U.S. patent application number 13/044633 was filed with the patent office on 2011-09-15 for identification of lost circulation zones.
This patent application is currently assigned to Schlumberger Technology Corporation. Invention is credited to Gerard Daccord, Dominique Guillot.
Application Number | 20110220350 13/044633 |
Document ID | / |
Family ID | 42537730 |
Filed Date | 2011-09-15 |
United States Patent
Application |
20110220350 |
Kind Code |
A1 |
Daccord; Gerard ; et
al. |
September 15, 2011 |
IDENTIFICATION OF LOST CIRCULATION ZONES
Abstract
Method and apparatus for identifying lost circulation in
subterranean wells, in particular, methods for treating the
identified lost circulation zones with fluid compositions that are
pumped into a wellbore enter voids in the subterranean-well
formation through which wellbore fluids escape, and form a seal
that limits further egress of wellbore fluid into the
lost-circulation zone.
Inventors: |
Daccord; Gerard; (Vauhallan,
FR) ; Guillot; Dominique; (Fontenay aux roses,
FR) |
Assignee: |
Schlumberger Technology
Corporation
Sugar Land
TX
|
Family ID: |
42537730 |
Appl. No.: |
13/044633 |
Filed: |
March 10, 2011 |
Current U.S.
Class: |
166/254.1 ;
166/305.1; 166/66 |
Current CPC
Class: |
E21B 21/003 20130101;
E21B 21/08 20130101; E21B 47/12 20130101; E21B 49/005 20130101 |
Class at
Publication: |
166/254.1 ;
166/305.1; 166/66 |
International
Class: |
E21B 47/00 20060101
E21B047/00; E21B 43/16 20060101 E21B043/16; E21B 43/00 20060101
E21B043/00 |
Foreign Application Data
Date |
Code |
Application Number |
Mar 11, 2010 |
EP |
10290126 |
Claims
1. A method for identifying the depth, the severity, or both, of
lost-circulation zones in a subterranean well, comprising: (i)
placing a tubular body in a wellbore, the tubular body being
equipped with: (a) a drill bit, the drill bit having at least one
nozzle; (b) at least one sensor attached to the outer surface of
the tubular body, the sensor being capable of measuring a parameter
that directly correlates to fluid-flow rate in the annulus between
the outer surface of the tubular body and the wellbore wall; and
(c) means to transmit the parameter to the surface; and (ii)
recording the parameter and transmitting the parameter to the
surface.
2. The method of claim 1, wherein: (i) the wellbore is drilled by
the tubular body; and (ii) drilling fluid is pumped through the
interior of the tubular body, through one or more drill-bit
nozzles, and upstream in the annulus between the outer surface of
tubular body and the wellbore wall.
3. The method of claim 1, wherein: (i) the wellbore is filled with
fluid; and (ii) fluid is not being pumped through the tubular body
as the tubular body is inserted into the wellbore.
4. The method of claim 1, further comprising removing the tubular
body from the wellbore while continuing to measure and transmit the
parameter.
5. The method of claim 1, wherein the sensor is chosen from the
group comprising flowmeters, spinners, electromagnetic flowmeters,
optical fluid sensors, ultrasonic flow-velocity sensors and
differential-pressure-flow sensors.
6. The method of claim 1, wherein the parameter is transmitted via
hard wire, optical fiber, wireless, radio, mud-pulse telemetry,
electromagnetic telemetry or microwave transmission.
7. The method of claim 1, wherein the parameter is transmitted to
the surface in real time.
8. A method for subterranean well treatment, comprising: (i)
placing a tubular body in a wellbore, the tubular body being
equipped with: (a) a drill bit, the drill bit having at least one
nozzle; (b) at least one sensor attached to the outer surface of
the tubular body, the sensor being capable of measuring a parameter
that directly correlates to fluid-flow rate in the annulus between
the outer surface of the tubular body and the wellbore wall; and
(c) means to transmit the parameter to the surface; (ii) recording
the parameter and transmitting the parameter to the surface; (iii)
identifying the depth, the severity, or both, of the zone to be
treated; and (iv) pumping a treatment fluid at the identified
depth.
