Note: Descriptions are shown in the official language in which they were submitted.
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Improvements in transporting fluids from wells
Technical field
The present invention relates to the field of fluid production from subsurface
reservoirs,
and in particular to methods of transporting production fluid from a well, and
related
apparatus. In particular, the invention relates to flow assurance in subsea
pipelines,
which may be used to transport hydrocarbon fluids over long distances.
Background
Production wells are used to produce fluid from reservoirs in the geological
subsurface.
In particular, fluids in the form of oil and gas are produced through wells,
as is routinely
the case in the oil and gas industry. The production fluid is typically
received in the well
from the subsurface reservoir due to the natural pressure conditions, and then
flows
out of the well inside a dedicated production tubing disposed in the well. A
production
pump may be installed in the well to help draw fluid into the well and along
the
production tubing to the surface. The production fluid from the well is then
transported
along pipelines to a downstream facility, for example a floating production
platform (in
the case of an offshore well) where the fluid may be processed further.
Additional
"booster pumps" may be provided in the production system at the surface, for
example
on the seabed, to help pump the production fluid from the well along the
pipeline to the
downstream facility at a suitable rate.
The fluid received in the well may in general vary in composition between
different
reservoirs and oil fields. For example, the production fluid may be multiphase
fluid
containing oil, gas and water in varying amounts, depending upon the oil field
or
reservoir in question. In addition, various solids may be carried in the
fluid. This leads
to challenges with transporting the fluid, and it is important to ensure that
the produced
fluid can flow and be transported effectively over time, as the costs of
shutdowns and
repair are substantial. In the transport of oils, wax may precipitate out in
solid form and
deposit on internal surfaces of the pipelines or other flow channels if the
temperature of
the oil drops below a certain wax appearance temperature (WAT).
In addition,
hydrates may form inside the pipe, below the relevant hydrate limit.
Such wax
deposits and hydrates can cause blockages in the pipe. Thus, it is important
to design
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systems for producing and transporting fluids that take into consideration
such
challenges, to provide so-called "flow assurance" in the fluid production
system.
Wax and hydrate control is particularly an issue in cases of transporting
produced fluids
along pipelines over long distances (e.g. 10 km or more) in the subsea
environment, as
the temperature of the production fluid will tend to drop significantly as
heat is lost
across the pipeline walls into the surrounding sea. The sea can typically have
a
temperature at the seabed of around 4-5 C, and even sub-zero temperatures can
exist
in deep areas.
Some reservoirs are much more difficult to exploit than others. Remote
reservoirs at
shallow depth and low temperature and/or pressure (close to the wax or hydrate
limits)
have been considered to have such onerous requirements that they have been
considered uneconomic or unfeasible for production with existing flow
assurance
approaches.
Summary of the invention
The inventors have developed solutions for producing fluids from shallow low
temperature reservoirs, such as those described above. In particular
embodiments, the
solutions go against traditional approaches to flow assurance design.
According to a first aspect of the invention there is provided a method of
transporting
production fluid from a well, comprising pumping the production fluid through
at least
one section of pipe so as to prevent the fluid in said section of pipe from
dropping
below a predetermined temperature.
According to a second aspect of the invention there is provided a method of
transporting production fluid from a well, comprising pumping the production
fluid
through at least one section of pipe so as to protect the fluid against any
one or more
of: hydrate formation; wax appearance; and wax deposition.
According to a third aspect of the invention there is provided a method of
transporting
production fluid from a well, comprising using at least one pump to pump the
fluid
through at least one pipe section, the pump and pipe section being arranged so
that
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the fluid interacts with a surface of the pipe section and generates friction
heat so that
wax appearance or wax deposition, or hydrate formation is thereby prevented.
The production fluid is preferably pumped to generate friction heat equal to
or greater
than the heat loss from the pipe section to its surroundings.
According to a fourth aspect of the invention there is provided a method of
transporting
production fluid in a pipe, the method comprising operating at least one pump
to pump
the fluid through at least one section of the pipe and generate friction heat
at said
section, the friction heat being equal to or greater than a predicted heat
loss, to protect
against any one or more of: hydrate formation; wax appearance; and wax
deposition.
