Note: Descriptions are shown in the official language in which they were submitted.
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DETACHABLE APPARATUS FOR PREVENTING
DIFFERENTIAL PRESSURE STICKING IN WELLS
BACKGROUND OF THE INVENTION
This invention relates to preventing downhole equipment
from sticking in well boreholes. The invention contemplates the
use of improved drill collars and other well implements having a
S porous coating placed on at least a portion of those
implements.
In the drilling of oil wells, gas wells, lixiviant
injection wells, and other b4reholes, various strata are
bypassed in achievin~ the desired depth. Each of these sub-
surface strata has associatèd with it physical parameters, e.~.,porosity, liquid content, hardness, pressure, etc., which make
the drilling art an ongoing challenge. Drilling through a
strat~m produces an amount of rubble and frictional heat; each
of which must be removed if efEicient drilling is to be ~ain-
tained. In rotary drilling operations, heat and rock chips are
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--2--removed by the use of a liquid known as drilling fluid or mud.
Most rotary drilling apparatus use a hollow drill string made up
of a number of drill pipe sections and, of course, a drill bit
at the bottom. Drilling fluid is circulated down through the
drill string, out through orifices in the drill bit where it
picks up rock chips and heat and returns up the annular space
between the drill string and the borehole wall to the surface.
There it is sieved, reconstituted and directed back down into
the drill string.
Drilling fluid may be as simple in composition as clear
water or it may be a complicated mixture of clays, thickeners,
dissolved inorganic components, and weighting agents.
The charactertistics of the drilled geologic strata
and, to some extent, the drilling apparatus determine the
physical parameters of the drilling fluid. For instance, while
drilling through a high pressure layer, e.~ , a gas ~ormation,
the density of the drilling fluid must be increased to the point
that the hydraulic or hydrostatlc head of the Pluid is greater
than the downhole pressure of the stratum to prevent gas leakage
into the annular space surrounding the drill pipe and lower
chances for a blowout.
:`
In strata which are porous in nature and additionally
have a low formation pressure, another problem occurs. Some of
the drilling fluid, because of its hydrostatic head, migrates
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out into the porous layer rather than completing its circuit to
the surface. One common solution of this problem is to use a
drilling fluid which contains bentonite clay or other filtration
control additives. The porous formation tends to filter the
filtration control additive from ~he drilling fluid and form a
filter cake on the borehole wall thereby preventing the outflow
of drilling fluid. As long as this filter cake is intact, very
little fluid is lost to the formation.
.
During drillin~, the rotating drill string is closely
adjacent or in contact with the filter cake. If the filter cake
is soft, thick, or of poor quality or if the drill string thins
the filter cake, then the higher hydrostatic head of the drill-
ing fluid will tend to push the drill string into the filter
cake. In some cases the drill string will stick to the borehole
wall. This phenomenon is known as differential pressure or -~
hydrostatic sticking. In severe cases~ it will be impossible to
either turn the drill string or even move it up and down the
borehole. It is this problem ~or which the apparatus of the
invention is a solution.
The two widely used methods of alleviating hydrostatic
or differential pressure sticking attack the problem from
different flanks; one is remedial and the other preventative.
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Once a drill string is stuck against a filter cake
adjacent a porous formation, the remedy of a chemical spotting
agent is used. It is first necessary to determine where on the
drill string the stickage has occurred. One such method
involves stretching the drill string by pulling it at the sur-
face. Charts are available correlating the resulting stretch
(per amount of applied stress) with feet of drill pipe. Once
this information is known, the injection of water-based drilling
fluid is interrupted and the spotting agent substituted. The
spotting agents are often oleophilic compositions and may be
; oil-based drilling fluids, invert emulsions of water in oil, or
a material as readily available as diesel oil. After the slug
of, typically, lO-50 barrels of spotting agent is introduced,
addition of drilling fluid is re-commenced. The slug of spot-
ting agent continues its trip down through the drill string, out
the drill bit, and up the wellbore annulus until it reaches the
site of the stickage. Upon arrival of the spotting agent at the
stiekage location, circulation is temporarily ceased. Those
skillful in this art speculate that oil-based spottlng agents
tend to dehydrate the fllter cake on the borehole wall and cause
it to break up, thereby allo~ing the ~rill string to come free.
