Introduction
[0001] The invention is in the field of reservoir monitoring by estimating the formation
pressure (the pore pressure on the borehole wall), in selected depth intervals in
a petroleum producing well while draining the reservoir, using installed tracer sources
in potentially petroleum-producing zones of the well. Depending on the configuration
of the tracer sources installation method and the flow pattern in the formation, the
so-called reservoir back pressure field and the reservoir boundary pressure may be
estimated.
[0002] A producing petroleum well, particularly a naturally producing petroleum well, will
decrease the pressure of the reservoir formation. A simplified section through an
imagined petroleum well drilled through geological formations, some of which are reservoir
rocks, and the well completed, is illustrated in Fig. 1. The geological formation
comprises in the parts of a reservoir shown, an upper general pressure barrier I,
e.g. shale, which is rather fluid proof, and another lower pressure barrier II. There
may also be a fault which comprises locally metamorphosed rocks or precipitations
which forms a third pressure barrier which may be more or less vertical and cuts through
the formations. The reservoir back pressure in the different parts of the reservoir
is what drives fluids out through the borehole walls to the producing annulus and
towards apertures in a production pipe in the well. The reservoir back pressure field
within the reservoir, apart from the hydrostatic pressure gradient, may be approximately
homogeneous when the production valve has been let closed and the reservoir back pressure
field has equalized for a sufficiently long period of time, because the field may
have a weak throughout permeability which allows a slow pressure equalization to take
place within the reservoir when everything else is held static. Normally, the reservoir
back pressure field has a large buffer capacity with a very long time constant. The
reservoir back pressure field, however, is not homogenous during production. It will
change locally according to the drain pressure in the tubing, according to local permeability,
viscosity of the produced fluid, and local geological features, and form a varying
pressure gradient around the well when production fluids such as oil, gas and water
flow when the production valve is open. One of the main reasons the reservoir back
pressure field may change inhomogeneously is that it has not had sufficient time to
be equalized far from the well. It will thus of interest to try to map the reservoir
back pressure field along a producing well.
Background art
[0003] The international
PCT patent application WO2013135861A2 published 19.09.2013 by Terje Sira and Tor Bjornstad presents an apparatus for tracer
based flow measurement. The apparatus comprises a tracer chamber for installation
on a production tubing. The tracer chamber is arranged for holding tracer and is arranged
to be linked, in use, to the pressure in an annulus about the production tubing. The
tracer chamber comprises an outlet for fluid communication between the tracer chamber
and the fluid within the production tubing. Tracer is released through the outlet
into the production tubing in accordance with a pressure differential between the
annulus and the production tubing. The general principle of Sira and Bjørnstads published
application is illustrated in Fig. 1 of
WO2013135861A2. Its tracer chamber is arranged in a geological formation made of a hydrocarbon production
zone, such as sandstone or carbonates, framed by impermeable layers above and below,
such as shales or salts. The tubing has been installed in the formation and it is
separated from the geological rocks by a sand-filled annulus and a casing or a naturally
cut borehole wall. In the annulus the production zone is typically isolated from the
geological formations above and below by packers. The production from the zone is
controlled at the level of one or more ICD's.
Brief summary of the invention
[0004] The present invention is a petroleum well formation back pressure meter system comprising
a petroleum fluid conducting tubing (8) in a borehole through a reservoir rock formation,
said tubing comprising a blank pipe section (81) forming a blank-pipe-isolated first
annulus section (3) isolated by a first and a second packer (1, 2), said tubing (8)
comprising an adjacent non-blank pipe section (82) beyond said first packer (1) forming
a tubing-communicating petroleum producing second annulus section (4), said first
packer (1) comprising a tracer-conducting channel (6) allowing through passage of
tracer material (Trb) from an inlet (61) from a tracer-holding bellows (5) in pressure
communication with said blank-pipe-isolated annulus section (3), to an outlet (62)
to said tubing-communicating annulus section (4).
[0005] The present invention is also a method for estimating a petroleum well formation
back pressure, comprising arranging a petroleum well formation back pressure meter
system (0) according to claim 1, producing petroleum fluids through said tubing (8),
conducting sampling of said petroleum fluids and analyzing for said tracer material
(Trb) and calculating a tracer flux (Φb), estimating, based on said tracer flux (Φb),
a pressure gradient (Δb) over said first packer (1), using said pressure gradient
(Δb) over said first packer (1) to estimate a local formation back pressure about
said petroleum well.
[0006] The present invention may further be defined as a method for estimating a petroleum
well formation back pressure, comprising arranging a petroleum well formation back
pressure meter system as defined above, having pressure-calibrated said tracer-conducting
channel (6), producing petroleum fluids through said tubing (8), conducting sampling
of said petroleum fluids and analyzing for said tracer material (Trb) and calculating
a tracer flux (Φb) of the produced petroleum fluids, and estimating, based on said
tracer flux (Φb), a pressure gradient (Δp) over said first packer (1), and using said
pressure gradient (Δp) to estimate a local formation back pressure about said petroleum
well.
Figure captions
[0007] The invention is illustrated in the attached drawing figures, wherein
Fig. 1 illustrates a simplified section through part of an imagined petroleum well
installed through drilled geological formations, some of which are reservoir rocks,
and the well completed. A production pipe in the reservoir formations has separate,
perforated or by other means open production zones isolated by packers, and also blank
pipe sections between the production zones.