The method may further comprise predicting said loss of heat. The production
fluid
may be pumped using a pump operating at a predetermined level based upon the
predicted heat loss.
Preferably, the pumping is performed by at least one "booster" pump which acts
to
boost the flow of production fluid from the well. This booster pump may for
example be
a seabed booster pump, e.g. placed on the seafloor, for boosting the flow of
production
fluid from the well. By way of pumping, a thermal effect can be generated in
the fluid
and/or the pipeline, which restricts or limits the cooling of the production
fluid. The
effect by the pump is necessary and sufficient to prevent the cooling of the
fluid below
the predetermined temperature, e.g. wax appearance or hydrate equilibrium
temperature. By operating in this way, the pipe can transport the fluid in a
wax-safe or
hydrate-safe operational envelope. The fluid is preferably pumped to generate
heat
equal to or greater than the heat loss from the pipe to its surroundings. The
pipe can
be any length, but this solution is particularly applicable to long distance
pipelines, for
example those of over 30 km in length, and in particular those greater than 50
km, and
yet more so in pipelines over 100 or 200 km in length, for example pipelines
in the
range of 100 to 200 km. The pipe is preferably insulated providing a low
insulation
coefficient U, which is typically equal to or less than 1 W/m2K. Preferably,
the pipe
comprises at least one pipe-in-pipe (PIP) section, for insulating the pipe.
The PIP
section may comprise an inner pipe section disposed within an outer pipe
section,
wherein the production fluid is pumped through the inner pipe section. The
pipeline
can have a diameter which is in general dependent upon the application or
reservoir
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case, but typically, for example for a long distance pipeline, a diameter is
selected
which is less than normally used in the prior art, where the normal strategy
is to
minimise pressure loss. The diameter may be for example less than 10 inches.
The
fluid can be pumped to boost the pressure in the production fluid to generate
for
example 100 bar pressure drop along the pipeline, although this is in general
application dependent.
The necessary pressure can be generated using known booster pump technology,
for
example by connecting several pumps in series which each help to increase the
pressure and flow rate of the fluid. In certain variants, the production fluid
may
comprise multiphase fluid from a well, and said pump used to pump the
production fluid
may comprise a first, multiphase pump. The method may then comprise operating
the
multiphase pump to pressurise the fluid to produce single phase production
fluid
downstream of the pump. The pump used to pump the production fluid may further
comprises a second, single phase pump, and the method may comprise using the
single phase pump to pump the produced single phase production fluid from the
first
pump, the first and second pumps together operating to generate said friction
heat in
the pipe to protect the fluid from wax or hydrate deposition. It will be noted
that the first
and second pumps could be provided on a common production facility on the
seabed.
It can be preferably to pump the pipeline in single phase and using single
phase
equipment, because single phase flows are generally less demanding in terms of
equipment to process and their flow stability.
The booster pump advantageously provides both the boost for carrying the fluid
the
necessary distance to the destination for the production fluid and also can
act to keep
temperatures from dropping below wax and hydrate limits. Accordingly,
dedicated
heating equipment to prevent wax may be unnecessary.
Frictional resistance arises between the flowing production fluid and the
surface of the
pipe through which the production fluid passes. Heat is generated due to
frictional
resistance and the heat generation increases with increased pressure gradient,
which
in this case can be manipulated through a slightly smaller than normal pipe
internal
diameter. The frictional resistance, and heat to be generated, can also depend
upon
the fluid type, in particular the viscosity of the fluid. The fluid is
typically a hydrocarbon
fluid, and may comprise oil, gas, and/or water. In the envisaged application,
the fluid
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may include heavy oil for example from a shallow reservoir. The frictional
resistance
depends also on the material roughness of the pipe section(s) through which
the
production fluid is pumped. The pipe may have a diameter adapted to
generate heat
by work against frictional resistance using the pump.
