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Abstract
The acquisition of quality samples from heavy oil reservoirs can be especially
critical. It is frequently the case that in these environments the quality of
the oil is the single biggest reservoir risk. Therefore a valid fluid sample
where accurate measurements of parameters such as gas oil ratio and viscosity
can be made is crucial. These sample can be acquired with production tests but,
as in many reservoir environments, it is often desirable to acquire these
samples with formation tester (WFT) tools. However, heavy oils provide a
significant challenge for WFT’s. The oils are of high viscosity which results
in large drawdowns while flowing. They are frequently located in shallower,
unconsolidated reservoirs where high drawdowns can lead to sand failure. And
additionally they can combine with water (from the formation or from the
filtrate) to form emulsions that make fluid analysis difficult and can degrade
the quality of the acquired sample.
In this paper we review the elements required for successfully sampling heavy
oil reservoirs with WFT tools. We first consider the pre-job modeling that is
performed to predict the drawdowns and flow rates that can be expected from
assumed reservoir properties. We then use this information to design the
appropriate tool string from the myriad of options available today. We look at
the variety of hydraulic pump and displacement unit options that afford a wide
range of flow rates and therefore control over drawdown. Additionally we look
at the probe and packer configurations that allow a wide variety of flow areas,
again giving more control over sandface drawdown. Finally we address the issue
of emulsions especially as it applies to downhole fluid analysis and how these
can be mitigated.
Introduction
Of the 9 trillion barrels of oil in place estimated to comprise the world’s
endowment, 6 trillion are attributed to the heaviest hydrocarbons. (Alboudwarej
2006) An accurate evaluation of this resource is obviously crucial to its
efficient exploitation. This evaluation is usually dependent on the
analysis of a representative fluid sample. In this paper we will discuss the
challenges faced with sampling heavy crudes with formation testers and the
means at our disposal to mitigate these challenges. Before discussing the
methods of acquiring such samples we should first define what is meant by heavy
oil. Although we commonly refer to heavy oil it is in fact the viscosity and
not the density of the oil that provides the challenges in sampling and
production. Density is more important downstream as it is the best indicator of
the economic value of the oil. However, it is
viscosity that most affects the sampling (and production) of heavy oil.
Unfortunately, there is no clear correlation between density and viscosity.
High paraffin content, light crudes in shallow, cool reservoirs may have higher
viscosity than heavier oils in deep, hot reservoirs. While the US Department of
Energy (Nethering 1983) defines heavy oil as between 10 and 22.3 API (0.9 – 1.0
g/cc) the techniques we discuss here are not distinct to this type of oil.
Firstly, our techniques here are varying applicable across abroad range of
conditions and secondly, the very nature of sampling with formation testers
often precludes foreknowledge of the fluid type.
In defining the challenges provided in sampling high viscosity oils we note the
following frequently encountered characteristics:
- The
oil has a high viscosity and will not flow easily
- It is
often encountered in shallow (and therefore cool) reservoirs that serve to
increase viscosity
- These
shallow reservoirs are often unconsolidated so sands are therefore weak and
subject to failure.
-
Although oil base mud is sometimes encountered the
wells are more frequently drilled with water based muds.
This leads to the possibility of oil-water emulsions forming which affects
sample quality and complicates downhole fluid analysis.
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