[0008] Fig. 2 is an illustration of a petroleum well formation back pressure estimating
system according to the invention. The drawing illustrates a petroleum fluid conducting
tubing (8) in a borehole through a reservoir rock formation. The tubing comprises
a blank pipe section (81) forming a blank-pipe-isolated first annulus section (3)
isolated by a first and a second packer (1, 2). The tubing (8) comprises adjacent
non-blank pipe section (82) beyond the first packer (1) forming a tubing-communicating
petroleum producing second annulus section (4) which is drained to the tubing (8).
Petroleum fluids enter through the borehole wall into the annulus space from the reservoir
rock due to the borehole wall pore pressure, and takes up tracer material (Trb) leaked
through the channel (6) in the first packer (1). The first packer (1) comprises the
tracer-conducting channel (6) allowing through passage of tracer material (Trb) from
an inlet (61) from a bellows (5) in pressure communication with said blank-pipe-isolated
annulus section (3), to an outlet (62) to said tubing-communicating annulus section
(4).
[0009] The term "blank pipe" is understood as a pipe section wherein the pressure of the
tubing annulus does not communicate with the main bore of the tubing, or a tubing
section which functions equivalently. The term "packer" is here a packer around the
tubing sealing against the wall or liner, a sealing around the tubing preventing annulus
fluid flow past the sealing, or any equivalently working element. The term "bellows"
implies an element which contains tracer fluid and which is in contact with the pressure,
here the pressure in the annulus fluid, and which releases tracer fluid due to the
pressure in the annulus fluid, and in the present case releases the tracer material
to the channel through the packer. The term "bellows" may thus be equivalent to a
piston chamber or a diaphragm with an outlet to a channel through the packer.
[0010] Fig. 3 is a modelled diagram of the reservoir back pressure field in the rocks behind
the borehole wall, outside a blank pipe section with a packer-isolated bellows as
illustrated in Fig. 2 above. From the produced fluids the tracer flux is measured,
and the pressure gradient (Δp) across the packer (1) is estimated. The pressure gradient
(Δp) across the packer may reflect the reservoir boundary pressure (p) some distance
or depth from the borehole into the surrounding formation from the well. The image
is the result of a COMSOL simulation. In the calculated example the reservoir back
pressure is about 6.56 Bar. The pressure gradient (Δp) from the back pressure field
just across the blank pipe section extends down to just below 4.56 Bar, one may see
the modelled 4.76 Bar isobar line approach the isolated annulus (3).
[0011] Fig. 4 is an embodiment of the invention wherein two additional tracers systems used
for checking the integrity of the packers (1, 2). The integrity of the packers (1,
2) will be crucial for the functionality of the distributed formation pressure unit
according to the invention. To reduce the uncertainty of this integrity, but also
to add value to the monitoring, it is possible to introduce two types of intelligent
tracer systems, a Tr
n source of tracer material not permeable or diffusable through the reservoir rock
about the borehole, and a Tr
p source which may permeate or diffuse through the same rocks. The two tracer systems
(Tr
n, Tr
p) are arranged in the packer-isolated blank pipe annulus section (3), both with a
release into the fluid that is expected to fill the section.
[0012] Fig. 5 illustrates three packer-isolated pressure zones in a multilayered reservoir,
wherein the system of the invention has been installed. In the three different pressure
zones of the reservoir, the reservoir back pressure differs between 8.0 Bar in zone
1, to 7.4 Bar in zone 2, to 8.8 Bar in zone 3, but the permeability is the same in
the layers. Each separate pressure zone is provided with a measurement device according
to the invention. It is assumed that the measured pressure drop is roughly proportional
to the total pressure drop of the reservoir back pressure field, here by a quotient
of 1/2 as an example.
[0013] Fig. 6 is an illustration of the reservoir back pressure field in a producing reservoir
zone such as across zone 1 through C-C of Fig. 5. The reservoir boundary is the boundary
for where it is assumed that no significant fluid flow occurs while draining the reservoir
locally, i.e. the location of the reservoir boundary pressure. The broken line isobar
at 4 Bar indicates the pressure 4 Bar inferred by the pressure gradient (Δp) over
the packer (1) using the device of the invention as illustrated in Fig. 5.
Embodiments of the invention
[0014] Permanent tracers in producer wells have in the background art been used for estimating
the nature and volume ratios of production flows, and for estimating the influx profiles
of the production flows. The present invention is a system and method for estimating
formation back pressure within the rock far behind the borehole wall in production
zones.
Basic system of the invention
[0015] The present invention is a petroleum well formation back pressure meter system comprising
a petroleum fluid conducting tubing (8) in a borehole through a rock formation, wherein
said tubing comprises a blank pipe section (81) forming a blank-pipe-isolated first
annulus section (3) isolated by a first and a second packer (1, 2), said tubing (8)
also comprising an adjacent non-blank pipe section (82) beyond said first packer (1)
forming a tubing-communicating petroleum producing second annulus section (4). Further
according to the invention, said first packer (1) comprises a tracer-conducting channel
(6) allowing through passage of tracer material (Trb) from an inlet (61) from a bellows
(5) comprising a fluid tracer (Tr
b) in pressure communication with said blank-pipe-isolated annulus section (3), to
an outlet (62) to said tubing-communicating annulus section (4). The tubing will conduct
produced fluid downstream, generally out to the surface. Petroleum fluids produced
through the tubing are sampled downstream and analyzed for their presence of tracer
materials (Tr
b) and optional other tracer materials.
[0016] Fig. 2 is an illustration of a petroleum well formation back pressure estimating
system according to the invention. The drawing illustrates a petroleum fluid conducting
tubing (8) in a borehole through a reservoir rock formation. The tubing comprises
a blank pipe section (81) forming a blank-pipe-isolated first annulus section (3)
isolated by a first and a second packer (1, 2). The tubing (8) comprises adjacent
non-blank pipe section (82) beyond the first packer (1) forming a tubing-communicating
petroleum producing second annulus section (4) which is drained to the tubing (8).