5
Modelling of the system may be performed to take into account any one or more
of the
following parameters: the surface roughness of pipe section along which the
fluid
passes upon being pumped, the pressure to be generated by the pump, the fluid
type
or viscosity, the gas oil ratio (GOR), length of pipe or pipe sections, pipe
insulation
coefficient, pipe diameter. Based on such modelling, the pump parameters
needed to
produce the friction heat for preventing the wax deposition or hydrate
formation. The
parameters of the system, and in particular the pump operational level
required to
produce the preventative heat effect, can be optimised based on this
modelling.
The present method is particularly of use when the hydrocarbon reservoir (and
hydrocarbon fluids therein to be produced) is at low temperature, for example
close to
a wax appearance temperature or hydrate equilibrium or hydrate formation
temperature, for example less than 5 C, such as 1 C or less or 2 C or less,
above that
temperature. Hydrate equilibrium temperatures may typically be 20 C or less,
30 C or
less, or even 40 C or less. Wax appearance temperatures would typically be in
the
range of 15 to 30 C. The fluid from the reservoir typically comprises oil,
which can be
of any kind. The present method may be particularly useful where the fluid
comprises
heavy oil, for example extra heavy oil with components susceptible to wax
formation.
The fluid from the reservoir may have a low gas-to-oil ratio (GOR) and/or a
low bubble
point.
According to a fifth aspect of the invention, there is provided a method of
transporting a
production fluid comprising providing at least one pipe section arranged to
transport the
production fluid, and circulating a circulation fluid so as to be in thermal
communication
with the pipe section and provide thermal energy that serves to protect the
production
fluid from any one or more of: hydrate formation; wax appearance; and wax
deposition..
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The circulated fluid and the production fluid are typically present on
opposite sides of a
wall of the pipe section. The circulation fluid is preferably circulated,
adjacent to the
pipe section, for example in an annulus around the pipe section.
In a sixth aspect of the invention, there is provided a method of transporting
production
fluid in a subsea pipeline, which comprises generating friction heat by way of
said fluid
flowing through the pipeline, so that wax appearance or deposition, or hydrate
formation, is thereby prevented. The method may further comprise using a pump
to
pump the fluid through said pipeline to generate the friction heat. The
generated
friction heat is preferably equal to or greater than the heat loss from the
pipeline to its
surroundings, e.g. across the pipeline wall, e.g. to the sea.
In a seventh aspect of the invention there is provided apparatus for
performing the
method of the any of the first to sixth aspects.
Further advantages of the particular features and embodiments the invention
will be
apparent from the description, drawings and claims.
Each of the above aspects may have further features as described in any other
aspect,
and features described in relation to one embodiment may be included in other
embodiments, as an additional feature or in exchange for another like feature.
Description
There will now be described, by way of example only, embodiments of the
invention
with reference to the accompanying drawings, of which:
Figure 1 is a schematic representation of apparatus for producing fluid from a
well
according to an embodiment of the invention;
Figure 2 is a cross-sectional representation of the well and tubing therein of
Figure 1
(with the exception of the pump and annular packer which are merely shown
schematically);
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Figures 3A and 3B are graphs of simulation results for production fluid
temperature and
fluid velocity against distance for a pump-driven flow;
Figure 4 is a block diagram representation of a method of producing fluid from
a well
according to an embodiment of the invention; and
Figure 5 is a block diagram representation of method of producing fluid from a
well
according to another embodiment.
With reference to Figure 1, there is depicted apparatus 1 for producing oil
from a well
50. The apparatus is shown as being distributed across locations A, B and C.
The well
is a subsea well and is shown at location A as extending from the seabed into
a
subsurface hydrocarbon reservoir 51. The well 50 is fitted with a Christmas
tree 52 at
the seabed 53 at the top of the well, which provides valves and connections
for
controlling the well and providing access for fluids into and out of the well.
At location
B, also on the seabed 51, the apparatus 1 has a pump station 20, and at
location C the
apparatus has a floating production facility 30 on the sea surface 21 to which
the
produced fluid from the well is transported.
