U.S. patent application number 13/128456 was filed with the patent office on 2011-09-15 for methods for minimizing fluid loss to and determining the locations of lost circulation zones.
This patent application is currently assigned to M-I L.L.C.. Invention is credited to Eugene Dakin.
Application Number | 20110220349 13/128456 |
Document ID | / |
Family ID | 42198753 |
Filed Date | 2011-09-15 |
United States Patent
Application |
20110220349 |
Kind Code |
A1 |
Dakin; Eugene |
September 15, 2011 |
METHODS FOR MINIMIZING FLUID LOSS TO AND DETERMINING THE LOCATIONS
OF LOST CIRCULATION ZONES
Abstract
A method for determining a location of a lost circulation zone
in a wellbore having a first wellbore fluid therein that includes
allowing loss of the first wellbore fluid to the lost circulation
zone to stabilize; adding a volume of a second wellbore fluid
having a density less than the first wellbore fluid to the wellbore
on top of the first wellbore fluid to a predetermined wellbore
depth; determining an average density of the combined first
wellbore fluid and second wellbore fluid; mixing the first wellbore
fluid and the second wellbore fluid together; pumping a volume of a
third wellbore fluid having a density greater the average density
of the combined first and second wellbore fluid into the wellbore
bottom until fluid loss occurs; and determining the location of the
lost circulation zone is disclosed.
Inventors: |
Dakin; Eugene; (Langdon,
CA) |
Assignee: |
M-I L.L.C.
Houston
TX
|
Family ID: |
42198753 |
Appl. No.: |
13/128456 |
Filed: |
November 13, 2009 |
PCT Filed: |
November 13, 2009 |
PCT NO: |
PCT/US09/64327 |
371 Date: |
May 10, 2011 |
Current U.S.
Class: |
166/250.08 |
Current CPC
Class: |
E21B 21/003
20130101 |
Class at
Publication: |
166/250.08 |
International
Class: |
E21B 47/10 20060101
E21B047/10 |
Claims
1. A method for determining a location of a lost circulation zone
in a wellbore having a first wellbore fluid therein, comprising:
allowing loss of the first wellbore fluid to the lost circulation
zone to stabilize; adding a volume of a second wellbore fluid
having a density less than the first wellbore fluid to the wellbore
on top of the first wellbore fluid to a predetermined wellbore
depth; determining an average density of the combined first
wellbore fluid and second wellbore fluid; mixing the first wellbore
fluid and the second wellbore fluid together; pumping a volume of a
third wellbore fluid having a density greater the average density
of the combined first and second wellbore fluid into the wellbore
bottom until fluid loss occurs; and determining the location of the
lost circulation zone.
2. The method of claim 1, further comprising: pumping a lost
circulation treatment into the determined location of the lost
circulation zone.
3. The method of claim 1, wherein the third wellbore fluid has a
density of at least 0.5 ppg more than the average density of the
combined first and second wellbore fluid.
4. The method of claim 1, wherein the pumping the volume of third
wellbore comprises: pumping the third wellbore fluid to a bottom of
a drilling assembly; and pumping and measuring pump strokes as the
third wellbore fluid exits the bottom of the drilling assembly
until fluid loss is detected and pumping is halted.
5. The method of claim 1, further comprising: identifying loss of
the first wellbore fluid to the loss circulation zone.
6. The method of claim 5, further comprising: stopping pumping of
the first wellbore fluid into the wellbore.
7. The method of claim 1, further comprising: determining a
location of a second loss circulation zone in the wellbore.
8. The method of claim 1, wherein the mixing comprises forming a
homogenous blend of the first and second wellbore fluids.
9. A method for minimizing fluid loss to a lost circulation zone in
a wellbore having a first wellbore fluid therein, comprising:
allowing loss of the first wellbore fluid to the lost circulation
zone to stabilize; adding a volume of a second wellbore fluid
having a density less than the first wellbore fluid to the wellbore
on top of the first wellbore fluid to a predetermined wellbore
depth; determining an average density of the combined first
wellbore fluid and second wellbore fluid; and pumping a third
wellbore having the determined average density of the combined
first and second wellbore fluids into the wellbore to fill the
wellbore.
10. The method of claim 9, further comprising: drilling with the
third wellbore fluid having the determined average density.
