Sampling
Multiphase Fluids From
Gassy Crude Through Condensates
To Wet Gas
Sampling
hydrocarbons has come a long way from simple manual spot sampling techniques
to the current state-of-the-art solutions, explains Mark A. Jiskoot.
Introduction
Sampling
hydrocarbons has come a long way from simple manual spot sampling techniques
through relatively simple automatic systems to the current state-of-the-art
solutions. Sampling is a requirement to measure a key part of the value
chain. Without quality/composition, quantity is of reduced relevance.
Today, there are a variety of accepted manual sampling methods used
by inspectors and operators alike; some well suited to the application,
others plainly, at best, a poor measurement technique. Even these techniques
are better than no information (a method with significant uncertainty
is better than no knowledge at all). This article does not address the
area of sampling dry gas, as this is relatively well-understood and
a well-trodden path.
Quality
Measurement Problems
Sampling
is a discrete process whereby small samples are extracted from a cross
section of the process on volume-based intervals. Unless the measurement
system provides a method for aggregating the quality value of the entire
cross section of the pipeline, some form of mixing will be required.
The first consideration in sampling anything, be it peanut butter or
space, must be the nature of the process variation both in time and
cross section. These are often termed temporal /special considerations.
It
helps to consider the various classifications of process regimes that
we are dealing with and there are a number of papers that do this at
great length. This is perhaps best illustrated by the diagrams for
multiphase flow regimes extracted from the Norwegian Society for Oil
and Gas Measurement - Handbook of Multiphase Metering 1995 and well
illustrated by the video taken at NEL as part of the multi-flow project.
It helps to visualize the requirement by considering the process fluctuations
in time, space and phase.
The
first two are evident in any regime and the influence of phase concentrations
should be treated separately.
Phase
is defined as a homogenous, physically distinct portion of matter in
a system not homogeneous; as, the three phases, ice, water and aqueous
vapour. A phase may be either a single chemical substance or a mixture,
as gases.
By
this definition, we should describe liquid hydrocarbon i.e. condensate/crude
oil with water as a single phase (liquid), the addition of a distinct
gas would make this a two-phase mixture. But actually, in the oil business
water/oil are in itself two distinct phases and (given time) forms quite
distinct and separate (immiscible) liquids. Gas as an addition makes
this a multiphase flow regime and one that the oil business has handled,
but avoided directly measuring, for many years.
In
the upstream sector, separators for test and process have always been
an early element in the process stream to allow handling and measuring
of production in ways we could physically achieve. In fact, the earliest
attempts at flow proportional sampling of a multiphase stream were prompted
in the late 1970’s when the UK government banned the flaring of gas
and forced its re-injection for transport ashore. These spiked crude
with a GOR at atmospheric of some 20 30: 1 would be sampled at pressures
of a 100 bar or so and therefore (ignoring phase transfer) would render
a process GVF of say 30 %.
With
the pressure on development cost and the rush to smaller and sub-sea
fields, interest has moved to the upstream sector with the desire for
accurate allocation of field production and improved reservoir management,
not to mention the correct payments of royalties/duties. This move has
also generated the need to be able to measure fluids with ever increasing
GVF’s through to the wet gas end of the market, which is considered
(depending on who you talk to) to be anything over 90 95 % at process.
One
of the first meters developed for this multiphase measurement, the Texaco
SMS was deployed close to 15 years ago. The industry has moved not to
produce more or less of any type of well (although many new techniques
have been developed, for example; gas lift, steam flood/ huff and puff),
they have widened both the opportunity to increase recovery and at the
same time created measurement problems.
The
focus on recognizing and accounting for value has also driven measurement.
For example, the values of condensate liquids in gas streams, formerly
overlooked in the audit train, have now caught the spotlight.
The
oil business typically runs through two primary business cycles, the
capacity cycle where volume is chased and the efficiency cycle where
profitability from any given asset is maximised. These demands are rarely
met simultaneously as the goals of speed (risk) vs tuning (little risk)
tend to be contrary.
While
there may be breakthroughs in developing production infrastructure,
developments in measurement tend to be driven from the downstream side
and are then applied upstream.
Measurement
Demands
Until
we can accurately meter online by mass composition to fraction in any
process regime, sampling will remain a crucial element in calculation
of the value chain.
To
briefly cite three examples: The simplest measurement is of mass/volume
of a simple crude import/export (stabilized with little free gas).
Even though (for years) a number of instruments have been available
for (online) measurement of water content, they remain generally unaccepted
for fiscal measurement.
In
the middle is the real multiphase arena, where the liquid phase may
benefit from compositional analysis to improve the quality of measurement.
Here samplers are used for comparison to the aggregated results derived
from multiphase flowmeters and also to gain compositional information
or physical properties of the individual phases (and less rigorously
their void fractions).
...contd
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