With further reference to Figure 2, the apparatus has a downhole production
pump, in
the form of hydraulic submersible pump (HSP) 2 which is disposed in the bore
of the
well 50. The HSP 2 is powered hydraulically by a power fluid such as water
which is
supplied into the well to the HSP 2 in a closed loop circuit 3. The power
fluid for the
pump is supplied along a circulation-In pipe 4, along an annular flow region
13, and
back out of the well along a circulation-Out pipe 5. The apparatus has a
circulation
pump 6 at the pump station 20 which pumps the power fluid along the closed
loop
circuit 3 to the HSP 2 in the well.
The production pump 2 is used to draw production fluid, e.g. hydrocarbon fluid
such as
oil and gas, from the reservoir into the production tubing 7 and pump the
production
fluid out of the well toward the production facility. To facilitate carrying
the production
fluid to the production facility, the apparatus has a booster pump 8, which is
also
provided on the pump station 20 at the seabed. The booster pump 8 is arranged
to
pump the production fluid along a pipeline 9 to the production facility 30.
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The apparatus 1 is applied particularly to help produce oil from shallow
reservoirs
where reservoir temperatures are relatively low and the oil is close to the
temperature
below which wax may precipitate from the oil or below which hydrate may form.
In
such conditions, there is a risk of wax being deposited and blockages forming
inside
the production tubing as the oil cools as it is transported out of the well.
The circulation pump 6 is run at a speed by which significant heat energy is
generated
in the pump. The heat transfers to the power fluid in the pump, as the fluid
passes
through. The power fluid is delivered into the well through the circulation-In
pipe and
the flow space 13 in the well, so that it circulates adjacent to the
production tubing.
The flow space 13 is provided between the production tubing 7 and an outer
tubing,
such as casing 14, which lines the formation wall 15 of the well. Heat energy
in the
power fluid can be transferred between the power fluid and the production
fluid across
the production tubing, e.g. across the production tubing wall.
By circulating the power fluid in the closed loop, heat energy is added to the
power fluid
incrementally at the pump. In this way, the circulation pump provides
sufficient heat in
the power fluid to keep the temperature in the fluid at or above a desired
temperature.
By keeping the temperature at or above the desired temperature, the presence
of the
power fluid around the production tubing can prevent the fluid in the
production tubing
from dropping below a certain temperature. The addition of heat energy at the
pump
can compensate for heat losses in the loop, so as to maintain a consistent
temperature
in the power fluid as the power fluid is circulated through the well. The
desired
temperature in the power fluid can be determined according to requirements,
but is
preferably not less than the temperature at which wax or hydrate is produced,
in order
to prevent deposition or blocking issues. In some cases, the temperature
sought in the
production fluid may be a few degrees above the temperature at which wax is
precipitated or above the hydrate equilibrium temperature in order to give a
suitable
error margin. In practice therefore the power fluid that is circulated has a
temperature,
which is equal to or above the minimum temperature sought for the production
temperature, e.g. a minimum temperature limit. The power fluid in the annulus
surrounding the production tubing acts in effect as a layer of insulation or
thermal
"blanket" which stops temperature in the production fluid from falling too
low. The
production tubing is heat conductive so that heat energy from the power fluid
can be
transferred conductively across the wall of the production tubing from the
power fluid
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into the production fluid. In this way, there is provided thermal
communication between
the power fluid and the production fluid.
In the variant of Figure 1, the closed loop includes a heater 10 which serves
to add
heat energy to the circulation fluid returning out of the well, if the
necessary
temperature in the power fluid is not achievable with only the heat energy
generated in
the circulation pump 6. It can be noted that the apparatus may include
temperature
sensors to monitor the temperature in the power fluid and/or the production
fluid. Data
from the temperature sensors may be used to control the circulation pump 6,
and
optionally the heater if used, so that the necessary temperatures are
generated in
power fluid and the production fluid, in order to perform as described above.
In Figure 1, the apparatus is shown during production. Thus, the power fluid
is
circulated continuously into and out of the well along the circuit 3 while
production fluid
is being produced via the production pump 2. The production fluid and the
circulating
power fluid are carried out of the well separately, along separate flow paths.
