region for a given temperature;inject an inhibitor (such as methanol) to shift the thermodynamic stability region so that hydrates will not form for the current system temperature and pressure. As the operating conditions become more extreme, the quantity of methanol required can become quite large and the costs prohibitive. Much research has been done in the past on the thermodynamic conditions (pressure, temperature, and composition) necessary for natural gas hydrate to form. The current focus of research is moving toward kinetic prevention of hydrate formation. Kinetic inhibition methods attempt to control the formation and growth of hydrate crystal when the system is in a region where hydrates are expected to form. Polymers and surfactants are added to the system in small quantities with the hope that they will either prevent initial nucleation of hydrate crystals or stop the individual hydrate crystals from growing and agglomerating. In this paper, we describe an experimental apparatus and the methods used for screening potential inhibitors with this apparatus, and we present results of the screening process. Experimental Apparatus The apparatus constructed to monitor hydrate formation consisted of a viscometer, a temperature control system, and a data acquisition computer. The viscometer was purchased from Cambridge Applied Systems (Model SPL 340). Desirable features included its ability to measure viscosities over a wide range of values, an operating pressure up to 10,000 psi, and an operating temperature range from -30 C to l90 C. The CAS viscometer measures viscosity by magnetically driving a piston back and forth inside a measurement chamber. Heat generation from the magnetic coils in the CAS viscometer proved to be substantial and resulted in a temperature difference between the fluid in the measurement chamber and the temperature bath. P. 125
The triple porosity reservoir investigated is unique with its highly heterogeneous carbonate characteristics. The largest hydrocarbon bearing formations are not only naturally fractured, but also highly vuggy. Special relative permeability, capillary pressure, and compressibility relationships were developed to simulated multi-phase flow in this triple porosity system. Well and interference tests were re-analyzed at several stages in the project to provide input to geology on fracture properties and later to condition the fracture properties coming from the geologic model. The calibrated model acceptably matched the historical pressure and the production of oil, water, and gas for the reservoir complex.
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