Note: Descriptions are shown in the official language in which they were submitted.
2 1 ~ 7
wO 94/21889 PCT/GB94/00515
Improvements in or Relatin~ to Drillin~
And to The Extraction of ~luids.
,,~,
The present invention relates to drilling, apparatus therefor and to the extraction of
fluids from reservoirs. In one specific application the invention relates to theextraction of oil and the like from underground or undersea reservoirs.
The extraction of oil from underground or undersea natural reservoirs, often ~;Çt;--ed
to as oil recovery, has long since passed the stage of simple pumping teçhniquesespecially in relation to heavy oils. It is gerierally considered that the average initial
recovery of oil from a reservoir is only about 20% of the oil in the reservoir.
Particularly with a view to enh~ncing the quantity of oil which can be recovered from a
reservoir and in some circ~lmct~nces making extraction from certain types of reservoir
or deposit feasible, it is Known to use techniques such as hot water or steam flooding
of an oil reservoir. These techniques consist of pumping hot water or steam,
respectively, into the natural reservoir so as to reduce the viscosity of the oil or the like
so as to enable it to be pumped more readily to the surface. Average oil recovery can
be increased using these techniques to between 30 % and 50%, depending on the
particular characteristics of the reservoir and the oil.
Despite relatively low current day oil prices, techniques as drastic as fire flooding have
also been proposed and used. The fire flooding technique involves igniting part of the
oil in the natural reservoir such that the heat thereby released lowers the viscosity of
the rem~ining oil so that it can successfillly be pumped to the surface. The det~ d
techniques are often quite complex, with variations such as forward and reverse
combustion, additional air injection and the like. It is also known to pump solvents
into an oil well in order to reduce the viscosity of the crude oil and so enable recovery
thereof.
In the above mentioned "flooding" techniques energy has to be used to generate and
apply the heat to the oil to be recovered. Typically, at least 25% of the recoverable oil
resource is used (or the energy equivalent thereof) to generate the heat needed to
f~cilit~te recovery ofthat recoverable oil. For many years these techniq-~s have been
the best available, despite the enormously large fin~nci~l gain from red~lcin~ the 25%
or more wastage of the recoverable resource.
2 1 ~
WO 94121889 2 PCT/GB94/OOSlS --
~ .
With a view, for example, to mitigating the above mentioned disadvantage, according
to a first aspect of the present invention there is provided a method of extracting fluid
from a reservoir of said fluid comprising the use of geothermal energy.
Preferably, the method comprises the drilling of a well into an area of geothermal
energy so as to enable release of the geothermal energy into the fluid reservoir.
The applicant has invented an especially adv~nt~geo~ confi~ration of wells for the
extraction of geothermal energy generally. Thus, accordh~g to another aspect of the
present invention there is provided a method of extracting geothermal energy from the
ground comprising the drilling of a configuration of wells as shown in figure 14A of
the accompanying drawings alone or as shown in figures 14A and l5A ofthe
accompanying drawings in combination.
In implementing the first aspect of the present invention it can be particularly ben~firi~l
to have the ability to drill horizontal and/or upwardly e~ennin~ bores from a
conventional downward e~t.onding well bore. Further aspects ofthe invention are
concerned with the apparatus which enable such well bores to be drilled.
Thus, according to a second aspect of the present invention there is provided a tool for
use in the drilling of wells~ comprising a tool body and a plurality of segm~nt~ movable
with respect to the bodv in a radial direction with respect to the well bore.
Similarly, according to another aspect of the present invention there is provided a tool
for use in the drilling of wells, comprising a main body, a calliper body, a plurality of
segmentc movable with respect to the calliper body in a radial direction with respect to
the well bore, and a mech~nicm for moving the main body with respect to the calliper
body.
According to another aspect of the present invention there is provided a tool for use in
the drilling of wells, comprising a body having first and second portions coupled by a
joint wherein the joint is adapted to be controlled by fluid pressure so as to change the
angle of inclin~tion of the said body portions relative to each other.
According to yet another aspect of the present invention there is provided a tool for
use in the drilling of wells, comprising a tool body and a plurality of se~ P~ movable
with respect to the body with each segment having a cutting edge at one end thereof
2 1 ~ 7
WO 94/21889 3 PCT/GB94/00515
and with movement of the segments being such that the said ends move in a radialdirection with respect to the well bore.
According to yet another aspect of the present invention there is provided a
pump/motor for use in the drilling of wells, comprising a ho~lcin~ having an internal
helix, a fixed female external helix outer stator with an internal helix and a fixed male
helix.
According to yet another aspect of the present invention there is provided a drilling
motor for use in the drilling of wells, comprising an epitrochoidal rotary cylinder and a
trirotor.
