Flow Assurance
What is Flow Assurance?
Flow assurance is a term originally coined by Petrobras in the
early 1990's. The term in Portuguese was "Garantia de Fluxo",
which translates literally to "Guarantee the Flow".
Flow assurance refers to ensuring the flow of produced
hydrocarbons from the reservoir to the point of sale. It covers
all aspects of the production system and incorporates topics such as:
- THERMO-HYDRAULIC ANALYSIS
encompasses all pressure and temperature related aspects of
single and multiphase flow behaviour. This will include pressure
loss (or gain) calculations for applications such as deliverability
optimization and pipeline sizing. It will also include heat loss
(or gain) calculations that consider the pipeline surroundings, thermal
insulation, and active heating of pipelines.
refers to how the system reacts to changes in operating
conditions. For example, an operability study might address
concerns associated with terrain slugging or slugs generated by pigging
operations and the sizing of slug catchers required by such
operations. Other examples might include thermal effects of
start-up and shut-down operations or limiting flow rates associated
with a variety of operating conditions.
can result from the deposition of hydrates, wax, asphaltenes,
elemental sulphur, sand, or other produced solids. The formation
of such deposits is a function of the operating conditions in the
production system.
define the properties of the fluids flowing in the
system. The phase behaviour and physical properties of the fluids
will significantly impact all aspects of the production
operations. For example, the viscosity of produced fluids, from
more conventional hydrocarbon-water mixtures to less common fluids such
as stable emulsions and foam, will have a significant impact on the
frictional pressure losses in the system.
includes the impact of corrosion and erosion on the physical
materials (e.g. steel) that make up the system. Both the corrosion
and erosion affecting the inside of the pipes (whether surface pipes
or well tubulars) can be significantly influenced by the nature of both
the fluids in the system and the manner in which they flow.
efforts such as chemical inhibition, operational procedures, or
choking that may be used to address various concerns will be
influenced by the nature of the flow in the pipe.
Why is PIPEFLO the tool of choice for flow assurance
studies?
According to the Norwegian Institute for Energy Technology
(IFE), "The term 'Flow Assurance' covers broadly the same meaning as
the term 'multiphase transport technology." Based on this
assessment, Neotec was involved in delivering "Flow Assurance" software
and services to the oil and gas industry for approximately 20 years
before the term was coined.
PIPEFLO combines superior multiphase flow and
heat transfer technologies with best-in-class thermodynamics models to
provide solutions for all aspects of a flow assurance study. PIPEFLO
can be used to model anything from single lines to complex networks,
and includes tools which facilitate powerful sensitivity studies.
Pipe sizing
electing an appropriate size for a new multiphase pipeline is a
common problem. These are just some of the questions that must
be considered in such an application:
- How does the terrain affect the pressure loss
profile?
- What happens to the performance of the system
as production rates decline?
- Can the pipeline accommodate increased rates
as the field grows?
- Are special measures required to prevent
hydrate formation, wax deposition, or other pipe blockages?
- What happens to the temperatures if the
pipeline is shut in?
When a multiphase pipeline is built in an area with significant
terrain effects, hydrostatic head losses may be significant. When
this is the case, although it may seem counter-intuitive, a smaller
diameter pipe may lead to lower total pressure losses. Unlike
single phase pipelines, the combination of frictional and hydrostatic
pressure losses that occurs in multiphase flow means that a bigger
pipeline does not always lead to reduced pressure losses.
The example plot below shows the wellhead pressure at
various flowrates for three different pipe sizes. The blue line
represents an 8-inch pipe, where the wellhead pressure increases with
the flow rate. This is the behaviour expected in most pipelines;
it indicates that the predominant pressure losses result from
friction.
The green curve represents a 12-inch pipe. In this
case, the wellhead pressure decreases with increasing flow
rate, indicating that the pressure losses in the line result mostly
from hydrostatic effects (i.e. liquid loading). Other results
from PIPEFLO might indicate that the risk of corrosion
is increased due to high liquid holdup and the resulting flow
patterns. If the large line is selected because more gas
production is expected in future, results from PIPEFLO
could be used to size the slug catcher required for pigging operations
and to design operational procedures for the start-up of additional
production to avoid flooding downstream separation equipment.
The red curve represents a 10-inch pipe and includes a
minimum flowing wellhead pressure at 1000 e3sm3/d; this marks the
transition, beyond which the increase in frictional pressure loss due to
an increase in the flow rate is greater than the corresponding
decrease in pressure loss due to hydrostatic head (i.e. the rate at
which the pressure losses become friction dominated). The 10-inch
line appears to give the lowest and most stable pressure losses, but
it is important to review other possible complications.
Thermal issues are also very important, as hydrate
formation or wax deposition can reduce efficiency or even stop flow
entirely. The plot below shows the unmitigated fluid temperature
in red and the hydrate formation temperature in white, indicating a
hydrate problem starting around 7200 m along the pipeline. The
blue line shows the effect of adding two line heaters to keep the fluid
temperature above 30°C. (A unique feature of PIPEFLO
automatically locates facilities, in this case heaters, based on
user-defined criteria.) The green line shows the effect of
adding insulation to the pipe. The pink line shows the hydrate
formation temperature when methanol is injected at the wellhead.
Thus, PIPEFLO allows all of these scenarios (heating,
insulation, and mitigation) to be analyzed with ease.
Operational issues may also be analyzed and dealt with
using PIPEFLO. In the plot below, an insulated
pipeline is shut in, and the operators want to know how long they have
before hydrates start to form in the line. The white curve again
represents the hydrate formation temperature, and the other curves
represent the temperature profile at shut-in and every six hours
thereafter. With this plot we can see that the pipeline must
start flowing again or be purged within about twelve hours (the yellow
line) to avoid hydrate formation. This result is based on a
pseudo-transient calculation and is intended to give only a qualitative
estimate of the timelines involved. Full transient simulations
are required for a more accurate assessment.
PIPEFLO also has a variety of options to
deal with slugging issues. Flow pattern maps can be generated,
indicating the current operating conditions and the boundaries between
flow patterns. In the example below, a pipe is currently
experiencing annular mist flow but a small drop in the gas rate will
shift the pipeline into intermittent (i.e. slug) flow. With this
information, the engineer can take appropriate action to either prevent
or accommodate slug flow. For example, it is likely that
different corrosion mitigation techniques would be required if the
pipeline were operating in slug flow rather than in annular mist flow.
A pigging slug calculation can be performed to estimate
the size of the liquid slugs generated when pigging the line. PIPEFLO
can also estimate the likelihood of severe slugs (which can damage
equipment) forming in risers.
Using routines developed by BP, PIPEFLO
can estimate the slug frequency, slug length, and bubble length under
steady-state slugging conditions. For design purposes, both the
mean and the more extreme 1 in 1000 values, the values most commonly
used in industry, are provided for each.
Click here for pdf version.