In an embodiment of the invention the second annulus section (4) is in fluid communication
with the same geological reservoir formation (fm) as the first annulus section (3).
The annulus section (4) may be packed with a permeable filler material such as a gravel
pack or sand, or only fluid-filled. Petroleum fluids enter through the borehole wall
into the annulus space from the reservoir rock due to the borehole wall pore pressure,
and takes up tracer material (Trb) leaked through the channel (6) in the first packer
(1). The first packer (1) comprises the tracer-conducting channel (6) allowing through
passage of tracer material (Trb) from an inlet (61) from a bellows (5) in pressure
communication with said blank-pipe-isolated annulus section (3), to an outlet (62)
to said tubing-communicating annulus section (4). The channel (6) may comprise a capillary
tube, a porous material or similar, which makes it appear as a Darcy-channel which
controls the pressure-induced flow of tracer material. In practical implementations
the properties of the capillary tubes of
WO2013135861A2 may be employed but arranged conducting tracer material through packer (1) in the
setting of the present invention.
[0017] Fig. 3 is a modelled diagram of the reservoir back pressure field in the rocks behind
the borehole wall, outside a blank pipe section with a packer-isolated bellows as
illustrated in Fig. 2 above. From the produced fluids the tracer flux is measured,
and the pressure gradient (Δp) across the packer (1) is estimated. The pressure gradient
(Δp) across the packer may reflect the reservoir boundary pressure (p) some distance
or depth from the borehole into the surrounding formation from the well. This virtually
probed pressure at a depth into the surrounding formation will depend on the distance
between the two packers; The larger the distance between packers, the further out
isobars will approach the isolated blank pipe annulus - the deeper you seem to observe
the pressure into the reservoir, i.e. the closer the pressure gradient (Δp) approaches
the reservoir boundary pressure. The image is the result of a COMSOL simulation. In
the calculated example the reservoir back pressure is about 6.56 Bar. The pressure
gradient (Δp) from the back pressure field just across the blank pipe section extends
down to just below 4.56 Bar, one may see the modelled 4.76 Bar isobar line approach
the isolated annulus (3). Thus a total pressure difference of only about 1.99 Bar,
i.e. 2 Bar exists between the reservoir boundary pressure and the measured (estimated)
pressure in the packer-isolated blank pipe annulus. The pressure gradient (Δp) across
the packer is 4.56 Bar between the isolated annulus (3) and the producing, perforated
annulus (4).
[0018] Fig. 5 illustrates three packer-isolated pressure zones in a multilayered reservoir,
wherein the system (0) (0A, 0B, 0C) of the invention has been installed. In the three
different pressure zones of the reservoir, the reservoir back pressure differs between
8.0 Bar in zone 1, to 7.4 Bar in zone 2, to 8.8 Bar in zone 3, but the permeability
is the same in the layers. Each separate pressure zone is provided with a measurement
device according to the invention. It is assumed that the measured pressure drop is
roughly proportional to the total pressure drop of the reservoir back pressure field,
here by a quotient of 1/2 as an example. Each separate pressure zone may be connected
to a separate pressure system. In the illustrated system, as a result of the tracer
measurements and the inferred pressure gradients, one may decide to close a sliding
sleeve valve to halt the production from the lowest pressure reservoir zone 2 until
production has reduced the borehole wall pressure of zone 3 and zone 1 to a lower
level so as for reducing the risk of losing fluid to zone 2.
[0019] Fig. 6 is an illustration of the reservoir back pressure field in a producing reservoir
zone such as across zone 1 through C-C of Fig. 5. The reservoir boundary is the boundary
for where it is assumed that no significant fluid flow occurs while draining the reservoir
locally, i.e. the location of the reservoir boundary pressure. There is a negative
pressure gradient inwards toward the borehole wall were the fluid is drained. The
broken isobar at 4 Bar indicates the pressure 4 Bar inferred as the pressure gradient
(Δp) over the packer (1) using the device of the invention as illustrated in Fig.
5.
Effect of the system of the invention
[0020] The petroleum well formation back pressure system according to the invention works
as follows: With reference to Fig. 2, Fig. 5, and Fig. 6, the fluid producing annulus
(4) drains, over time, the reservoir, creating a formation back pressure field from
the reservoir back pressure down to a zero level set as the tubing pressure, which
in this context may be used as a local reference pressure. One may assume that in
the tubing isolated annulus (3), the pressure difference from the formation back pressure
at the reservoir pressure boundary will be much less than the pressure difference
from the petroleum fluid producing annulus (4) to the formation back pressure at the
reservoir pressure boundary, because the petroleum fluid permeability in the surrounding
rock formation (fm) does not allow instant pressure equilibrium to be reached. Thus
the pressure (p3) in the tubing isolated annulus section (3) may represent an approximation
to the back pressure p in the formation, please see Fig. 3, Fig. 5, and Fig. 6. Thus
the pressure (p3) in the packer-isolated annulus (3) observes the same pressure as
exists some distance into the formation behind the borehole wall in the tubing-open
producing annulus (4). The pressure gradient (Δp) over the packer (1) may be approximately
proportional to the formation back pressure p. In Fig. 3. The above petroleum well
formation back pressure meter system works passively so as for allowing compression
of said bellows (5) by pressure (p3) in said first annulus section (3) to force tracer
material (Trb) through said channel (6) to said open, tubing-communicating second
annulus section (4). The open second annulus section (4) will allow said tracer material
(Trb) to escape to form part of the production flow. The tracer flux will be proportional
to the pressure gradient across the packer (1). Downstream, at the surface or downstream
below the surface, the production fluids with said tracer material (Trb) are sampled
and analyzed and measured for tracer flux (Φb). The tubing-isolated annulus section
(3) is ideally not producing, so the tracer flux (Φb) may be assumed to be proportional
to a pressure gradient (Δp) across said packer (1). Knowing the pressure gradient
(Δp) across said packer (1), one has a good indication of the pressure (p3) (relative
to the second annulus (4) pressure) in the blank-pipe-isolated annulus (3). One may
assume that the pressure in the blank-pipe isolated annulus (3) has some proportionality
factor to the formation boundary pressure (p, p
fm) behind the non-producing annulus (3) and the producing annulus (4).