~n any event, once movement of the drill string is detected,
circulation of the drilling fluid is restored. It should be
observed that the cost of this process is high and the success
rate only moderate.
32~
A preventative method of allaying drill string stickage
in porous formations entails the use of drill collars having
flutes, spirals, or slots machined in the outer surfaces. This
method is used to a lesser extent than the spotting agent method
since it involves a higher capital expense, and results in
lighter drill collars. Drill collars are, of course, used for
the speciflc purpose of adding weight to the lower end of a
drill string. Consequently, light drill collars are not viewed
with much enthusiasm. Although these collars are somewhat more
effective in preventing stickage, they are not immune to the
problem since the exterior grooves can be plugged, inter alia,
with soft clay.
.
SUMMARY OF THE INVENTION
The purpose of this invention is to provide downhole
well implements with reduced susceptibility to differential
pressure sticking. In particular, it involves providing such
implements with a wear-resistant porous layer or coating. This
2~ conting may be permeated with a chemical spotting agent. This
coating may also be either permanent or de~achable.
The implements typically requiring such a coating would
be either drill collars or logging tools. Drill collars are
essentially heavy drill pipe sections and are placed between the
drill bit and the upper section of drill pipeO They are used to
stabilize the drill string and weight the drill bit during
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drilling operations. Logging tools are instruments lowered into
an open borehole on a wire-line or cable to measure various for-
mation parameters, e.g., resistivity, sonic velocity, etc.
These measurements are then transformed into usable information
regarding, for instance, natural gas or oil content.
The applied porous coating of ~he present invention is
one that does not present a large unbroken surface area to the
filter cake but does allow liquid migration within the coating
from the open borehole area to an area of contact with the
filter cake. It should be apparent that the well implements,
whether permanently coated with a porous coating or merely
covered with a detachable porous coating, present a substan-
tially nonporous or continuing surface below the innermost level
of the coating. It is theorized that the porous coating's capa-
bility of allowing liquid to flow toward the area of the drill
string's contact with the thinned filter cake is the physical
c~aracteristic which prevents substantial differential pressure
sticking.
2~
It is further contemplated that the pores of the coat-
ing may be impregnated with an oleophilic composition having a
viscosity between that of a light oil and a grease and having
the capability of acting as a localized spotting agent.
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BRIEF DESCRIPTION OF THE DRAWINGS
FIGURE 1 is a schematicized depiction of a typical
drilling rig.
FIGURE 2 is a cross-sectional view of a drill collar in
a borehole having a permanent single laye~r of porous material
attached thereto.
FIGURE 3 is a cross-sectional view of a drill collar in
a borehole having multiple layers of porous material attached
thereto.
FIGURE 4A is a side view of a well implement having
mottled layers of porous material attached thereto.
FIGURE 4B is a side view of a well implement ~aving
bands of permanent layers of porous material attached thereto.
FIGURE 5A is a side view of a detachable porous
covering suitable for use on a well implement.
' FIGURE 5B is a variation of the detachable porous
cove~ing shown ;n FIGURE 5A.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
A conventional rotary drilling rig is shown in FIGURE
1. The portion below ground consists of a drill string and is
made up of upper drill pipe sections 103, drill collars 104, and
drill bit 105. Pipe sections 103 and drill collars 104 are
little more than threaded hollow pipe which are rotated by
equipment on the surface. Drill collars 104 are significantly
heavier than are the sections of drill pipe 103 because they are
intended to weight drill bit 105, to steady the drill string and
to keep it in tension.
. .
The drill string is turned by use of kelly 102, a
flat-sided hollow pipe often square in cross section, whic~ is
screwed into the uppermost section of drill pipe 103. The k&lly
is turned by a powered rotary table 107 through a kelly ~
bushing 108. The drill string and kelly 102 are supported by
rig hoisting equipment on derrick 106.
While the drill string is turning, a drilling fluid or
mud is pumped into the swivel lOl from a hose attached to con-
nection llO. The drilling fluid proceeds down through
kelly 102, upper drill pipes 103, and drill collars 104. The
drilling fluid exits through orifices in drill bit 105 and flows
z~ ~ .
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upwardly through the annulus between the borehole wall 109 and
either the drill collars lQ4 or the drill pipe sections 103.