9. The method of claim 8, wherein the treatment comprises
lost-circulation or inflow of formation fluid.
10. The method of claim 8, wherein: (i) the wellbore is drilled by
the tubular body; and (ii) drilling fluid is pumped through the
interior of the tubular body, through one or more drill-bit
nozzles, and upstream in the annulus between the outer surface of
tubular body and the wellbore wall.
11. The method of claim 8, wherein: (i) the wellbore is filled with
fluid; and (ii) fluid is not being pumped through the tubular body
as the tubular body is inserted into the wellbore.
12. The method of claim 8, further comprising removing the tubular
body from the wellbore while continuing to measure and transmit the
parameter.
13. The method of claim 8, wherein the sensor is chosen from the
group comprising flowmeters, spinners, electromagnetic flowmeters,
optical fluid sensors, ultrasonic flow-velocity sensors and
differential-pressure-flow sensors.
14. The method of claim 8, wherein the parameter is transmitted via
hard wire, optical fiber, wireless, radio, mud-pulse telemetry,
electromagnetic telemetry or microwave transmission.
15. The method of claim 8, wherein the parameter is transmitted to
the surface in real time.
16. The method according to claim 8, wherein the treatment fluid
contains chemicals that react downhole to form a plug.
17. A well-treatment apparatus, comprising a tubular body having at
its bottom end a drill bit, the drill bit being equipped with at
least one nozzle through which fluids may flow, wherein the outer
surface of the tubular body is equipped with a least one sensor
able to measure a parameter useful for identifying the depth and
severity of a lost-circulation zone, the apparatus being further
equipped with means for transmitting the parameter value to
surface.
18. The apparatus of claim 16, wherein the sensor is chosen from
the group comprising flowmeters, spinners, electromagnetic
flowmeters, optical fluid sensors, ultrasonic flow-velocity sensors
and differential-pressure-flow sensors.
19. The apparatus of claim 16, wherein the parameter is transmitted
via hard wire, optical fiber, wireless, radio, mud pulse telemetry,
wired drill pipe, electromagnetic telemetry or microwave
transmission.
20. The apparatus of claim 16, wherein the parameter is transmitted
to the surface in real time.
Description
BACKGROUND OF THE INVENTION
[0001] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0002] Embodiments relate to equipment and methods for identifying
the presence and location of lost circulation in subterranean
wells; in particular, methods for treating the identified lost
circulation zones with fluid compositions that are pumped into a
wellbore, enter voids in the subterranean-well formation through
which wellbore fluids escape, and form a seal that limits further
egress of wellbore fluid into the formation.
[0003] During the construction of a subterranean well, drilling and
cementing operations are performed that involve circulating fluids
in and out of the well. The fluids exert hydrostatic and pumping
pressure against the subterranean rock formations, and may induce a
condition known as lost circulation. Lost circulation is the total
or partial loss of drilling fluids or cement slurries into highly
permeable zones, cavernous formations and fractures or voids. Such
openings may be naturally occurring or induced by pressure exerted
during pumping operations. Lost circulation should not be confused
with fluid loss, which is a filtration process wherein the liquid
phase of a drilling fluid or cement slurry escapes into the
formation, leaving the solid components behind.
[0004] Lost circulation can be an expensive and time-consuming
problem. During drilling, this loss may vary from a gradual
lowering of the mud level in the pits to a complete loss of
returns. Lost circulation may also pose a safety hazard, leading to
well-control problems and environmental incidents. During
cementing, lost circulation may severely compromise the quality of
the cement job, reducing annular coverage, leaving casing exposed
to corrosive downhole fluids, and failing to provide adequate zonal
isolation. Lost circulation may also be a problem encountered
during well-completion and workover operations, potentially causing
formation damage, lost reserves and even loss of the well.
[0005] While drilling, it is routine practice to monitor the amount
of drilling fluid pumped into the well and flowing back from the
well, any difference between these volumes being attributed to
downhole losses; this global fluid mass balance provides an
accurate indication of downhole fluid losses or gains, but does not
reveal the location at which such events are occurring.