11. The method of claim 9, further comprising: pumping a third
wellbore having the average density of the combined first and
second wellbore fluids into the wellbore to fill the wellbore;
pumping a volume of fourth wellbore fluid having a density greater
the average density of the combined first and second wellbore fluid
into the wellbore bottom until fluid loss occurs; and determining
the location of the lost circulation zone.
12. The method of claim 11, further comprising: pumping a lost
circulation treatment into the determined location of the lost
circulation zone.
13. The method of claim 11, wherein the fourth wellbore fluid has a
density of at least 0.5 ppg more than the average density of the
combined first and second wellbore fluid.
14. The method of claim 11, wherein the pumping the volume of
fourth wellbore comprises: pumping the fourth wellbore fluid to a
bottom of a drilling assembly; and pumping and measuring pump
strokes as the fourth wellbore fluid exits the bottom of the
drilling assembly until fluid loss is detected and pumping is
halted.
15. The method of claim 9, further comprising: identifying loss of
the first wellbore fluid to the formation.
16. The method of claim 9, further comprising: stopping pumping of
the first wellbore fluid into the wellbore.
17. The method of claim 11, further comprising: determining a
location of a second loss circulation zone in the wellbore.
18. The method of claim 9, wherein the pumping the third wellbore
fluid comprises displacing the first and second wellbore fluids
from the wellbore.
19. A method for determining a location of a lost circulation zone
in a wellbore having a wellbore fluid therein, comprising: allowing
loss of the wellbore fluid to the lost circulation zone to
stabilize; calculating the pressure gradient of the lost
circulation zone; increasing the weight of the wellbore fluid in
the wellbore from a bottom of the wellbore upwards until fluid loss
occurs; and calculating the location of the lost circulation
zone.
20. The method of claim 17, further comprising: pumping a lost
circulation treatment into the determined location of the lost
circulation zone.
21. The method of claim 17, wherein calculating the pressure
gradient comprises determining a wellbore fluid density that
balances or slightly overbalances the pressure gradient.
22. The method of claim 17, wherein the fluid loss stabilizes when
the pore pressure and the fluid pressure are substantially the
same.
Description
BACKGROUND OF INVENTION
[0001] 1. Field of the Invention
[0002] Embodiments disclosed herein relate generally to lost
circulation experienced during drilling a wellbore. In particular,
embodiments disclosed herein relate to the identification or
determination of the location(s) of loss zones in a wellbore for
lost circulation treatments.
[0003] 2. Background Art
[0004] During the drilling of a wellbore, various fluids are
typically used in the well for a variety of functions. The fluids
may be circulated through a drill pipe and drill bit into the
wellbore, and then may subsequently flow upward through the
wellbore to the surface. During this circulation, the drilling
fluid may act to remove drill cuttings from the bottom of the hole
to the surface, to suspend cuttings and weighting material when
circulation is interrupted, to control subsurface pressures, to
maintain the integrity of the wellbore until the well section is
cased and cemented, to isolate the fluids from the formation by
providing sufficient hydrostatic pressure to prevent the ingress of
formation fluids into the wellbore, to cool and lubricate the drill
string and bit, and/or to maximize penetration rate.
[0005] Wellbore fluids may also be used to provide sufficient
hydrostatic pressure in the well to prevent the influx and efflux
of formation fluids and wellbore fluids, respectively. When the
pore pressure (the pressure in the formation pore space provided by
the formation fluids) exceeds the pressure in the open wellbore,
the formation fluids tend to flow from the formation into the open
wellbore. Therefore, the pressure in the open wellbore is typically
maintained at a higher pressure than the pore pressure. While it is
highly advantageous to maintain the wellbore pressures above the
pore pressure, on the other hand, if the pressure exerted by the
wellbore fluids exceeds the fracture resistance of the formation, a
formation fracture and thus induced mud losses may occur. Further,
with a formation fracture, when the wellbore fluid in the annulus
flows into the fracture, the loss of wellbore fluid may cause the
hydrostatic pressure in the wellbore to decrease, which may in turn
also allow formation fluids to enter the wellbore. As a result, the
formation fracture pressure typically defines an upper limit for
allowable wellbore pressure in an open wellbore while the pore
pressure defines a lower limit. Therefore, a major constraint on
well design and selection of drilling fluids is the balance between
varying pore pressures and formation fracture pressures or fracture
gradients though the depth of the well.