Prior to production starting, the power fluid can be circulated in the well
and heated
with the circulation pump 6 in the same way as described above, to prepare the
production tubing for production. For example, the power fluid may be used to
bring
the production tubing up to temperature, to avoid wax problems at the start-up
of
production (when using the HSP production pump). To do so, a valve may be
provided
at the HSP for the power fluid to bypass the HSP when not operational. The
valve may
be configured to produce a thermal effect in the power fluid to generate heat
or
increase the temperature in the circulation fluid at the bypass or valve
location, so as to
improve the performance of the circulation fluid and enhance supply of heat
energy for
the production tubing.
Upon exiting the well, the production fluid flows through a connecting pipe 11
to the
booster pump 8. The booster pump 8 is used to pump the production fluid along
the
subsea pipeline 9 to the floating production facility 30.
The booster pump 8 is operated to generate significant pressure and velocity
in the
pipeline 9 downsteam of the booster pump 8. This, in turn, generates
substantial
friction heat due to the frictional resistance between the production fluid
and the
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pipeline wall. The generated friction heat prevents the production fluid in
the pipeline 9
from dropping below a certain temperature over the length of the pipeline, to
prevent
wax appearance, deposition and/or hydrate formation. Preferably, the pipeline
9 is
insulated with insulation provided around the outside of the pipeline. For
example,
5 thermal insulation with a coefficient U of equal or less than 1 W/m2K
could be used for
a pipeline which is 200 km long, although the technique could be suitable for
pipelines
in general of for example 30 km upwards. Good insulation properties may allow
the
pump speed and capacity to be reduced. The friction heat effect generated in
the
pipeline by operation of the booster pump 8 to yield high fluid rates and
pressure is
10 described in further detail below.
In other embodiments, a plurality of booster pumps operating such as the pump
8 is
provided sequentially along the pipeline. In this way, a given pump in the
sequence
only needs to operate to provide a sufficient effect for the length of the
pipeline onward
to the next pump (or, in the case of the final pump, onward to the facility).
This can
help to reduce capacity requirements of individual pumps.
In certain embodiments, the power fluid can comprise water. Such water can be
supplied through a supply tubing 12 and valve 13 from the floating production
facility.
The tubing 12 is primarily used to supply separate injection wells with water
for
injecting into the reservoir but can also supply water to the loop circuit if
required.
However, as the loop circuit 13 is a self-contained closed loop, there is in
general little
need for it to be supplied with water once it has been filled.
Turning to Figure 4, a method 100 for producing fluid from the well 50 is
illustrated by
steps 51 to S3 in the figure. At 51, hydrocarbon fluid from the reservoir is
transported
out of the well. The fluid is passed onward to a subsea booster pump. At S2,
the
booster pump pumps the hydrocarbon fluid to facilitate transport of the fluid
to a
processing platform destination downstream. The booster pump is operated at a
high
level so that it produces high pressure in the fluid immediately downstream of
the
pump. The pressure drives the flow against frictional resistance between the
production fluid and the inside wall surface of the pipeline, generating
friction heat
energy along the pipeline that keeps the temperature in the fluid high. The
energy
generated replenishes the heat loss to the sea from the pipeline along its
length,
keeping the temperature of the fluid more or less constant, above the wax and
hydrate
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limits. The fluid is carried in the pipeline and, at S3, is received at the
processing
platform, where the fluid may be processed further. The booster pump serves to
pressurise the fluid both to transport fluid and generate friction heat in the
pipeline
downstream to keep it warm over long distances.
In Figure 5, a method 200 for producing fluid from the well 50 is illustrated
by steps Ti
to T3 in the figure. This method is concerned with flow assurance particularly
in the
well and in the transport of the hydrocarbon fluid from the well to the
booster pump.
At Ti, the power fluid is pumped into the well using the power fluid
circulation pump.