[0006] Lost-circulation solutions may be classified into three
principal categories: bridging agents, surface-mixed systems and
downhole-mixed systems. Bridging agents, also known as
lost-circulation materials (LCMs), are solids of various sizes and
shapes (e.g., granular, lamellar, fibrous and mixtures thereof).
They are generally chosen according to the size of the voids or
cracks in the subterranean formation (if known) and, as fluid
escapes into the formation, congregate and form a barrier that
minimizes or stops further fluid flow. Surface-mixed systems are
generally fluids composed of a hydraulic cement slurry or a polymer
solution that enters voids in the subterranean formation, sets or
thickens, and forms a seal that minimizes or stops further fluid
flow. Downhole-mixed systems generally consist of two or more
fluids that, upon making contact in the wellbore or the
lost-circulation zone, form a viscous plug or a precipitate that
seals the zone.
[0007] A thorough overview of LCMs, surface-mixed systems and
downhole-mixed systems, including guidelines for choosing the
appropriate solution for a given situation, is presented in the
following reference: Daccord G, Craster B, Ladva H, Jones TGJ and
Manescu G: "Cement-Formation Interactions," in Nelson E and Guillot
D (eds.): Well Cementing--2.sup.nd Edition, Houston: Schlumberger
(2006): 202-219, included herein by reference thereto.
[0008] Mechanical solutions also exist, and generally involve
placing a piece of tubular in front of the loss zone, thereby
making this portion of the wellbore impervious.
[0009] Both chemical and mechanical methods work best when the
depth of the zone to be plugged is well known--this is of paramount
importance for mechanical solutions. Failure to place fluid systems
at the optimal depth may lead to various detrimental effects such
as dilution of the fluid system into the drilling fluid already
present in the well or unknown delay between the time when the
fluid exits the drill string and when it enters the loss zone.
Often, the fluid system even undergoes chemical reactions, for
instance in order to increase its viscosity once it is placed into
the loss zone. If the chemical reaction takes place too soon or too
late, the effectiveness of the treatment may be dramatically
reduced.
[0010] Presently, identification of the depth of loss zones is
seldom performed because it requires time and specialized
equipment. One method consists of recording formation-evaluation
logs and wellbore images using either wireline or "while-drilling
tools." From this information, specialists can infer the probable
depths of loss zones. This method is usually reserved for
situations in which losses are severe and the associated hazards
are high. In the majority of situations, it is not economical to
spend rig time recording this information.
[0011] Monitoring the drilling-fluid pressure and temperature in
the annulus while drilling is a common practice. These measurements
are weakly sensitive to losses of drilling fluid to the formation,
but they are much more sensitive to other parameters--fluid
rheology, hole cleaning, pipe movement, etc. As a result, it is
practically impossible to extract any information on loss zones
depth from these measurements.
[0012] In paper SPE 97372, the authors describe means of performing
reservoir testing while drilling underbalanced. Examples are
provided in which distributed-pressure measurements are made along
the drillstring, together with the flow rate at surface. The flow
is multiphase, and the objective is to estimate reservoir pressure
by analyzing the annulus pressure. This paper is included herein by
reference.
[0013] In paper SPE 108345, the authors studied the best
theoretical distributed measurements that could be made while
drilling. They provide two theoretical examples of (1) a fluid
influx from the formation into the well and (2) loss of drilling
fluid into a fracture. The measurements considered included
pressure and flow rate. The authors concluded that
annular-flow-rate measurements do not exist at present and "could
be essential in improving an early detection of [ . . . ] incidents
resulting in loss of circulation." This paper is included herein by
reference.
[0014] Many patents have been issued concerning the measurement of
mud returns at surface, e.g., U.S. Pat. No. 5,063,776 and U.S. Pat.
No. 6,257,354, included herein by reference thereto. These methods
are aimed at the real-time analysis of downhole events using
surface-flow-rate measurements and eventually downhole-pressure
measurements. These methods are intrinsically unable to measure the
depth at which drilling fluid losses are occurring.
[0015] WO2007/148269 relates to a system including a section of
tubular having a main flow passage, a fluid diversion port and at
least two sensors in the section of tubular, one being located
upstream of the fluid diversion port and one being located
downstream, included herein by reference thereto. This patent
application does not relate to lost circulation, as pumping
lost-circulation solutions through a tubular port would create
risks of losing the tubular as the lost-circulation solution could
form a plug instantaneously, thereby sticking also the tubular.