Drilling fluid leaves the well through pipe 111 for subsequent
recovery, reconstitution and recycling.
For purposes of illustration, the depicted well has a
porous strat~ or layer 114. The well has been treated with a
drilling fluid which left a filter cake 115. The well has, as
most oil wells have, a partial casing 112 terminated by a casing
. 10 shoe 113. Well casings are cemented in place and serve to
isolate the various pressured formations and to prevent contami-
nation o~ water-bearing strata with drilling fluid and
petroleum.
Problems with differential pressure sticking in such a
well normally would occur at the interface between filter
cake 115 and d~ill collar 104.
FIGURE 2 depicts, in horizontal cross-section, a situa-
tion in w~ich a drill collar 104 made in accordance with the
present invention is in contact with a low pressure forma-
tion 114 having a filter cake 115 deposited thereon. The drill
collar 104 has the i~ventive porous coating 150 disposed about
it. The drill collar 104, in this example, squeezed in or
abraded away a portion of filter cake 115 and formed a thin
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--10-
area 155. Since the hydrostatic pressure of the drilling Eluid
in wellbore annulus 154 is higher than the pressure in forma-
tion 114, a potential differential pressure sticking situation
is present.
The wellbore implements of the instant invention, such
as the drill collars depic~ed in FIGURES 1 and 2, or various
logging tools, have thereon a porous coating. Desirable coating
compositions comprise those metals which adhere to the steels
1~ used in most drilling implements after proper treatment. ~hey
are corrosion and wear resistant in the borehole environment.
The coating may also have dispersed within it a number of abra-
sive or wear resistant particles. These abrasives are used to
prolong the life of the coating and may be materials such as
SiC, WC, corundum, etc.
The use of porous ceramic, glass materials or plastics
which are sufficiently tough to undertake the rigors of rig
handling and borehole environment without substantial
degradation are within the scope of this invention.
In theory, the coating prevents differential pressure
sticking for two reasons. First, the rough outer surface of the
coating does not readily provide a seal between the implement
and the filter cake. Secondly, the network of small tunnels
within coating 150 allows the higher pressure fluid in borehole
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annulus 154 to flow via a path 153 to the vicinity of highest
differential pressure to lower the pressure dif~erential at the
interface between the drill collars and the filter cake and
enable movement of the drill string.
Another desirable configuration is depicted in FIGURE 3
and entails multiple layers of coatings of di~ferent permeabili-
ties, e.~., an inner layer 156 or layers produced with large
particles and thereby having a higher permeability, covered by
an outer layer 150 produced f~om smaller particles having lower
permeability. This allows the liquid to flow quickly through
the inner layer to the contact area while the outer layer would
be less susceptible to plugging.
The coating need not completely cover the outside area
of the implement. It must, however9 mask a sufficient propor-
tion of the implement's outer surface to prevent differential
préssure sticking. The coating as shown in FIGURE 4A, may be
mottled 157 in its coverage of the implement. The most desir-
able configuration entails bands 158 of coating as shown in
FIGURE 4B. The coating need not be uniform in thickness in
either case although such is desirable from the viewpoint of
lessened solids buildup on the drill collar 104.
IL21L~3~
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Production of the coating may take place any well-known
prior art method. The often corrosive environment presented by
drilling fluids somewhat limits the choice of materials which
are suitable as coatings for the drill implements. However,
application of powdered iron alloys with or without additional
abrasive material such as silica or alundum to steel and iron
substrates is shown is U.S. Patent No. 2,350,179 (issued on May
30, 1944 to Marvin). The process taught therein partially
presinters the powders to create a pre- form corresponding in
shape to the desired backing. The pre- sintered form is placed
on its backing material and both are raised to a temperature
suitable for sintering the particles and bonding them to the
support. A reducing atmosphere is used in the latter sintering
step. The sintered layer is then rolled either while still in
lS the sintering oven or shortly after its exit to enhance the
adhesion between the layers. ~`
Another suitable method for producing a porous coating
on a drill implement is disclosed in U.S. patent No. 3,753,757
2~ (issued on August 31, 1~73 to Rodgers et al). This process
entnils ~irst:applying a diluted polyisobutylene polymer to the
implement. The polymer forms a tacky base to which metal pow-
ders will adhere. An appropriate metal powder of iron, steel,
or stainless steel is then applied to the tacky surface prefer-
ably by electrostatic spraying. The implement is heated to a
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first temperature sufficient to volatilize the isobutylene poly-
mer and a second temperature sufficient to bond the powder to
itself and the implement.
