Heavy Oil Fluid Testing with Conventional and Novel Techniques

ABSTRACT

In this paper, we propose the combined utilization of x-ray tomography and magnetic resonance techniques for quantification of heavy oil fluid properties.The design of these systems is presented along with preliminary results combined with conventional measurements.The objective is to understand the PVT behavior of a viscous heavy oil from a reservoir that has undergone primary production. Methane is dissolved into the oil at ambient temperature and elevated pressure.The pressure is later slowly depleted and the oil PVT properties are recorded.Specifically, this paper details measurements of oil density, formation value factor, and solution gas-oil-ratio as a function of pressure.The incremental benefit of the proposed nucleonic techniques is that they provide more detailed information about that oil, compared to conventional PVT measurements.This improves our understanding of the foamy oil response.

Introduction

Understanding fluid behavior of heavy oils is important for reservoir simulation and production response predictions.In heavy oil reservoirs, the oil viscosity and density are commonly reported, but there is little experimental data in the literature reporting how oil properties change with pressure.This information would be especially useful for production companies seeking to understand and improve their primary (cold production) response.

It is already widely known that foamy oil behavior is a major cause for increased production in cold heavy oil reservoirs along with sand production. Therefore it would be valuable to first study the bulk fluid properties of live heavy oil prior to sand pack depletion experiments. If the response of these properties to incremental pressure reduction can be established, this can be compared with fluid expansion during pressure depletion in a sand pack.

Computer Assisted Tomography (CT) scanning is useful in studying high-pressure PVT relationships. Images of a pressure vessel filled with live oil can be taken as the volume of the vessel is expanded and used to calculate bulk densities and free gas saturation. Also, CT images allow us to visually see how the gas comes out of solution and where it is located in the vessel. For example, CT scanning can be used to provide an indication of whether or not small bubbles nucleate within the oil and then slowly coalesce into a gas cap, or if free gas forms straight away.

CT scanning provides much more information than conventional PVT cells. Uncertainties about where gas is forming in the oil, its effect on oil properties and transient behavior cannot be solved in conventional PVT cells. However, from CT images the formation of micro bubbles could be inferred based on the density of the oil with the dissolved gas. If the oil density decreases as the pressure drops, then it is likely that gas has come out of solution but remains within the oil, hence the resulting mixture is less dense than the original live oil.However, if oil density increases as the gas evolves then the oil does not contain small gas bubbles, and gas has separated from the oil.

Also, the free gas saturation growth with time, and comparison of images at equilibrium vs. immediately after the expansion of the vessel, will provide mass transfer information about gas bubble growth, supersaturation and gravity separation.

When characterizing heavy oil and bitumen fluid properties, oil viscosity is one of the most important pieces of information that has to be obtained.The high viscosities of heavy oil and bitumen present a significant obstacle to the technical and economic success of a given EOR option.As a result, in-situ oil viscosity measurement techniques would be of considerable benefit to the industry.

A full version of this paper is available on OnePetro Online.