The petroleum well formation back pressure estimating system according to the invention
may be arranged with different unique tracers (Trb) in several producing, packer-isolated
zones or formations (fm) along the production tubing, thus enabling estimation of
back pressure for each system-installed zone or formation, such as in Fig. 5.
[0021] In the petroleum well formation back pressure meter system (0, 0A, 0B, 0C) of the
invention, one may have either calibrated or non-calibrated, but equally tracer-conducting
channels (6). In an embodiment of the invention said tracer-conducting channel (6)
is calibrated with regard to pressure gradient.
[0022] In an embodiment of the invention shown in Fig. 5, there is arranged in the petroleum
well completion along the tubing (8), two, three, or more petroleum well formation
pressure meter systems (0A, 0B, 0C... ) according to the invention. Each formation
pressure meter system (0A, 0B, 0C.. ) is separated by a packer-isolated blank pipe
section (83), and each tracer material (TrbA, TrbB, TrbC, .. ) is unique.
[0023] Obtaining non-calibrated relative pressures:
If the tracer-conducting channels (6, 6A, 6B, 6C, ..) are equal or at least have equal
tracer flux rates relative to pressure, but not necessarily pressure calibrated, the
relative formation pressures for the separate or isolated zones may be estimated by
the following method:
- providing a petroleum well completion with two, three, or more petroleum well formation
pressure meter systems (0A, 0B, 0C... ) of the invention,
- separating each formation pressure meter system (0A, 0B, 0C.. ) by a packer-isolated
blank pipe section (83),
- using unique tracer materials (TrbA, TrbB, TrbC, .. ) for each system (0A, 0B, 0C,
..)
- producing petroleum fluids through said tubing (8),
- conducting sampling of said petroleum fluids and analyzing for said tracer material
(TrbA, TrbB, TrbC, .. ) and calculating a tracer fluxes (ΦbA, ΦbB, ΦbC, ..),
- estimating, based on said tracer flux (ΦbA, ΦbB, ΦbC, ..), relative pressure gradients
(ΔbA, ΔbB, ΔbC,..) over said first packers (1A, 1 B, 1 C),
- using said pressure gradients (Δb) over said first packers (1A, 1 B, 1C, ..) to estimate
relative local formation back pressures about said petroleum well.
[0024] Knowing, as above, the relative pressure gradients (ΔbA, ΔbB, ΔbC,..) over said first
packers (1A, 1 B, 1 C) and using the pressure gradients (Δb) over the first packers
(1A, 1 B, 1C, ..) to estimate relative local formation back pressures about said petroleum
well, even without having calibrated pressure properties, may be used by the well
operator to adjust an influx control device from one or more of the producing annulus
zones (4A, 4B, 4C,... .). It may be advantageous to adjust the influx control devices
to obtain equal formation pressures in order not to induce reverse flow in any of
the producing zones, and further to adjust the influx control devices as the production
proceeds in order to maintain good relative pressure conditions.
[0025] Obtaining calibrated pressures:
If, in addition, the tracer conducting channels (6A, 6B, 6C, .. ) are pressure calibrated,
one may use the above method to indirectly measure the true formation pressures and
thus estimate with good approximation the formation boundary back pressures for each
zone.
[0026] The steps above for conducting sampling of said petroleum fluids and analyzing for
said tracer material (TrbA, TrbB, TrbC, .. ) and calculating a tracer fluxes (ΦbA,
ΦbB, ΦbC, ..) is a task for the person skilled in the art, who will know how to conduct
instantaneous or average sampling to obtain representative tracer concentration values,
and take due care in case of slug flow or fluid slip problems in the well. One has
to conduct a series of samples and analyze each sample for concentration in order
to integrate over time to obtain the tracer flux.
Packer integrity control
[0027] It is advantageous to know whether the packers (1, 2) are properly installed and
tight so as for being fluid-proof against the surrounding borehole wall and not leaking
petroleum fluids nor water from the confined annulus zone (3). Fig. 4 is an embodiment
of the invention wherein two additional tracers systems used for checking the integrity
of the packers (1, 2). The integrity of the packers (1, 2) will be crucial for the
functionality of the distributed formation pressure unit according to the invention.
To reduce the uncertainty of this integrity, but also to add value to the monitoring,
it is possible to introduce two types of intelligent tracer systems, a Tr
n source of tracer material not permeable, i.e. non-diffusing through the reservoir
rock about the borehole, and a Tr
p source which is permeable or diffusable through the same reservoir rocks.
[0028] The two tracer systems (Tr
n, Tr
p) are arranged in the packer-isolated blank pipe annulus section (3), both with a
release property into the fluid that is expected to fill the section: One with tracer
Tr
n that
is not capable of penetrating the surrounding formation (fm) and/or one with tracer Tr
p that
will penetrate the surrounding formation (fm).