The various aspects of the invention will now be described by way of example only and
with reference to the accompanying drawings, in which:-
Figure 1 illustrates a well drilled with a downward bore followed by a holizonlal bore,bv means of which three reservoirs of oil or the like are accesse(l;
Figure 2 illustrates a "U" shaped well in which a downward vertical bore 1 is followed
bv a short horizontal bore 4 and then an upward vertical bore 2;
Figure 3 illustrates a well which accecsPs two oil reservoirs;
Fi_ure 4 illustrates the use of multiple bores exten~in~ from a common downward
bore;
Figure S illustrates the use of multiple wells inclu~ing in particular a well which passes
through an area of geothermal energy and which subsequently extends into an oil
reservolr;
Figure 6 illustrates the use of multiple "J" shaped bores e~rten~ing from a single vertical
bore and a subsequent horizontal bore;
Figure 7 illustrates an arr?ngement of wells which might be provided so as to apply
geotherrnal energy directly to a reservoir of heavy crude oil;
2158G37
WO 94/21889 4 PCT/GB94/00515--
Figure 8 illustrates an arrangement in which separate wells are used to create the
artificial fracturing of the granite rock formation and to forrn a pathway for the
geothermal energy to enter the oil reservoir;
Figure 9 illustrates a variation of the arrangement shown in figure 8;
Figure 10 illustrates a further arrangement in which a separate cold water injection well
is used to create an artificial network of fractures in a granite forrnation;
Figure I 1 shows a diagr~mm~tic view of the drilling and production of an oil reservoir
and a hot dry rock steam injection method;
Figure 12 illustrates an arrangement in which high flow rates are used;
Figure 13 illustrates an arrangement in which a shaft/tunnels are drilled and horizontal
twin wells are drilled with coiled tubing units
Figures 14A & B show well injection and production geometry for high production
flow rates with single injector well and twin trilateral production wells;
Figures 1 5A & B illustrate a plan views of the wells shown in figures 14A & B,
respectively;
Figure 16 shows a radial cross-section of an adjustable rotary reamer/stabiliser;
Figure 17 shows a radial cross-section of an adjustable reamer/stabiliser blade with
spherical cutter balls;
Figure 18 shows a radial cross-section of a reamer/stabiliser blade with cross cutting
barrel rollers;
Figure 19 shows a radial cross-section of a reamer/stabiliser blade with vertical cutter
rollers;
Figure 20 shows an axial cross-section of a reamer/stabliser body;
Figure 21 shows a radial cross-section of a caliper thrust unit;
2158 G37
Wo 94/21889 5 pcTlGs94loo5l5
Figure 22 is an axial cross-section of the caliper thrust unit;
Figure 23 is an axial cross-section of the caliper thrust unit caliper body and hydraulic
drill collar piston valve block assembly;
.~
Figure 24 is a radial cross-section of a caliper thrust unit piston;
A
Figure 25 is a radial cross-section of the hydraulic drill collar piston valve assembly and
cylinder body with telemetry unit controllers and valve control spool, telemetry unit
controllers for dump valves;
Figure 26 is a radial cross-section of a telemetry control unit;
Figure 27 shows a radial cross-section of a dual acting telemetry unit controller;
Figure 28 shows an axial top section of a pivot ball joint;
Figure 29 shows an axial cross-section of the trajectory control unit, cylinder body and
piston with piston guide control tube and rod;
Figure 30 shows a radial cross-section of a flexible connection;
Figure 31 shows a radial cross-section of a fluid dump valve;
Figure 32 shows a radial cross-section of a down-hole drilling motor;
Figure 33 shows a diagramatic drawing of a drilling assembly for directionaUhorizontal
drilling;
Figure 34 shows radial cross-sections of a telemetry unit controller;
Figure 35 shows radial cross-sections of a telemetry unit controller;
,.
Figure 36 shows a radial cross-section ofthe toggle bar and toggle latch with latch
plates;
Figure 37 shows a diagramatic drawing of two single trajectory control units in a
drilling assembly;
_
2158~7
WO 94/21889 , j 6 PCT/GB94/00515
Figure 3 8 shows a diagramatic drawing of a single trajectory control unit in a drilling
system;
Figure 3 9 shows radial cross-section of an orientation unit;
Figure 40 shows a diagramatic view of a twin bend housing assembly trajectory control
unit;
Figure 41 shows a radial cross-section of a universal joint and output thrust shaft;
Figure 42 shows a radial cross-section of a trajectory control unit and down-hole
motor sealed bearing assembly (singie ~end sub);
Figure 43 shows the main mechanism of the figure 42b arrangement to a larger scale;
Figure 44 shows a radial cross-section of a compPn~ting underreamer, hole
opener/milling tool;
Figure 45 shows epitrochoidal rotoritrirotor stator positive displ~cçmPnt mud drilling
motor with fixed orbital trirotor stator and rotary epitrochoidal outer rotor with rotary
stabiliser;
Figure 46 illustrates the position of the trirotor in the epitrochoidal rotary ch~mher of
the motor shown in fi_ure 45; and
Figure 47 shows a radial cross-section of a multiphase flow type ultralobe cavity
trirotor pump.