[0016] Thus, despite valuable contributions in the art, the
industry still has difficulties properly locating the position of
lost-circulation zones in a timely manner, especially while
drilling.
SUMMARY OF THE INVENTION
[0017] Despite many contributions in the art, there is still a need
for a system to locate lost-circulation zones, allowing a quick and
efficient treatment and thereby preserving the well and maximizing
its productivity. Some embodiments of the invention fulfills this
need.
[0018] In an aspect, embodiments relate to methods for identifying
the depth and/or severity of loss zones while drilling a well.
[0019] In a further aspect, embodiments relate to methods for
treating lost circulation in a subterranean well.
[0020] In yet a further aspect, embodiments relate to a
well-treatment apparatus.
BRIEF DESCRIPTION OF THE DRAWINGS
[0021] For a more complete understanding of some embodiments, and
the advantages thereof, reference is now made to the following
descriptions taken in conjunction with the accompanying figures, in
which:
[0022] FIG. 1 displays a wellbore drilled through various
geological formations, using a hollow drill string.
[0023] FIG. 2A shows an arrangement of several fluid-velocity
sensors placed around a tubular body.
[0024] FIG. 2B shows an arrangement of one sensor placed on a
rotating pipe.
DETAILED DESCRIPTION
[0025] Some embodiments may be described in terms of treatment of
vertical wells, but is equally applicable to wells of any
orientation. Embodiments may be described for hydrocarbon
production wells, but it is to be understood that the invention may
be used for wells for production of other fluids, such as water or
carbon dioxide or, for example, for injection or storage wells.
Embodiments may also be described for offshore and land wells. It
should also be understood that throughout this specification, when
a concentration or amount range is described as being useful, or
suitable, or the like, it is intended that any and every
concentration or amount within the range, including the end points,
is to be considered as having been stated. Furthermore, each
numerical value should be read once as modified by the term "about"
(unless already expressly so modified) and then read again as not
to be so modified unless otherwise stated in context. For example,
"a range of from 1 to 10" is to be read as indicating each and
every possible number along the continuum between about 1 and about
10. In other words, when a certain range is expressed, even if only
a few specific data points are explicitly identified or referred to
within the range, or even when no data points are referred to
within the range, it is to be understood that the inventor
appreciates and understands that any and all data points within the
range are to be considered to have been specified, and that the
inventor has possession of the entire range and all points within
the range.
[0026] Embodiments relate to simple and cost-effective means for
locating the depth of lost-circulation zones and the severity of
the fluid losses while drilling. One calculates the fluid-loss rate
from in-situ drilling-fluid-flow measurements in the annular
portion of the well. The differentiation of the flow rate with
respect to the depth provides the depth of the lost-circulation
zones and their respective fluid-loss rates. This knowledge allows
one to design treatments adapted to the severity of the losses, and
placing the optimal treatments at the optimal depths.
[0027] One embodiment involves inserting a tubular body equipped
with a drill-bit into the wellbore. The drill bit is equipped with
at least one nozzle. Drilling of the wellbore commences, drilling
fluid is circulated through the interior of the tubular body,
through the drill-bit nozzle(s), and then through the annulus
between the outer surface of the tubular body and the wellbore
wall. At least one sensor is attached to the outer surface of the
tubular body, the sensor being able to record a parameter and
transmit the parameter to surface.
[0028] The sensor attached to the outer surface is preferably
located at least a few meters above the drill bit, preferably about
10 m. Preferably, the tubular is equipped with a plurality of
sensors, allowing the user to have a means for detecting
lost-circulation zones all along the tubular. Moreover, as the lost
circulation may occur during the drilling operations, e.g., if a
fracture is created due to excessive pressure, such a configuration
would allow real-time monitoring.
[0029] The drilling fluid may be any drilling fluid known in the
art such as water-base mud, oil-base mud or synthetic-base mud.
[0030] The tubular body is preferably sectioned pipe wherein the
sections may be joined by any means (welds, threaded fittings,
flanged fittings, combinations thereof, and the like).