[0029] It is well known in the field that tracers based on longer molecule chains penetrate
less easily through reservoir rocks than tracers based on shorter molecule chains
do. The person skilled in the art will know how to obtain formation non-penetrating
and formation penetrating tracers (Tr
n, Tr
p).
[0030] Thus in an embodiment of the petroleum well formation back pressure meter system
of the invention it comprises - a first auxiliary second tracer system (9) releasing
first auxiliary tracer molecules (Tr
n) in said isolated first annulus section (3), said first auxiliary tracer material
(Tr
n)
not capable of passing through the geological material of said formation (fm) adjacent
to said first and/or second packers (1, 2). If the first auxiliary tracer molecules
(Tr
n) are detected downstream, one or both of packers (1) or (2) are leaking somehow.
A further check of the packers of the petroleum well formation back pressure meter
system described above, comprises
- a second auxiliary second tracer system (10) releasing second auxiliary tracer molecules (Trp) in said isolated first annulus section (3), said second auxiliary tracer material
(Trp) capable of passing through the geological material of said formation (fm) outside of said
first or second packers (1, 2). If the second auxiliary tracer molecules Trp are detected downstream, and the first auxiliary tracer molecules Trn are not detected, packers (1) and (2) are properly installed with regard to fluid-proofness.
[0031] The detection of one or both of the two tracers are ideally interpreted as:
- 1* Detecting Trp and Trn: Packer is leaking.
- 2* Detecting Trp (and not Trn): Packer is OK. The permeability of the reservoir rock is indicated from (Δp) (transient).
- 3* No tracer Trn, Trp seen: Packer is good, formation is tight or the back pressure is low.
[0032] From Fig. 4 one will see that situation 2* is illustrated: The formation-penetrating
tracer Tr
p enters the producing annulus (4) by permeating through the formation (fm) while the
non-penetrating tracer Tr
n does not.
[0033] The permeability level can be estimated from Δp.
Advantages of the invention
[0034] The present invention is a fully passive formation pressure measurement device system
using tracers released through some plug with known permeability, in an annulus zone
isolated by packers. All these are known, passive building elements. With the present
invention it is possible to monitor formation pressures in one or more production
zones without having to shut down and pressure-equalize each producing zone. The present
invention is a new combination of known elements are combined into a wireless distributed
formation pressure monitoring system.
[0035] According to the present invention, information is extracted from the tracer flux
from an installed tracer source that releases tracer as a function of the differential
pressure between a producing and a non-producing section of the borehole wall. By
matching data to models the technique may enable estimation of pressures some distance
into the near wellbore formation, - reservoir backpressure being the ultimate goal.
[0036] Continually monitoring the tracer flux for each producing zone adds data for formation
evaluation while producing fluids from the well. So it contributes to our ability
to dynamic updating the well and reservoir model.
1. A petroleum well formation pressure meter system (0) comprising
- a petroleum fluid conducting tubing (8) in a borehole through a reservoir rock formation,
- said tubing comprising a blank pipe section (81) forming a blank-pipe-isolated first
annulus section (3) isolated by a first and a second packer (1, 2), said tubing (8)
comprising an adjacent non-blank pipe section (82) beyond said first packer (1) forming
a tubing-communicating petroleum producing second annulus section (4),
characterized by
- said first packer (1) comprising a tracer-conducting channel (6) allowing through
passage of tracer material (Trb) from an inlet (61) from a bellows (5) comprising
a fluid tracer (Trb) in pressure communication with said blank-pipe-isolated annulus section (3), to
an outlet (62) to said tubing-communicating annulus section (4).
2. The petroleum well formation back pressure meter system of claim 1, comprising
- a first auxiliary second tracer system (9) releasing first auxiliary tracer molecules
(Trn) in said isolated first annulus section (3), said first auxiliary tracer material
(Trn) not capable of passing through the geological material of said formation (fm) adjacent
to said first and/or second packers (1, 2).
3. The petroleum well formation back pressure meter system of claim 2, comprising
- a second auxiliary second tracer system (10) releasing second auxiliary tracer molecules
(Trp) in said isolated first annulus section (3), said second auxiliary tracer material
(Trp) capable of passing through the geological material of said formation (fm) outside
of said first or second packers (1, 2).
4. The petroleum well formation back pressure meter system of any of claims 1 - 3, wherein
said tracer-conducting channel (6) is calibrated with regard to pressure gradient.
5. A petroleum well completion comprising two, three, or more petroleum well formation
pressure meter systems (0A, 0B, 0C... ) according to any of claims 1 - 3,
- each formation pressure meter system (0A, 0B, 0C.. ) separated by a packer-isolated
blank pipe section (83),
- each tracer material (TrbA, TrbB, TrbC, .. ) being unique.
6. A method for estimating a petroleum well formation back pressure, comprising arranging
a petroleum well formation back pressure meter system (0) according to claim 1,
- producing petroleum fluids through said tubing (8),
- conducting sampling of said petroleum fluids and analyzing for said tracer material
(Trb) and calculating a tracer flux (Φb),
- estimating, based on said tracer flux (Φb), a pressure gradient (Δb) over said first
packer (1),
- using said pressure gradient (Δb) over said first packer (1) to estimate a local
formation back pressure about said petroleum well.