The power fluid is at a temperature above wax/ hydrate limits of the
hydrocarbon fluid
to be produced. The power fluid is supplied with heat energy by the pump to
keep the
power fluid warm. At T2, the power fluid is circulated along a flow path
where the
fluid contacts the surfaces of the production tubing (which is pre-provided in
the well).
In this way, there is thermal communication between the power fluid and the
production
tubing, and provision for the transfer of heat energy there between (The
production
tubing is heat conductive). This circulation takes place in this example prior
to
production has started. At T3, the HSP in the well is activated and production
starts,
with the HSP operating to pump hydrocarbon fluid from the reservoir out of the
well and
the power fluid driving the HSP. The power fluid continues to circulate in
contact with
the production tubing and provides an insulative blanket for the production
tubing such
that the production fluid temperature does not drop below the hydrate or wax
limits, in
the flow to the seabed booster pump 8. The power fluid has a dual purpose in
that it is
used both to power the production HSP and to keep the production tubing warm.
It should be distinguished between the generation of friction heat as used in
the
production transport pipeline 9 and that of "pump heat" as used in the
circulating power
fluid in the well bore. With regard to the latter, as the circulation pump 6
operates, heat
energy is generated in the circulation pump 6. The circulation pump becomes
"warm"
due to the interaction and working of moving parts in the pump, including for
example
the pump motor. The generated heat energy can transfer to the power fluid in
the
pump, to heat the power fluid, or maintain a temperature therein. It can be
noted that a
similar heat generative effect is produced in the booster pump 8, although in
general it
is not sufficient to provide the necessary protection against wax deposition
and hydrate
formation in the pipeline 9. Accordingly, the booster pump 8 operates to
produce
pressure and fluid velocity downstream of the pump so that substantial
friction heat is
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generated against the frictional resistance of the pipeline. Likewise, the
circulation of
power fluid using the circulation pump 6 will result in some downstream
friction heat
generation due to the flow of power fluid in the supply pipes and fluid
passageway of
the closed loop. However, the friction heat in this case is not substantial
compared
with the incremental heat energy generated in the circulation pump 6, and
added to the
power fluid as it is circulated. It can further be noted that different
conditions are
applicable to the use of the circulation pump 6 and circulation of power fluid
in the well
(compared with the transport of production fluid with booster pumps), in
particular: the
power fluid is circulated in a closed loop whereby it repeatedly passes
through the
circulation pump; the circulated power fluid travels typically a lesser
distance; and heat
loss is less extreme, as the well environment is "warmer".
Design principles
The principle of using the booster pumps to generate friction heat in the
pipeline
downstream of the pump provides a technique for flow assurance in long
distance
transport of liquid dominated well streams.
The temperature in the well stream (comprising production fluids) is
maintained above
the hydrate and wax limits through balancing frictional heat production and
thermal
heat loss. The flow is kept warm through its own work. It is kept just warm
enough so
that hydrate or wax precipitation does not occur.
In order to produce the necessary effect, a high pressure drop and good
insulation of
the pipeline is needed. The pump is configured to drive flow through a small
internal
diameter pipeline, adding energy to the system as pressure. Insulation with a
thermal
coefficient of U equal to or less than 1 might typically be used, for example
by providing
the pipeline through which the fluid is pumped as a Pipe-in-Pipe arrangement.
This is an opposite design mind set to that in normal flow assurance design.
In normal
design, it is sought to minimise pressure drop and insulation, with a view to
saving
energy and minimising cost. In the design in the present invention, pressure
drop is
maximised and super insulation is used to balance heat loss and generation.
This
allows fields to be developed which ordinarily would have been rendered as
"not
feasible" for production by normal flow assurance design considerations.
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Heat is generated through viscous dissipation when the pressure gradient in
the pipe
does work against friction on the pipe wall. Heat is lost through temperature
gradient
driven conduction through the pipe wall. These phenomena are sought to be
balanced
by the operating the pumps and configuring the pipe suitably.
When these are balanced, the temperature of the fluid stays constant along the
pipeline (neglecting other thermodynamic effects due to pressure drop along
pipeline,
which is usually small in liquid systems but may be significant when gas is
present (J-
T-cooling). The energy which is provided as pressure at the inlet to drive
flow
becomes available as heat along the pipeline, to help solve flow assurance
issues such
as hydrates and wax.