[0006] As stated above, wellbore fluids are circulated downhole to
remove rock, as well as deliver agents to combat the variety of
issues described above. Fluid compositions may be water- or
oil-based and may comprise weighting agents, surfactants,
proppants, and polymers. However, for a wellbore fluid to perform
all of its functions and allow wellbore operations to continue, the
fluid must stay in the borehole. Frequently, undesirable formation
conditions are encountered in which substantial amounts or, in some
cases, practically all of the wellbore fluid may be lost to the
formation. For example, wellbore fluid can leave the borehole
through large or small fissures or fractures in the formation or
through a highly porous rock matrix surrounding the borehole.
[0007] Lost circulation is a recurring drilling problem,
characterized by loss of drilling mud into downhole formations.
However, other fluids, besides "drilling fluid" can potentially be
lost, including completion, drill-in, production fluid, etc. Lost
circulation can occur naturally in formations that are fractured,
highly permeable, porous, cavernous, or vugular. These earth
formations can include shale, sands, gravel, shell beds, reef
deposits, limestone, dolomite, and chalk, among others.
[0008] Lost circulation may also result from induced pressure
during drilling. Specifically, induced mud losses may occur when
the mud weight, required for well control and to maintain a stable
wellbore, exceeds the fracture resistance of the formations. A
particularly challenging situation arises in depleted reservoirs,
in which the drop in pore pressure weakens hydrocarbon-bearing
rocks, but neighboring or inter-bedded low permeability rocks, such
as shales, maintain their pore pressure. This can make the drilling
of certain depleted zones impossible because the mud weight
required to support the shale exceeds the fracture resistance of
the sands and silts. Another unintentional method by which lost
circulation can result is through the inability to remove low and
high gravity solids from fluids. Without being able to remove such
solids, the fluid density can increase, thereby increasing the hole
pressure, and if such hole pressure exceeds the formation fracture
pressure, fractures and fluid loss can result.
[0009] Losing any fluid to the formation, for any reason, can be a
costly result for the drilling, completion, or production operation
due to the fluid cost as well as the rig downtime and equipment
rental. Mechanical and electrical methods exist for determining the
location(s) or zone(s) of fluid loss; however, they require
specialized equipment and repeated trips in and out of the hole. If
such equipment is unavailable, the location of the loss zones may
not actually be determined but instead larger than necessary
volumes of loss circulation treatments may be pumped into the well
with the hope that the treatment will plug the zone where losses
are occurring so that that drilling (or other) operations may
resume. Because of this inaccuracy, it is typically necessary to
repeat loss circulation treatments, further increasing costs and
downtime.
[0010] Accordingly, there exists a continuing need for methods by
which a loss zone may be easily and more accurately determined
without the cost of specialized equipment so that a loss zone may
be identified and plugged more quickly and the regular drilling or
other operations resumed.
SUMMARY OF INVENTION
[0011] In one aspect, embodiments disclosed herein relate to a
method for determining a location of a lost circulation zone in a
wellbore having a first wellbore fluid therein that includes
allowing loss of the first wellbore fluid to the lost circulation
zone to stabilize; adding a volume of a second wellbore fluid
having a density less than the first wellbore fluid to the wellbore
on top of the first wellbore fluid to a predetermined wellbore
depth; determining an average density of the combined first
wellbore fluid and second wellbore fluid; mixing the first wellbore
fluid and the second wellbore fluid together; pumping a volume of a
third wellbore fluid having a density greater the average density
of the combined first and second wellbore fluid into the wellbore
bottom until fluid loss occurs; and determining the location of the
lost circulation zone.
[0012] In another aspect, embodiments disclosed herein relate to a
method for minimizing fluid loss to a lost circulation zone in a
wellbore having a first wellbore fluid therein that includes
allowing loss of the first wellbore fluid to the lost circulation
zone to stabilize; adding a volume of a second wellbore fluid
having a density less than the first wellbore fluid to the wellbore
on top of the first wellbore fluid to a predetermined wellbore
depth; determining an average density of the combined first
wellbore fluid and second wellbore fluid; and pumping a third
wellbore having the determined average density of the combined
first and second wellbore fluids into the wellbore to fill the
wellbore.
[0013] In yet another aspect, embodiments disclosed herein relate
to a method for determining a location of a lost circulation zone
in a wellbore having a wellbore fluid therein that includes
allowing loss of the wellbore fluid to the lost circulation zone to
stabilize; calculating the pressure gradient of the lost
circulation zone; increasing the weight of the wellbore fluid in
the wellbore from a bottom of the wellbore upwards until fluid loss
occurs; and calculating the location of the lost circulation
zone.