7. In the method of claim 6, using a petroleum well completion comprising two, three,
or more petroleum well formation pressure meter systems (0A, 0B, 0C...),
- arranging a petroleum well formation back pressure meter system (0) according to
claim 1,
- each formation pressure meter system (0A, 0B, 0C.. ) separated by a packer-isolated
blank pipe section (83),
- each tracer material (TrbA, TrbB, TrbC, .. ) being unique,
- producing petroleum fluids through said tubing (8),
- conducting sampling of said petroleum fluids and analyzing for said tracer material
(TrbA, TrbB, TrbC, .. ) and calculating a tracer fluxes (ΦbA, ΦbB, ΦbC, ..),
- estimating, based on said tracer flux (ΦbA, ΦbB, ΦbC, ..), relative pressure gradients
(ΔbA, ΔbB, ΔbC, ..) over said first packers (1A, 1 B, 1 C),
- using said pressure gradients (Δb) over said first packers (1A, 1 B, 1C, ..) to
estimate relative local formation back pressures about said petroleum well.
8. The method of claims 6 or 7, wherein said tracer-conducting channels (6A, 6B, 6C)
are calibrated with regard to pressure gradient.
9. The method of any of claims 6 - 8, further comprising
- in said petroleum well formation back pressure meter system of claim 1, further
installing a first auxiliary tracer system (9) releasing first auxiliary tracer molecules (Trn) in said isolated first annulus section (3), said first auxiliary tracer material
(Trn) not capable of passing through the geological material of said formation (fm) adjacent
to said first and/or second packers (1, 2).
- analyzing one or more of said samples of said petroleum fluids for said first auxiliary
tracer material (Trn),
- if detecting said first auxiliary tracer material (Trn), determining that said first or second packers (1, 2) are leaking, if not they are
proof.
10. The method of any of claim 9, further comprising,
in said petroleum well formation back pressure meter system of claim 2, further installing
a
second auxiliary second tracer system (10) releasing
second auxiliary tracer molecules (Tr
p) in said isolated first annulus section (3), said second auxiliary tracer material
(Tr
p) capable of passing through the geological material of said formation (fm) outside
of said first or second packers (1, 2),
- analyzing one or more of said samples of said petroleum fluids for said second auxiliary
tracer material (Trn),
- if detecting said second auxiliary tracer material (Trp), and not detecting said first auxiliary tracer material (Trn), determining that said first or second packers (1, 2) are proof.
1. Ölbohrlochlagerstättendruckvermessungssystem (0) umfassend
- ein ölflüssigkeitsführende Rohrleitung (8) in einem Bohrloch durch eine Speichergesteinsformation,
- wobei die Rohrleitung einen Glattrohrabschnitt (81) zum Ausbilden einer glattrohrisolierten
ersten ringförmigen, durch einen ersten und eine zweiten Presskopf (1, 2) isolierte
Ringraumsektion (3) umfasst, wobei die Rohrleitung (8) einen benachbarten Nicht-Glattrohrabschnitt
(82) jenseits des ersten Presskopfes (1) zum Ausbilden eine rohrleitungsverbindende
ölfördernden zweiten Ringraumsektion (4) umfasst, dadurch gekennzeichnet, dass
- der erste Presskopf (1) eine markierungsmittel-führenden Kanal (6) umfasst, der
den Durchfluss eines Markierungsmaterial (Trb) von einem Einlass (61) aus einem Dehngefäß mit einem flüssigen, in Druckverbindung
mit der glattrohrisolierten Ringraumsektion (3) befindlichen Markierungsmittel (Trb) zu einem Auslass (62) in der rohrleitungsverbindenden Ringraumsektion (4) gestattet.
2. Das Ölbohrlochlagerstättendruckvermessungssystem nach Anspruch 1, umfassend:
- ein erstes hilfsweises Zweitmarkierungsmittelsystem (9) zum Abgeben erster Hilfsmarkierungsmittelmoleküle
(Trn) in die isolierte erste Ringraumsektion (3), wobei das erste Hilfsmarkierungsmittelmaterial
(Trn) nicht geeignet ist, um durch das geologische Material der Formation (fm) benachbart
zum ersten und/oder zweiten Presskopfs (1, 2) zu gelangen.
3. Das Ölbohrlochlagerstättendruckvermessungssystem nach Anspruch 2, umfassend:
- ein zweites hilfsweises Zweitmarkierungsmittelsystem (10) zum Abgeben zweiter Hilfsmarkierungsmittelmoleküle
(Trp) in die isolierte erste Ringraumsektion (3), wobei das zweite Hilfsmarkierungsmittelmaterial
(Trp) geeignet ist, um durch das geologische Material der Formation (fm) benachbart zum
ersten und/oder zweiten Presskopfs (1, 2) zu gelangen.
4. Das Ölbohrlochlagerstättendruckvermessungssystem nach einem der Ansprüche 1 bis 3,
wobei der markierungsmittel-führenden Kanal (6) in Bezug auf einen Druckgradienten
kalibriert ist.
5. Ein Ölbohrlochabschluss umfassend zwei, drei oder mehr Ölbohrlochlagerstättendruckvermessungssysteme
(0A, 0B, 0C...) nach einem der Ansprüche 1 bis 3, wobei
- jedes Ölbohrlochlagerstättendruckvermessungssystem (0A, 0B, 0C...) durch einen presskopfisolierten
Glattrohrabschnitt(83) getrennt ist,
- jedes Markierungsmaterial (TrbA, TrbB, TrbC...) unverwechselbar ist.