Heat generated, force*distance/ time, can be defined as:
dP
QG = ¨dxAxsV (Equation 1)
where dP/dx is the pressure gradient, A, is the pipe cross-sectional area, and
V is the
fluid velocity.
Heat lost, thermal loss coefficienrsurface area*temperature difference, can be
defined
as:
QL = UApsAT (Equation 2)
where U is overall heat transfer coefficient, Aps is pipe surface area, and LT
is
temperature difference.
If the heat generated is larger than or equal to the heat lost, then the
temperature will
not decrease along the pipeline. This relation can be expressed as follows:
32rh3f
QG QL ¨dPA,V U ApsAT or 7r2p2D5 > Urt-D AT
dx
(Equation 3)
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where dP/dx is the pressure gradient, Axs is the pipe cross-sectional area, V
is the fluid
velocity, U is overall heat transfer coefficient, Aps is pipe surface area, LT
is
temperature difference, rh is mass flow rate, f is Fanning friction factor, D
is pipe
internal diameter, and p is fluid density.
The relation of Equation 3 can be manipulated to give, for an otherwise given
system, a
minimum insulation (maximum U) value, minimum mass (production) rate in, the
minimum velocity V, maximum pipe diameter D, maximum temperature difference
LT,
and the e-folding length Le approaching LT. The expressions for these
parameters are
listed below:
32rh3f
U < ________________________ (Equation 4)
¨ 7r3p2D6AT
7rD2 3 2p2UAT
lh, f
> ¨ _______________________ (Equation 5)
¨ 4
. . . . _ 3, \ I /2U LT
V ---- ¨ (Equation 6)
¨ Pt
6, \ I 32rh3f
D < (Equation 7)
3 2 1 LAT
Tr p
32rh3f
AT = _______________________ (Equation 8)
7r3p2D6u
L = filCP (Equation 9)
e 7rDU
The e-folding length parameter indicates exponential change and is the
distance from
the pipeline inlet where temperature has changed by (1-1/en)*LT. At the first
e-folding
length, LT has reached about 63% of the final/maximum/steady state value. In
the e-
folding expression of Equation 9, the parameter Cp is the fluid heat capacity.
Feasibility example
Simulations for transport along a 40 km pipeline have been performed. The
pipeline
inlet temperature was 20 C after boosting, somewhat above a wax appearance
temperature of 17 C. The pipeline has a PiP configuration with U-value of 1
W/m2K, a
CA 02953434 2016-12-22
WO 2015/197784 PCT/EP2015/064441
Fanning friction factor of 0.004, 50% water cut with mixture density of 900,
and the
ambient temperature (mimicking the seawater environment at the seabed) is 5 C,
providing a LT of 15 C. The equation 7 indicates that the diameter of the
pipeline
needs to be less than 0.2707 m, and equation indicates that the velocity will
be 2.03
5 m/s.
Results from an OLGA simulation are shown in Figures 3A and 3B. OLGA is
commercially available software. Figure 3A shows that the temperature remains
roughly constant at 20 C along the length of the pipeline, well over the
hydrate and wax
10 limits, and velocity is just over 2 m/s. A small effect of pressure
dipping below the
bubble point is evident in the results after about 30 km. The simulation
assumed a well
stream with a gas to oil ratio (GOR) of 48, and a bubble point of about 70
bar. The inlet
pressure is 114 bar, with a suction pressure of 14 bar, giving 100 bar
boosting by the
booster pump. In order to provide this, the power required might typically be
less than
15 1.5 MW, and typically is less than 0.5 MW to heat the PiP pipeline using
EHT to above
the hydrate limit. It was also found in the simulations that the time to reach
the hydrate
limit upon shutdown in this configuration is about 20 hours, which is a long
cool down
time and facilitates flow assurance during an unplanned shutdown situation.
Various modifications and improvements may be made without departing from the
scope of the invention herein described.