Figure 1 to 13 inclusive show examples of the extraction of oil from an oil reservoir
using the method of drilling into a an area of geothermal energy ~djacçnt the oil
reservoir. Although geothermal energy has previously been used, eg for the gen~ lion
of electricity, it has not previously been proposed to use geothermal energy to aid in
the recovery of heavy oils and the like.
It has been well known for very many years that molten rock lies beneath the earth's
crust. The materials of the crust are poor conductors of heat and are cooled by ground
water circulation. At sufficient depths, a steep temperature gradient exists - often as
WO 94/21889 7 2 i 5 8 ~ 3 7 PCT/GB94/00515
high as 20C/km or even ~0C/km. What is not well known, and what has not
previously been utilised to any signific~nt extent, is the fact that in most parts of the
world temperatures sufficiently high to produce high pressure steam exist at depths
which can be reached with conventional drilling techniques, namely of the order of
l Okm to l ~ km.
The conventional methods of hot water or steam flooding are inefflcient, since rapid
cooling takes place as the water or steam is passed through pipes to the well and
passes through the cool ground materials and/or seawater above the oil reservoir.
Generation of the hot water or steam typically involves the burning of fuels which are
environmentally d~m~Ping, causing acid rain, accelerating the destruction of forests
and adding to global warming. Particularly for undersea oil wells, where the
production of the hot water or steam must take place on the confined area of an oil
platform, the risks arising from potential ignition of fluids from the reservoir are
sufficiently great to prevent e:Ytensive use of such techniques. Techniques involving
the use of solvents also involve a significant risk of causing pollution.
Use according to the present invention of geothermal energy can avoid the above
mentioned difficulties associated with conventional techniques.
There are various methods by which geothermal energy can be applied to a reservoir of
oil. One preferred method according to the present invention is to fracture the rock
formations between the geothermal area and the oil reservoir. This involves
engineering to provide artificial permeability of the rock formations. The çnginpering
comprises the drilling of appropriately cont;gured wells and the injection of a fluid,
usually water under high pressure, to cause a network of fractures which will provide a
pathway for the geothermal energy to be applied to the oil reservoir. Another
p,e~ d method involves the drilling of a well through an area of geothermal energy
and e~enciing the well beyond the area of geothermal energy into the oil reservoir. In
an alternative arrangement, the well may be drilled through the oil reservoir and
beyond the reservoir into an area of geothermal energy with subsequent blocking of
the well above the fluid reservoir. In this arrangement preferably the well is blocked
using a non-return valve, so as to permit the subsequent introduction downhole of any
desired fluids.
.
Particularly in the above described embudiment in which a well is drilled into the
geothermal area and subsequently into the oil reservoir, the well bore will often need to
first extend down to the geothermal area and then extend upwardly to the oil reservoir.
~lS~S~
WO 94/21889 '- 8 PCT/GB94/00515 --
Often it will also be desirable for the well bore to extend horizontally for part of its
length. The drilling of upwardly and/or horizontally e~ontlin~ well bores is generally
not feasible, or is inefficient and unreliable, using conventional drilling app~d~.ls.
Thus, in accordance with other aspects of the present invention there are provided
various devices which enable the desired well configurations to be drilled with ease,
efficiency and reliability.
2158~7
WO 94/21889 9 PCT/GB94/00515
Figure 1 illustrates a well drilled with a downward bore followed by a holizo,lLal bore,
by means of which three reservoirs of oil or the like are accessed for extraction of the
oil. A downward, vertical bore 1 is drilled from the surface 6 through the layers of
surface material 7. A generally horizontal bore 2 is drilled from the base of the vertical
bore 1, so as to extend through one oil reservoir, 4, and into another, 5. A third oil
reservoir, 3, is accessed via an upward directed bore 8 e~n-iing from the h~ on~al
bore 2.
Figure 2 illustrates a "U" shaped well in which a downward vertical bore 1 is followed
by a short horizontal bore 4 and then an upward vertical bore 2. Rock formations are
indicated generally by reference 5 and reference 6 indicates a granite rock strata. High
pressure water injected into the well bores 1,2 and 4 cause the granite to rupture, as
indicated by reference 3.