6. Verfahren zum Abschätzen des Ölbohrlochlagerstättendrucks, umfassend der Einrichtung
eines Ölbohrlochlagerstättendruckvermessungssystems (0) gemäß Anspruch 1, mit
- Fördern von Ölflüssigkeit durch die Rohrleitung (8),
- Durchführen von Probenentnahmen der Ölflüssigkeit und Analysieren auf Markierungsmaterial
(Trb) und Berechnen eines Markierungsdurchflusses (Φb),
- Abschätzen, basierend auf dem Markierungsdurchfluss (Φb), eines Druckgradienten
(Δb) über den ersten Presskopf (1),
- Verwenden des Druckgradienten (Δb) über den ersten Presskopf (1) zum Abschätzen
eines lokalen Lagerstättendrucks des Ölbohrlochs.
7. In dem Verfahren nach Anspruch 6, Verwenden eines Ölbohrlochabschlusses umfassend
zwei, drei oder mehr Ölbohrlochlagerstättendruckvermessungssysteme (0A, 0B, 0C...),
- Einrichten eines Ölbohrlochlagerstättendruckvermessungssystems (0) gemäß Anspruch
1, wobei
- jedes Ölbohrlochlagerstättendruckvermessungssystem (0A, 0B, 0C...) durch einen presskopfisolierten
Glattrohrabschnitt (83) getrennt ist,
- jedes Markierungsmaterial (TrbA, TrbB, TrbC...) unverwechselbar ist,
- Fördern von Ölflüssigkeit durch die Rohrleitung (8),
- Durchführen von Probenentnahmen der Ölflüssigkeit und Analysieren auf Markierungsmaterialien
(TrbA, TrbB, TrbC...) und Berechnen von Markierungsdurchflüssen (ΦbA, ΦbB, ΦbC...) ,
- Abschätzen, basierend auf dem Markierungsdurchflüssen (ΦbA, ΦbB, ΦbC...) , von Druckgradienten
(ΔbA, ΔbB, ΔbC...) über die ersten Pressköpfe (1A, 1B, 1C),
- Verwenden der Druckgradienten (Δb) über die ersten Pressköpfe (1A, 1B, 1C) zum Abschätzen
der lokalen Lagerstättendrücke des Ölbohrlochs.
8. Verfahren nach Anspruch 6 oder 7, wobei die markierungsmittel-führenden Kanäle (6A,
6B, 6C) in Bezug auf einen Druckgradienten kalibriert sind.
9. Verfahren nach einem der Ansprüche 6 bis 8, weiter umfassend
- in dem Ölbohrlochlagerstättendruckvermessungssystem nach Anspruch 1, weiter Vorsehen
eines ein ersten Hilfsmarkierungsmittelsystem (9) zum Abgeben erster Hilfsmarkierungsmittelmoleküle
(Trn) in die isolierte erste Ringraumsektion (3), wobei das erste Hilfsmarkierungsmittelmaterial
(Trn) nicht geeignet ist, um durch das geologische Material der Formation (fm) benachbart
zum ersten und/oder zweiten Presskopfs (1, 2) zu gelangen,
- Analysieren eines oder mehrerer Proben der Ölflüssigkeit auf das erste Hilfsmarkierungsmittelmaterial
(Trn),
- bei Detektion des ersten Hilfsmarkierungsmittelmaterial (Trn), Feststellen, dass
der erste oder zweite Presskopf (1, 2) undicht ist, ansonsten das sie dicht sind.
10. Verfahren nach Anspruch 9, weiter umfassend,
- in dem Ölbohrlochlagerstättendruckvermessungssystem nach Anspruch 2, weiter Vorsehen
ein zweites Hilfsmarkierungsmittelsystem (10) zum Abgeben zweiter Hilfsmarkierungsmittelmoleküle
(Trp) in die isolierte erste Ringraumsektion (3), wobei das zweite Hilfsmarkierungsmittelmaterial
(Trp) geeignet ist, um durch das geologische Material der Formation (fm) benachbart
zum ersten und/oder zweiten Presskopfs (1, 2) zu gelangen,
- Analysieren eines oder mehrerer Proben der Ölflüssigkeit auf das zweite Hilfsmarkierungsmittelmaterial
(Trn),
- bei Detektion des zweiten Hilfsmarkierungsmittelmaterial (Trp) bei Nicht-Detektion
des ersten Hilfsmarkierungsmittelmaterial (Trn), Festellen, dass der erste oder zweite
Presskopf (1, 2) dicht sind.
1. Système de mesure de la pression pour la formation d'un puits de pétrole (0) comprenant
- un tube (8) conduisant du fluide pétrolier dans un trou de forage à travers une
formation de roche réservoir,
- ledit tube comprenant une section de tube vide (81) formant une première section
annulaire isolée de tube vide (3), isolée par une première et une seconde garnitures
d'étanchéité (1, 2), ledit tube (8) comprenant une section de conduite non-vide adjacente
(82) au-delà de ladite première garniture d'étanchéité (1) formant une seconde section
annulaire de tube communiquant avec le pétrole produit (4),
caractérisé par
- ladite première garniture d'étanchéité (1) comprenant un canal conduisant un traceur
(6) permettant le passage de matière traceur (Trb) à travers depuis une entrée (61)
à partir d'une soufflerie (5), comprenant un traceur de fluide (Trb) en communication sous pression avec ladite section annulaire isolée de tuyau vide
(3), vers une sortie (62) de ladite section de tube annulaire communiquant (4).
2. Système de mesure de contre-pression pour la formation d'un puits de pétrole selon
la revendication 1, comprenant
- un premier système de second traceur auxiliaire (9) libérant des premières molécules
de traceurs auxiliaires (Trn) dans ladite première section annulaire isolée (3), ledit premier matériau traceur
auxiliaire (Trn) n'étant pas capable de passer à travers le matériau géologique de ladite formation
(fm) adjacente auxdites première et / ou seconde garnitures d'étanchéité (1, 2).