The optional abrasive powders are mixed with the metal
powders at or before the time of application. The sintering
temperature of most abrasives is significantly higher than that
of any metal or alloy realistically useful on a drill imple-
ment. For instance, the sintering temperatures of tungsten car-
10 bide is 2650-2700Fo The usual sintering temperature for AISI
C102~ carbon steel i5 generally about 2000F. A tungsten car-
bide particle therefore comes through the powder sintering
process largely unaffected.
When ferrous powders are used to coat the implement,
treating in superheated steam (1000-1100F) for a short length
of time a~ter sintering is desirable. Such treatment causes an
increase in the wear and corrosion resistance of the coating by
producing a thin layer of black iron oxide on the exterior of
the particles.
Another method of placing a porous coating on well
implements entails use o~ removable devices such as those shown
in FIGURES 5A and 5B. FIGURE 5A shown a removable coating
assembly in which a thin nonporous layer 160 is coated by a per-
meable layer 162 made in the manner discussed above. The two or
more parts are hinged together at hinge 164. The two halves are
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swung together over a well implement and bolted together using
recessed boltholes 166 and nutholes 168. Holes 181 may be cut
through layer 160 to expose both sides of permeable layer 162.
In this way, the permeability of layer 162 may be monitored
during the lifetime of the assembly.
FIGURE 5B shows another embodiment of a removable coat-
ing assembly. This embodiment uses two similar halves; one of
which is shown 170. Each half has fingers 172 along the mating
edge which fit into matching depressions on the other halE.
When assembled around a well implement~ a pin 174 is inserted
through a series of holes which line up through the meshing
fingers 172. Two pins 174 hold the assembly together. Alter-
nately, a hinge, as shown in FIGURE 5A, may be substituted for a
set of meshing fingers. The assembly half 170 is made up of a
nonporous backing 178, to add strength to the assembly, and the ~`
porous coating 180. Holes 181 may also be integrated in this
deqign.
The length of the remarkable coating assembly shown in
FIGURE 5A and 5B is not particularly critical. Its area must be
sufficient to cover the well implement to pre~ent sticking.
Siz;ng depends on the particulars of the involved well. The
removable coating assembly s~ould fit snug against the well
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implement around which it is installed. Several may be placed
on a single well implement and form a complete covering or a
number of bands.
The porous coating on the removable coating assemblies
shown in FIGURES 5A and SB may be mottled, banded~ or be made up
of multiple layers having varying porosities as discussed
above. The coatings may also contain the abrasion-resistant
materials mentioned supra.
The removable assembly shown in FIGUR~S 5A and SB are
especially suitable for lighter well implements such as logging
tools. These may be fabricated from the noted plastic, metal,
glass, ceramic, or wear resistant composite materials.
In any event, once the implements are provided with a
porous coating, they are used as any uncoated implement would
be. However, if so desired, the porous openings in the outer
layer may be impregnated with an oleophilic composition having a
viscosity between about that of diesel oil and about that of
grease. Greases may be applied by a number of methods. For
i instance, the greases may be diluted in a volatile hydrocarbon
solvent and sprayed on the implement. Once the solvent evapo-
rates, the grease will rema;n both on the surface of the imple-
men~ and in the outer pores of the applied coating. The greases
3~
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obviously may also be applied by rolling or brushing. The
lighter hydrocarbons may be sprayed or brushed or the implement
may be dipped into the hydrocarbon prior to use.
The added oleophilic composition has dual functions.
It primarily serves as a localized spotting agent. However,
some lubricity is also present especially when heavier
hydrocarbons are applied.
In sum, the instant invention is readily applicable to
either new or existing well implements. It uses only well known
materials and methods of application and yet solves a heretofore
serious problem.
However, it should be understood that the foregoing
disclosure and description are only illustrative and explanatory -~
of the invention. Various changes in size, shape, materials of
construction, and configuration as well as in the details of the
illustrated construction may be made within the scope of the
appended claims without departing from the spirit of the
invention.