[0014] Other aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF DRAWINGS
[0015] FIGS. 1 to 6 show schematics of a wellbore having a lost
circulation event and subjected to the methods disclosed
herein.
DETAILED DESCRIPTION
[0016] Embodiments disclosed herein generally relate to the
identification or determination of the location(s) of loss zones in
a wellbore. In particular, embodiments disclosed herein relate to
determination of a loss circulation zone so that a lost circulation
treatment may be more accurately placed in the vicinity of the
loss.
[0017] In particular, the method of the present disclosure rely on
the principles of pore pressures and pressure gradients within a
well to determine the location of a lost circulation zone instead
of relying on costly and time-consuming mechanical or electrical
equipment to make sure determinations. Specifically, the methods
described herein may include determination of pressure gradients to
achieve a balanced (or slightly overbalanced) well and then slowing
introducing a heavier wellbore fluid at the wellbore bottomhole
such that when the heavier fluid reaches the depth of the loss
circulation zone, additional fluid loss will occur, indicating the
location of the loss circulation zone has been determined.
[0018] Referring to FIGS. 1 to 6, schematic illustrations of a
wellbore at incremental stages of the methods disclosed herein are
shown. Specifically, as shown in FIG. 1, a wellbore 10 includes a
first wellbore fluid 20 therein. Such wellbore fluid 20 may include
any type of wellbore fluid, including drilling fluids, completion
fluids, drill-in fluids, production fluids, and the like, which may
include one or more liquid and/or gas phases. Rather, no limitation
is placed on the type of wellbore fluid that may be present in the
wellbore when lost circulation occurs, and the present methods may
be applied to determine the location of the lost circulation.
[0019] When a lost circulation event occurs, loss of first wellbore
fluid 20 to the formation at the lost circulation zone 16 occurs,
and is identified, for example, a drop in the fluid level, by
constant or periodic make-up volumes, or the inability to maintain
circulation of the wellbore fluid. Once a lost circulation event is
detected, in accordance methods disclosed herein, pumping of the
first wellbore fluid is stopped, and the fluid level 20a is allowed
to decrease or stabilize to an equilibrium static point 12.
Stabilization occurs when the formation pressure exerted on the
loss circulation zone and the pressure exerted by the fluid in the
wellbore are balanced (or at least substantially balanced).
[0020] Upon stabilization of the first wellbore fluid 20, a second
wellbore fluid 22 lighter than the first wellbore fluid 20 is added
to the casing top (i.e., on top of the first wellbore fluid 20)
until the second wellbore fluid level 20a reaches a predetermined
wellbore depth (which as shown in FIG. 2, is a depth of zero, at
the top of the casing. As mentioned above with respect to first
wellbore fluid 20, second wellbore fluid (as well as any other
wellbore fluids) may include at least one liquid and/or gaseous
component. In a particular embodiment, the second wellbore fluid 26
may be water. The volume of second wellbore fluid 20 added to the
wellbore 10 is measured and recorded. When the second wellbore
fluid 20 is added to the wellbore 10, the first wellbore fluid
level 20a may drop to a greater depth D2 as compared to D1 due to
the increased density/fluid pressure added by the second wellbore
fluid to obtain a pressure balanced system.
[0021] Upon stabilization of the fluids 20 and 22 within the
wellbore and measurement/recordal of the volume of second wellbore
fluid 22 added to the well, the average fluid density between the
combined first and second wellbore fluids 20 and 22 may be
determined. Such determination may be made through calculating the
fluid volume fractions, depth fractions well fractions, total
pressure within the wellbore, and/or average fluid gradient
density. However, one skilled in the art would appreciate that the
ultimate determination (average fluid density) may be broken into
multiple calculation steps or may be performed as a single long
calculation.
[0022] Upon determination of the average density for the balanced
wellbore fluid system in the wellbore (layers of wellbore fluids 20
and 22), the fluids may be mixed/homogenized or displaced (with a
third wellbore fluid) such that the fluid 24 present in the
wellbore 10 is a substantially uniform fluid having a density at
the calculated density (of the first and second wellbore fluids 20
and 22) so that the well remains balanced (or even slightly
overbalanced for safety concerns). Depending on the intent of the
operator, drilling may be continued at this density or the location
of the lost circulation zone may be determined. Drilling may be
continued without making such determination in such an instance
where the operator does not care to determine the location of the
lost circulation zone, but instead desires to determine the maximum
density of the wellbore fluid that may be used to continue drilling
with minimal fluid losses.