3. Système de mesure de contre-pression pour la formation d'un puits de pétrole selon
la revendication 2, comprenant
- un second système de second traceur auxiliaire (10) libérant des secondes molécules
de traceurs auxiliaires (Trp) dans ladite première section annulaire isolée (3), ledit second matériau traceur
auxiliaire (Trp) étant capable de passer à travers le matériau géologique de ladite formation (fm)
à l'extérieur desdites première ou seconde garnitures d'étanchéité (1, 2).
4. Système de mesure de contre-pression pour la formation d'un puits de pétrole selon
l'une des revendications 1 à 3, dans lequel ledit canal conduisant un traceur (6)
est étalonné par rapport à un gradient de pression.
5. Réalisation de puits de pétrole comprenant deux, trois, ou plusieurs systèmes de mesure
de la pression pour la formation d'un puits de pétrole (0A, 0B, 0C ...) selon l'une
quelconque des revendications 1 à 3,
- chaque système de mesure de la pression pour la formation d'un puits de pétrole
(0A, 0B, 0C ...) étant séparé par une section de tuyau vide à garniture d'étanchéité
(83),
- chaque matériau traceur (TrbA, TrbB, TrbC, ..) étant unique.
6. Procédé pour estimer une contre-pression pour la formation d'un puits de pétrole,
comprenant l'agencement de système de mesure de la pression pour la formation d'un
puits de pétrole (0) selon la revendication 1,
- produisant des fluides pétroliers à travers ledit tube (8),
- conduisant des échantillonnages desdits fluides pétroliers et les analysants pour
ledit matériau traceur (Trb) et calculant un flux de traceur (Φb),
- estimant, sur la base dudit flux de traceur (Φb), un gradient de pression (Δb) sur
ladite première garniture d'étanchéité (1),
- utilisant ledit gradient de pression (Δb) sur ladite première garniture d'étanchéité
(1) pour estimer une formation locale de contre-pression autour dudit puits de pétrole.
7. Procédé selon la revendication 6, utilisant une réalisation d'un puits de pétrole
comprenant deux, trois, ou plusieurs systèmes de mesure de la pression pour la formation
d'un puits de pétrole (0A, 0B, 0C ...),
- disposant d'un système de mesure de la pression pour la formation d'un puits de
pétrole (0) selon la revendication 1,
- chaque système de mesure de la pression pour la formation d'un puits de pétrole
(0A, 0B, 0C..) étant séparé par une section de tuyau vide à garniture d'étanchéité
(83),
- chaque matériau traceur (TrbA, TrbB, TrbC, ..) étant unique,
- produisant des fluides pétroliers à travers ledit tube (8),
- conduisant des échantillonnages desdits fluides pétroliers et les analysants pour
ledit matériau traceur (TrbA, TrbB, TrbC, ..) et calculant des flux de traceur (ΦbA,
ΦbB, ΦbC, ..),
- estimant, sur la base dudit flux de traceur (ΦbA, (ΦbB, (ΦbC, ..), les gradients
de pression relative (ΔbA, ΔbB, ΔbC, ..) sur ladite première garniture d'étanchéité
(1A, 1B, 1C),
- utilisant lesdits gradients de pression (Δb) sur ladite première garniture d'étanchéité
(1A, 1B, 1C, ..) pour estimer la formation locale de contre-pressions relative autour
dudit puits de pétrole.
8. Procédé selon les revendications 6 ou 7, dans lequel lesdits canaux conduisant un
traceur (6A, 6B, 6C) sont étalonnés par rapport à un gradient de pression.
9. Procédé selon l'une quelconque des revendications 6 à 8, comprenant en outre
- dans ledit système de mesure de contre-pression pour la formation d'un puits de
pétrole selon la revendication 1, en outre l'installation d'un premier système de
traceur auxiliaire (9) libérant des premières molécules de traceur auxiliaires (Trn) dans ladite première section annulaire isolée (3), ledit premier matériau traceur
auxiliaire (Trn) n'étant pas capable de passer à travers le matériau géologique de ladite formation
(fm) adjacente auxdites première et / ou seconde garnitures d'étanchéité (1, 2),
- l'analyse d'un ou plusieurs desdits échantillons desdits fluides pétroliers pour
ledit premier matériau traceur auxiliaire (Trn),
- si ledit premier matériau traceur auxiliaire (Trn) est détecté, la détermination que lesdites première ou seconde garnitures d'étanchéité
(1, 2) ne sont plus étanches, sinon elles sont imperméables.
10. Procédé selon la revendication 9, comprenant en outre, dans ledit système de mesure
de contre-pression pour la formation d'un puits de pétrole selon la revendication
2, en outre l'installation d'un second système de second traceur auxiliaire (10) libérant
des secondes molécules de traceur auxiliaires (Tr
p) dans ladite première section annulaire isolée (3), ledit second matériau traceur
auxiliaire (Tr
p) étant capable de passer à travers le matériau géologique de ladite formation (fm)
à l'extérieur desdites première ou seconde garnitures d'étanchéité (1, 2),
- l'analyse d'un ou plusieurs desdits échantillons desdits fluides pétroliers pour
ledit second matériau traceur auxiliaire (Trn),
- si ledit second matériau traceur auxiliaire (Trp) est détecté, et ledit premier matériau traceur auxiliaire (Trn) n'est pas détecté, la détermination que lesdites première ou seconde garnitures
d'étanchéité (1, 2) sont imperméables.