Note: Descriptions are shown in the official language in which they were submitted.
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INFLOW DETECTION APPARATUS AND SYSTEM FOR ITS USE
Field of the Invention
This invention relates to a method for measuring
fluid flow in a subterranean formation; in particular
measurements of flow rates of liquids, gases, and mixed
fluids in subterranean formations.
Background
Recent developments in the oil drilling industry of
well bore construction techniques such as horizontal
wells and multi-lateral wells, present new challenges to
the completion and reservoir engineering disciplines.
High rate horizontal wells in deep water conditions
further push the technology tools the petroleum engineer
has available to safely and prudently produce the
reservoirs.
Classical methods of reservoir monitoring assume the
permeability (" K" ) and height (" H" ) of the zone
contributing to the production of the well is known.
This "KH" is often confirmed with production logs on a
periodic basis and is typically considered constant. The
KH of a well is paramount for most reservoir
calculations. In a horizontal well or a multi-lateral
well, the H of the well bore penetrating the reservoir is
known from electric logging methods, and more recently by
logging while drilling techniques. However, the logged
reservoir interval may not be the same as the H actually
contributing to the well production and, in fact, the H
may change with time.
The industry has adopted a laze faire attitude
relating to the assumption of inflow performance in
horizontal and multi-lateral wells. Grand assumptions
regarding inflow well performance are made based on
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surface data (i.e. flow rates, pressures, water cut, etc.),
possible down hole pressure gauges, and rules of thumb. The
reality is that these assumptions can lead to poor well
performance, poor reservoir management, completion equipment
failures, and in the worst cases, catastrophic failure of the
well.
The only method currently available to the reservoir
or production engineer to monitor changes or losses in "H" is
to run a wire line or tubing deployed production log during
well interventions. These logs are difficult to interpret,
particularly in horizontal and high angle wells. This is due
to the flow meters inability to measure the 3 phase flow
rates, often referred in the literature as water hold up or
gas blow by. This procedure of production logging and those
known from European patent application Nos. 0442188
and 0508894 require a rig mobilization, resulting in lost
production during the rig up and rig down of the logging
equipment, and presents a risk of losing equipment in the
well. Production logging is not always possible (e.g. some
subsea completions or wells in which an electrical submersible
pump (ESP) is installed). Moreover, since the production
logging data is subject to interpretation, the decision to run
the production-logging suite is often avoided. The end result
is that the production is maintained by increasing the choke
size at the surface. This can result in more damage, and
ultimately in screen and wellbore failures or large hydrate
production and blowouts.
A method for monitoring fluid flow within a region
to be measured of a subterranean formation is known from
European patent application 0442188. In the known method a
doppler flowmeter is temporarily lowered into a wellbore on a
wireline. Another logging probe which is equipped with fibre
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optical signal generation and detection means is known from
European patent application No. 0508894.
Summary of the Invention
In accordance with one aspect of the present
invention, there is provided a method for monitoring fluid
flow within a subterranean region, said method comprising:
placing at least one source within said subterranean region;
placing at least one sensor within said region to be measured,
wherein each said at least one sensor is adjacent to at least
one source such that said sensor measures changes to said
fluid caused by said source; providing at least one means for
transmitting data from each said at least one sensor to at
least one data collection device, said at least one data
collection device capable of communicating with an operator;
characterised in that said source and/or sensor comprise a
heat source and a thermal sensor that are placed permanently
within said subterranean formation and/or wellbore.
The method of an embodiment of the invention is
characterised in that a source and sensor are mounted
permanently within a subterranean wellbore and/or surrounding
formation.
Detailed Description
The method of the invention provides a means for
monitoring the flow of fluid, wherein fluid means liquids or
gases or mixtures of liquids and gases, from subterranean
formations. Measurement takes place directly in the region
where a measurement is desired. In the case of a flowing
well, the measurements may be taken while the well is
producing. Thermal and/or acoustic sources are placed in the
fluid flow path and sensors capable of detecting temperature
or acoustic
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changes placed near the sources detect changes to the
fluid caused by the sources.
One embodiment of the invention provides a method for
monitoring fluid flow within a region to be measured of a
subterranean formation. At least one source is placed
within the formation. Placement is relatively permanent,
meaning the source is set and then left in the
measurement zone. At least one sensor is also placed
within the region to be measured. Each sensor should be
adjacent to one or more sources, in close enough
proximity to measure changes to the fluid caused by the
source(s). It is necessary to also provide at least one
means for transmitting data from the sensors to at least
one data collection device. The data collection device
may be subterranean, on the surface, or in the air but it
must be capable of communicating with an operator. As
used herein, an operator may be an object, such as an
operating station, or a human.
The sources may be optical sources, electrical heat
sources, acoustic sources, or combinations thereof.
Examples include thermisters, optical heaters, continual
heating elements, electric cables, sonar generators, and
vibration generators. Because it is optimum to limit
restrictions in the formation, the preferred sensors are
optical fibres, which are small enough to be non-
intrusive. The optical fibres may also act as the data
transmission means, thereby serving two purposes. The
sources and the sensors are preferably oriented
perpendicular to the fluid flow.
When the subterranean formation is a well, the fluid
flow region to be measured is typically within the well
bore, be it vertical, horizontal or deviated. A means
for deploying the sensors and data links in a fairly non-
intrusive manner is via hollow tubular members.