[0031] The parameter to be recorded in the present invention is
preferably a parameter that can enable the operator to detect
lost-circulation zones, preferably the parameter is fluid
velocity.
[0032] The sensor useful in the context of the present invention
may be any sensor capable of measuring suitable parameters.
Examples of suitable sensors include (but are not limited to)
flowmeters, spinners, electromagnetic flowmeters, optical-fluid
sensors, ultrasonic-flow-velocity sensors and
differential-pressure-flow sensors. Such devices can measure flow
rate directly, without having to employ mathematical algorithms.
Such devices are also not affected by variations in the fluid's
rheological properties.
[0033] Embodiments may comprise a plurality of sensors capable of
detecting--in real time--fluid flow at the outlet of the tubular
body and up the annulus between the tubular body and the wellbore.
The sensors may be programmable both downhole and at the surface.
This may be accomplished by using one or more algorithms to allow
rapid, real-time interpretation of downhole data, allowing
adjustments to be made at the surface and/or downhole for effective
treatment.
[0034] Embodiments also include an apparatus comprising a tubular
body having at its bottom end a drill bit, the drill bit being
equipped with nozzles through which fluids may flow. The tubular
body is equipped at its outer surface with a least one sensor able
to record a parameter useful for identifying the depth and severity
of lost-circulation zones. The apparatus is further equipped with
means for transmitting the parameter values to the surface.
[0035] In the present context, a lost-circulation zone will be
identified if an annular-fluid-flow difference is measured by the
sensor(s) placed along the tubular body. Basically, with the
methods and apparatus of the present embodiments, one compares, in
real time, the mud-flow rate that is pumped downhole with the
mud-flow rate returning upstream through the annulus. The mud-flow
rate is calculated from the measurement of the hole size, the
knowledge of the external dimensions of the tubular body, and the
measurement of the fluid velocity. The hole size can be determined
using standard techniques such as acoustic measurements.
[0036] The mud-flow rate, in the present context, may be calculated
at various depths while drilling or during trips.
[0037] Accordingly, as soon as a flow-rate reduction is detected,
the information will be transferred to the surface, and the
operator will thus be able to immediately react. The preferred next
step will then be to pump a lost-circulation treatment. As the
flow-rate will generally be proportional to the severity, the
present invention will also allow the operator to tailor the
treatment.
[0038] Another improvement is the reduction of risks attached with
lost-circulation treatments. Indeed, some extremely efficient
lost-circulation treatments have recently been developed. These are
based on fluids that crosslink in-situ, forming an extremely strong
mass. One of the risks associated with these fluids is that, if not
placed properly, they may stick the drill pipe, rendering any
subsequent job highly difficult. The present embodiments will allow
precise fluid placement directly into the voids, thereby reducing
the risks. In a preferred embodiment, once the
lost-circulation-zone depth and severity have been determined, a
lost-circulation treatment will be pumped at the required depth,
the treatment having delayed activation. The activation trigger may
be (but would not be limited to) pH, temperature or even the stress
encountered while the fluid passes through the drill-bit
nozzles.
[0039] The apparatus and methods according to the present
embodiments may include surface/tool communication through one or
more communication links, including (but not limited to) hard wire,
optical fiber, wireless, radio, mud-pulse telemetry,
electromagnetic telemetry, wired drill pipe and microwave
transmission. The sensors and communication systems may be powered
locally by battery, fuel cell, fluid flow, or other local power
sources.
[0040] Systems and methods of the embodiments may use information
from one or more sensors in real-time to evaluate and change, if
necessary, the treatment.
[0041] In a further aspect, embodiments allow the identification of
lost-circulation events that are so severe that there is no
returning annular flow. In this case, the first sensor placed above
the depth of the loss zone will not detect any returning flow.
Under these circumstances, pumping a strong
lost-circulation-treatment fluid would be very useful.
[0042] The system and methods may also be used as a diagnostic tool
to determine whether the lost-circulation treatment has been
successful or not. In this case, once the lost-circulation
treatment fluid has been pumped, and normal operations are
restarting, the real-time measurement of the returning flow-rate
will tell immediately to the operator if the treatment was
successful.
