November
2016
HYDROCARBON
ENGINEERING
82
historical data, despite the acknowledgement that
flow conditions can change very quickly. To reduce
costs, new field developments have eliminated the
infrastructure to take fluid samples, which has
increased the risks associated with flow assurance and
reduced the margins for error. Hence, there is a
reliance on over-injecting chemicals to eliminate
issues.
Currently, fluid composition is determined for
assessing and developing chemical treatment
programmes by taking samples of the production fluid.
If samples are taken on an oil platform, then the
sample will be at different conditions compared to
subsea pipelines. This adds additional measurement
uncertainty from the laboratory analysis of the sample
and subsequent extrapolation to subsea conditions.
Another disadvantage to sampling is that some
components can already be deposited in subsea
pipelines and, hence, not detected in downstream or
topside samples, which is a major flow assurance risk.
Taking a multiphase or wet gas sample from a
pipeline is a complex engineering challenge. The
distribution of the fluids can change, making the
collection of a representative sample difficult as a
sufficient amount of each phase must be collected for
analysis in a laboratory to determine the composition.
Sampling and analysis is also expensive, which severely
limits the frequency of sampling. Despite the cost and
engineering challenges, sampling is regarded as critical
to effective flow assurance management.
The fluid samples may need to be conditioned for
up to five days to ensure the mixing and partitioning
of phases before beginning analysis. It can take several
weeks from the collection of a sample to the
provision of usable data for operators to allow
decisions on flow assurance and chemical injections to
be made. Within that period, flow conditions are likely
to have changed.
Sensor technology
There have been some pilot investigations by research
organisations into the development of new sensor
technology and models that can be used successfully
to indicate when flow assurance issues may occur in
real time and determine accurate chemical dosing.
Research has shown that in one field alone, for the
most part, there was no need to inject any hydrate
inhibitor chemicals as the flow conditions and fluid
composition were outside the hydrate formation
envelope. This saved substantial operating costs as,
previously, inhibitors were continuously injected based
on the worst case operating scenario.
One estimate suggests that with improved
chemical management, a potential reduction in a
hydrate inhibitor (MEG) alone could save around
£1 million/y for just a typical single gas well. The
average cost of chemical injection to mitigate flow
assurance issues can be as high as
€
2/bbl of produced
oil. With the current low oil price of
€
40/bbl, the cost
of chemical injection can be 5% of production costs.
A step change
The industry has identified several ground breaking
challenges that would require innovative
instrumentation to develop sensors and sampling to
collect real time data, combined with a more
advanced, fundamental understanding of physical
chemistry. This should enable a step change, in both
the optimisation of chemical injection programmes to
mitigate flow assurance risks and when balancing
economics for production and processing. These
challenges include the development of robust in-situ,
real time flow sampling techniques and hydrocarbon
composition determination, along with the
development of new sensors/techniques, which are
able to detect and measure dosing chemicals.
The fluid sampling techniques should not rely on
the removal of samples for remote analysis offline,
and will need to be accurate and repeatable for all
flow compositions, velocities and flow patterns.
Methods will also need to be established to provide a
real time breakdown of the hydrocarbon composition
of multiphase flows. This is in order to establish the
optimal chemical dosing requirements and to
determine the amount of water present.
Sensors will need to be developed and evaluated,
while techniques using correlations linked to other
sensor measurements could be developed to detect
and measure the quantities of residual-dosing
chemicals in different parts of a pipeline. Flow
assurance models could potentially be optimised,
based on the real time data from in-line sensors in
long subsea pipelines and risers, and in other remote
inaccessible locations.
If new sensors were developed that can determine
the hydrocarbon composition and concentration of
added inhibitor chemical species in real time, this
would offer a step change in flow assurance
management and substantially reduce measurement
and modelling errors – currently, there are little or no
sensors available to operate in these environments.
Information on the flow conditions, such as
temperature, pressure, hydrocarbon composition and
water content, can be used to establish ‘safe’ operating
envelopes. Within these ‘safe’ envelopes, no chemicals
will be required. The same strategy applies to inhibitor
chemicals for wax and scaling. This would launch a
new era in cost effective flow assurance management
strategies.
Conclusion
Flow assurance intervention costs could be
substantially reduced by the availability of real time
data that will make it possible to rapidly identify and
mitigate issues, including equipment failures and
production shutdowns, and to reduce the cost and
volume of chemicals required. This means that the
flow of oil and gas to downstream processing and
refining facilities will be more efficient and
predictable, as many of the flow assurance issues
encountered upstream will be resolved.