[0023] However, if the operator wishes to determine the location of
the lost circulation zone, once the well has a fluid density
substantially balancing the wellbore's pressure gradient, a fourth
wellbore fluid 26 may be pumped into and fill the drill string.
Fourth wellbore fluid 26 may have a density slightly greater than
the balanced wellbore fluid 24. Such increase in density may be
achieved by formulating a fluid 26 having a density greater than
the average density of the first and second wellbore fluids 20 and
22 (through general fluid components, including weight material)
and/or adding a weight material to the a third displacement fluid
24 (if used). The amount of such increase in density (as compared
to balanced fluid 24) may be selected based on the particular well;
however, suitable ranges may include an increase of at least 0.5
ppg in some embodiments and at least 1.0 ppg in other embodiments.
However, no limitation is intended on the scope of the present
disclosure. Rather other density differentials may be used without
departing from the scope of the present disclosure.
[0024] Pumping of fluid 26 out of the drill string and into the
wellbore 10 occurs at a slow rate, and by measuring the pump
strokes so that the volume of fourth wellbore fluid 26 may be
recorded. Additionally, pumping may occur at a slow rate, and with
periodic stops so that fluid loss may be detected as soon as
possible after occurrence. As shown in FIG. 5, no fluid loss to the
formation 18 has occurred because the density of fluid 24 above the
low pressure pore area at the lost circulation zone 16 is the same
as the pressure exerted by the fluid above the zone. However, as
shown in FIG. 6, fluid loss occurs because as the volume of fluid
26 pumped into the wellbore increases such that the fluid level 26a
approaches the lost circulation zone 16, the denser fluid 26 is
exerting greater pressure on the lost circulation zone 16 than what
the formation is exerting on the wellbore fluid 24. As soon as
fluid loss is detected, the measurement of the volume of fluid 26
pumped into the wellbore (as it is pumped from the bottom of the
wellbore up) may be used to determine the depth D3 or location of
lost circulation zone 16 using known wellbore dimensional
values.
[0025] However, it is possible that a single wellbore 10 may
include multiple lost circulation zones 16. In such an instance,
the lost circulation zones may be determined from the bottom of the
well up, repeating the steps described herein until each lost
circulation zone is locationally indentified and treated.
[0026] Following determination of the location(s) of the lost
circulation zone 16, a lost circulation treatment may be accurately
placed proximate the location of the loss zone. Lost circulation
treatments fall into two main categories: low fluid loss treatments
where the fracture or formation is rapidly plugged and sealed; and
high fluid loss treatments where dehydration of the loss prevention
material in the fracture or formation with high leak off of a
carrier fluid fills a fracture and/or forms a plug that then acts
as the foundation for fracture sealing. The mechanism by which
fluid loss is controlled, i.e., plugging, bridging, and filling,
may be based on the particle size distribution, relative fracture
aperture, fluid leak-off through the fracture walls, and fluid loss
to the fracture tip. Accurate placement of such materials may allow
for less rigdown downtime and more managed use of lost circulation
treatments. Selection of lost circulation treatments may be made
based on the type quantification, and analysis of losses,
formation/fracture type, and pressures within the loss zone, many
of which may be quantified during the methods disclosed herein.
Selection based on these factors may be described in greater detail
in U.S. Patent Application No. 61/024,807, which is assigned to the
present assignee and herein incorporated by reference in its
entirety.
[0027] Lost circulation treatments may include particulate- and/or
settable-based treatments. Particulate-based treatments may include
use of particles frequently referred to in the art as bridging
materials. For example, such bridging materials may include at
least one substantially crush resistant particulate solid such that
the bridging material props open and bridges or plugs the fractures
(cracks and fissures) that are induced in the wall of the wellbore.
Examples of bridging materials suitable for use in the present
disclosure include graphite, calcium carbonate (preferably,
marble), dolomite (MgCO.sub.3.CaCO.sub.3), celluloses, micas,
proppant materials such as sands or ceramic particles and
combinations thereof. In addition to such particulate based
treatments, depending on the classified severity of loss, a
reinforcing plug, including cement- or resin-based plugs, may be
necessary to seal off the fracture.
[0028] Settable treatments suitable for use in the methods of the
present disclosure include those that may set or solidify upon a
period of time. The term "settable fluid" as used herein refers to
any suitable liquid material which may be pumped or emplaced
downhole, and will harden over time to form a solid or gelatinous
structure and become more resistance to mechanical deformation.