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The system of the invention is expected to perform
well using applied well technology known as Micro Optical
Sensing Technology ("MOST"). MOST allows for the
miniaturization of sensing equipment in submersible
equipment. Fundamentally, oil and gas well environments
have restricted geometry and hostile conditions of
temperature and pressure. MOST is able to function in
these environments due to it's ability to use very small
diameter data links (optic fibres) and to use sensors
that can withstand temperatures above 200 C.
Since the sources, sensors and data links are
permanently installed in the desired region of the
formation, there is no need for well interventions, such
as production logging. The method can provide a
continual inflow performance profile of the formation on
a real time basis and multiple flow detection nodes along
the formation can be monitored.
The use of thermal sources and sensors will be used
as an example. A series of electrically or optically
powered heat sources may be placed along a well bore axis
parallel to a series of thermal sensors. The thermal
sources may be in many forms, including but not limited
to single point heating elements like thermisters,
optical heaters, or a continual heating element like
electric cable.
The heat sensors are preferably single or multiple
optic fibres. The fibres may be deployed into the well
in multiple means and in multiple geometry. An example
of deployment which will protect the fibres from hydrogen
exposure is to arrange the temperature sensors and data
links in small hollow members, such as tubes. The flow
detection system is formed by placing the optic fibres in
the flow stream before the heaters, after the heaters, or
both. Other embodiments uses the optic fibres and
heaters deployed parallel to one another, surrounding one
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another in coil configurations, and many other
geometry's. The preferred embodiment places the heat
source and thermal sensors perpendicular to the fluid
flowing in the well bore, such that the heat source heats
the fluid while the thermal sensors measure the heat
change in the fluid stream flowing over the heat source.
This system then forms a series of classic thermal flow
meters according to the following simplified heat flow
equation:
Q = Wcp (T2 - T1)
where
Q = heat transferred (BTU/Hr);
W = mass flow rate of fluid (lbm/Hr); and
cp = specific heat of fluid (BTU/lbm F).
The accuracy of the flow meter is dependent on the
accuracy of specific heat data for the flowing fluids.
The specific heat of the fluids in the well will change
with time, flowing pressures, and reservoir conditions
(e.g. coning).
Optimum well production requires the heat sources and
temperature measurement devices to be small and non-
intrusive to the well bore inside diameter. Non-
intrusive deployment allows for the well to be fully
opened and thus allows for stimulation, squeeze, or
logging techniques to be performed through the completion
with the sources, sensors and data links permanently
installed.
The preferred sensors and/or data links of the
invention are optic fibres. Optic fibres are exotic
glass fibres which are available with many different
coatings and by various different manufacturing methods
that affect their optical characteristics. Optic fibres
have a rapid decrease in functionality when exposed to
hydrogen, and of course subterranean water is a readily
available hydrogen carrier. Therefore the fibres must be
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placed in a carrier. But other characteristics of optic
fibres allow one fibre to read multiple changes along the
fibre's length, an obvious advantage.
Fibers may be used in oil and gas wells in
conjunction with Optical Time Delay Reflectometry
("OTDR" ) devices (commonly referred to as "intrinsic
measurement"). Intrinsic sensing along the fibre is done
with application of quantum electrodynamics ("QED"). QED
relates to the science of sub-atomic particles like
photons, electrons, etc. For this application, interest
is in the photons travelling through a very special glass
sub-atomic matrix. The probability, or probability
amplitude, of the photon interacting with a silicon
dioxide sub atomic structure is known for each
specialized optic fibre. The resulting back scattering
of light as a function of thermal affects in the glass
subatomic structure has a very well known relationship to
the index of refraction of the optic fibre. Knowledge of
the power and frequency of the light being pumped, or
launched down the optic fibre allows for calculation of
the predicted light and frequency emitted or back
scattered at a given length along the optic fibre.
The process of the invention uses OTDR and thermal
and/or acoustic sources to measure flow in wells. Flow
changes at each node may be monitored versus time,
providing a qualitative measurement on a permanent basis
in real time. Knowing the glass and laser light being
used, a back scattering returning power can be measured
with "OTDR" according to the following equation:
Pbs (1) = &I POAtvgCsNA2exp (J-2(xdx)
where
Pbs = backscattering power returning from distance 1;
PO = launch power;
At = source time pulse width, in time units;
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vg = group velocity;
Cs = scattering constant;
NA = numerical aperture of fibre; and
a = total loss of attenuation coefficient.
OTDR can successfully and very repeatable measure the
back scattering changes as a function of temperature
caused by a laser pulsed light wave down an optic fibre,
by relating Cs to and a.
Cs = (ar) co +(as)co + Pc/Pt (as)d
and
a = aco + Pc/Pt (ad)
where
ar = Raman scattering coefficient;
as = Rayleigh scattering coefficient;
()co = parameter associated with fibre core;
()cl = parameter associated with fibre cladding; and
Pcl/Ptotal = ratio of total power exists in cladding
due to evanescent wave effects.
The OTDR equipment uses a laser source, an optic
fibre; a directional coupler connected to the fibre, an
optoelectronic receiver, signal processing, and data
acquisition equipment.
The method of the invention allows simple actions to
be performed downhole without surface intervention, and
allows reservoir performance downhole to be monitored
using 4D seismic and other technologies. The present
invention may also be applied to other flow processes
(i.e. pipelines, refining processes, etc.).
MDOB/TH1273PCT
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