Thermophysical properties required for the hydrocarbon economy

A. Goodwin1

1Schlumberger Technology Corporation, Sugar Land, U.S.A.

Keywords: oil-field, oil, gas, asphaltenes
property: density, viscosity, phase borders
material: hydrocarbon and water

The World’s economy requires energy, from a variety of forms, to operate. Recent estimates suggest the Global energy consumption is on the order of 1021J per annum. Today about 65 % of this energy is obtained from oil and gas, about 20 % from coal and the remaining 15 % from nuclear and sustainable sources. By the year 2030 the energy sources will be more diverse and the energy fraction obtained from hydrocarbon has been predicted to decrease to about 50 %. The hydrocarbon will by then be predominantly found in either so-called deep-water or unconventional resources; the latter include fossil fuels commonly known as heavy oil, bitumen, gas-hydrates and oil shale. These sources are, for different reasons, more complicated to extract and process than conventional oil and consequently lead to a substantially greater financial risk to the owner. Operating companies determine the producible reserves from a series of measurements that include those conducted on hydrocarbon samples obtained from exploration and appraisal well. A hydrocarbon reservoir consists of a group of fluid-bearing layers separated by impermeable shale. Typically, wells are drilled through these layers using drilling fluids that serve to cool and lubricant the drilling-bit, remove cuttings to surface and to prevent collapse of the well-bore wall. To identify the hydrocarbon zones (as they are referred to in the industry) a series of electrical and acoustic measurements are performed. Then, through a device that attaches to the bore-hole wall, a fluid sample is extracted from the reservoir. In view of the presence of drilling fluid, the sampling devices use spectroscopic measurements to determine the presence and quantity of drilling fluid within the reservoir hydrocarbon. Additional measurements of both electrical conductivity and refractive index are used to identify the phase and fluid type as either gas, connate water or liquid hydrocarbon. The thermophysical properties and, to an extent, the chemical composition, of the reservoir fluid are determined from in situ measurements. The measured thermophysical properties are combined with measurements of the reservoir permeability, size, shape, and compartmentalization to perform analyses concerning the oil-field development. The thermophysical properties determined for conventional oil and gas reservoirs include the following: density, viscosity, (solid+liquid) and (liquid+gas) phase borders. The methods selected to perform these measurements must provide results with a quantifiable uncertainty that is suited to the intended application. This presentation will discuss the methods implemented for in situ measurements in conventional oil. These include a vibrating wire viscometer, a vibrating tube densimeter, electrochemical measurements of chemical composition and mid-infra red determination of the mole fraction of CO2 in both hydrocarbon and water. Un-conventional resources require additional in situ measurements, for example, thermal diffusivity, that are needed to select plausible production strategies.

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