[0043] FIG. 1 displays a wellbore 101 drilled through various
geological formations, using a hollow drill pipe 102. A drilling
fluid 103 is pumped down the tubular body. Once reaching the bottom
of the tubular body, the fluid passes through a drill-bit (not
represented), and then moves up the annulus usually to the surface
104. In an ideal configuration, the fluid is recovered and recycled
on surface.
[0044] A first lost-circulation zone 105 is represented by a loss
of fluid from the wellbore into the formation, decreasing the
return-flow rate. The tubular body according is equipped with at
least one annular-flow-rate sensor 106 that will immediately detect
a lost-circulation zone and allow the operator to act accordingly.
In a preferred embodiment, the present invention allows even the
detection of multiple loss zones, as long as the first loss
circulation zone does not create a situation of "total loss." This
is displayed in FIG. 1, where a second loss zone 107 is
represented. When the drill pipe is equipped with several sensors
at various depths, any fluid-velocity differences between various
locations in the annulus would be detected.
[0045] The location and severity of lost-circulation zones is then
straightforward to detect. If no losses occur, the annular-flow
rate is equal to the pump rate. The annular flow rate decreases at
the depth of a lost-circulation zone. The identification of this
flow-rate decrease provides two pieces of information: the depth of
the loss zone and the severity of the losses.
[0046] FIG. 2A shows an arrangement of several fluid velocity
sensors 301a placed around the tubular body 302. Each sensor has a
limited investigation area, but the set of several sensors allows
covering the entire annular-flow area. Alternatively, a single
sensor 301b placed on a rotating pipe (FIG. 2B) provides the same
information.
[0047] A typical application of the invention encompasses, for
example, situations during which drilling is in progress, with the
drilling fluid being pumped at a constant flow rate. At least one
flow-rate sensor is measuring the annular flow rate at a given
depth, and the measured flow rate is being compared in real-time
with the pump rate. The measurement allows identifying potential
losses in two zones--below or above the sensor. If several flow
rate sensors (N) are placed at different depths along the drill
string, these N measurements allow splitting the depth into N+1
depth zones while drilling.
[0048] Another situation is when pumping is stopped, for instance
during a connection. Any flow measured will be an indication of
volume changes. Such changes are indications of losses or even
gains.
[0049] A further situation is when a tubular body is run into the
wellbore, with no mud being pumped. As the tubular body is moving
down, the measured flow rates should correspond to the drillstring
velocity and metal volume being lowered in the hole. Deviation from
this expected value will indicate losses due to, for instance, the
surge pressure.
[0050] In yet a further situation, the tubular body is pulled out
of the hole and pumping is stopped. In this case, the measured flow
rate should correspond to the pipe velocity and metal volume
removed from the hole. Deviations from this behavior would be
observed when a sensor goes crosses a loss zone or when formation
fluids are entering the wellbore below the sensor, for instance
because of transient swab pressure.
[0051] The inventive methods and systems may be employed in any
type of geologic formation, for example (but not limited to)
reservoirs in carbonate and sandstone formations, and may be used
to optimize the placement of treatment fluids, for example, to
maximize wellbore coverage and diversion from high permeability and
water/gas zones, to maximize their injection rate (such as to
optimize Damkohler numbers and fluid-residence times in each
layer), and their compatibility (such as ensuring correct sequence
and optimal composition of fluids in each layer).
[0052] The inventive method may also be useful for detecting leak
locations in a tubular string, e.g., when there is a hole in an
upper casing string when drilling fluid may flow into this annular
space. Similarly, the inventive method might be used for detecting
inflow (kicks, cross-flow) into the wellbore during drilling.
[0053] As used herein, "oilfield" is a generic term including any
hydrocarbon-bearing geologic formation, or formation thought to
include hydrocarbons, including onshore and offshore.
[0054] A "wellbore" may be any type of well, including, but not
limited to, a producing well, a non-producing well, an experimental
well, and exploratory well, and the like. Wellbores may be
vertical, horizontal, some angle between vertical and horizontal,
and combinations thereof, for example a vertical well with a
non-vertical component.
* * * * *