Examples of compositions that may be included in the carrier fluid
to render it settable include cementious materials, "gunk" and
polymeric or chemical resin components.
[0029] Further, while the present disclosure may refer to use of
these methods in traditional wellbores and/or traditional drilling
operations, the present invention is not so limited. Rather, it is
specifically within the scope of the present invention that the
methods disclosed herein may be used in any wellbore operations,
including, for example, casing drilling, cable drilling,
conventional drilling, reverse circulation drilling, and coiled
tubing drilling, etc.
Example
[0030] The following example is used to demonstrate the manner in
which the depth of a lost circulation zone may be calculated and a
treatment more rapidly and accurately spotted into the well.
[0031] For a given well (such as that shown in FIG. 1) that has an
observed fluid loss of an original wellbore fluid (11 ppg), the
fluid loss may be allowed to stabilize. Following stabilization, a
light density fluid (water, 8.334 ppg) may be added to the top of
the well, as shown in FIG. 2, and the volume of light density fluid
added to the well to fill the well to a predetermined depth (i.e.,
zero depth) is recorded (as shown in Table 1 below). From the
volume of lighter density fluid (3400 gallons), the casing and
drill pipe diameter, the volume per depth (and depth) of the light
density fluid may be calculated. Thus, by knowing the total footage
drilled, the well fractions of the original and light density
fluid, as well as the total pressure along the wellbore, may be
calculated. From this pressure value, the average fluid gradient
(10.079 ppg) is calculated.
TABLE-US-00001 TABLE 1 Calculate Pressure Gradient as Fluid Weight
#1 Original Fluid Density* 11 pounds per gallon #2 Light Density
Fluid* 8.334 pounds per gallon Volume of Light Density Fluid Added
#2* 3400 Gallons Internal Diameter of Casing* 9.625 Inches External
Diameter of Drill Pipe* 3.5 Inches Casing Volume/depth*** 3.2811
gallons per foot Calculated Depth of Light Fluid Added*** 1036.2
Feet of Light Density Fluid Total Well TVD* 3000 Feet Well Fraction
of Original Fluid Density*** 1123.3 psi fraction Well Fraction of
Light Density Fluid*** 449.07 psi fraction Total pressure along
wellbore*** 1572.3 psi at bottom of hole Average fluid gradient
density*** 10.079 pounds per gallon Required *= Data ***=
Calculated Data
[0032] Following mixing of the original and light density fluid to
form a homogenous fluid (10.079 ppg a weight material (at +1 ppg)
may be added to the fluid to form a heavier fluid. The heavier
fluid may be filled into the drill string and slowly pumped at the
borehole bottom. Pump strokes may be calculated, and the pumping
periodically stopped so that fluid levels may be observed and fluid
loss immediately detected. Upon detection of fluid loss, the number
of pump strokes and/or volume of fluid pumped into the wellbore may
be recorded. From the volume of heavier fluid pumped into the
wellbore (as well as drill pipe and bit diameter), the volume per
depth, as well as total feet from the bottomhole, of the heavier
fluid may be calculated. The lost circulation zone will correspond
to the heavier fluid height. From the heavier fluid height, the
depth from the surface may be calculated so that a lost circulation
treatment may be spotted with relative accuracy.
[0033] Embodiments of the present disclosure may advantageously
provide for at least one of the following. Losing any fluid to the
formation, for any reason, can be a costly result for the drilling,
completion, or production operation due to the fluid cost as well
as the rig downtime and equipment rental. Conventional reactions
include use of either mechanical and electrical equipment (with
repeated trips in and out of the hole) or larger than necessary
volumes of loss circulation treatments may be pumped into the well
with the hope that the treatment will plug the zone where losses
are occurring so that that drilling (or other) operations may
resume. Because of this inaccuracy, it is typically necessary to
repeat loss circulation treatments, further increasing costs and
downtime. However, in accordance with the present disclosure,
methods by which a loss zone may be easily and more accurately
determined are provided without the cost of specialized equipment
so that a loss zone may be identified and plugged more quickly and
the regular drilling or other operations resumed.
[0034] While the invention has been described with respect to a
limited number of embodiments, those skilled in the art, having
benefit of this disclosure, will appreciate that other embodiments
can be devised which do not depart from the scope of the invention
as disclosed herein. Accordingly, the scope of the invention should
be limited only by the attached claims.
* * * * *