Figure 3 illustrates a well which accesses two oil reservoirs, 4 and 5. First a
downward bore enters the first oil reservoir and the bore is then extended in a
generally horizontal direction~ at section 2, followed by a short upward bore 3 and
finally another horizontal bore 7 which extends into reservoir 4. Reference 6 inrlic~tes
the layers of surface material.
Figure 4 illustrates the use of multiple bores extPnrling from a common downwardbore, 1. The bottom of bore I branches into two bores which extend into di~ere--~parts of a large oil reservoir 5. One of the two bores, bore 2, is a generally ho,izo.,Lal
bore. The other of the two bores. bore 3, has a horizontal portion followed by an
upward portion. The upward portion extends into the second oil reservoir, 6. A third
bore, 4, extends into reservoir 6 from a side wall part way down the downward bore 1.
Reference 7 indicates the layers of surface material.
Figure 5 illustrates the use of multiple wells inclu~ing in particular a well which passes
through an area of geothermal energy and which subsequently extends into an oil
reservoir. Reference 8 indicates lavers of surface material and reference 6 inriir~tes a
granite rock formation which has been artificially fractured, as indicated by lerere.lce 5.
The well exten-ling through the geothermal area comprises a downward bore 1, an
upward bore 3 and a generally horizontal bore 4. Bore 4 extends into the oil reservoir,
7. Geothermal energy enters the well in the region of the artificial fractures 5 and
passes along the well to reach the oil reservoir 7. The vertical bore 1 may be blocked
offas appl.)p,iate. Geothermal energy entering the reservoir 7 reduces the viscosity of
heavy crude oil in the reservoir and thus enables the recovery thereof via the three
I
2 1 ~ 7
WO 94/21889 lO PCT/GB94/00515
additional wells which are independently drilled from the surface into the reservoir 7.
The three additional wells are included so as to illustrate the various configurations
which might be used. One of the additional wells consists of a simple vertical
downward bore 1 1. Another of the wells comprises a downward bore 1~ followed bya generally horizontal bore 9. The third additional well has a generally "J" shaped
configuration, with a vertical bore 7 and a curved extension ,12, at the end thereof.
- Figure 6 illustrates the use of multiple "J" shàped bores 3 e~ctPn~ing from a single
vertical bore 1 and a subsequent horizontal bore 2. References S and 6 indicate rock
formations and reference 4 indicates the crude oil reservoir.
Figure 7 illustrates an arrangement of wells which might be provided so as to apply
geothermal energy directly to a reservoir of heavy crude oil, so as to enable the
recovery of oil which might not otherwise be possible. A vertical bore 6 is drilled from
the surface 1 through rock formations 2, 4 until an area of granite 5 is reached. A
generally horizontal bore 7 is drilled in the granite formation, or along the surface
thereof.. The well is extended beyond the granite area by an upward bore 8 so as to
reach a reservoir of heavy crude oil 3. Within the reservoir the well continues as a
generally horizontal bore 9, so as to increase dispersion of geothermal energy within
the reservoir. The granite lies above an area of geothermal energy and is artificially
fractured by the injection of high pressure cold water into bores 1 and 7. A separate
well is used for extraction of the reduced viscosity oil. The extraction well comprises a
vertical bore 1 1 drilled from the surface 10 and an upward bore 13 and a ho"zonLal
bore 14 which extend from the bottom ofthe vertical bore 11 into the reservoir 3.
Figure 8 illustrates an arrangement in which separate wells are used to create the
artificial fracturing of the granite rock formation and to form a pathway for the
geothermal energy to enter the oil reservoir. Three wells are shown in total, one being
a cold water injection well for fracturing the granite and the other two being oil
extraction wells which penetrate the oil reservoir 4. Each of the three wells are drilled
from the surface 1 through surface rock formations 2 and 3. The cold water injection
well comprises a bore 7 which extends down to the granite formation 5. Each of the
two wells entering the oil reservoir comprise a downward bore 9 continl~ing into at t
least one further bore. In one case the further bore is a generally horizontal bore 8 and
in the other case multiple bores extend from the vertical bore. The multiple bores
comprise a "J" shaped bore and a generally horizontal bore 1 1, both of which access
di~, en~ parts of the oil reservoir. The horizontal bore is drilled laterally from the
215~637
WO 94121889 11 PCT/GB94100515
vertical bore of the "J" and below that junction a downward bore 10 is drilled to
access, via a subsequent horizontal bore 12, the artificially fractured granite.
A variation of the arrangement shown in figure 8 is shown in figure 9. Again a
separate well, 7, is used for the formation of an artificial network of fractures, 6, in a
layer of granite, 5. An extensive reservoir, 3, of heavy crude oil is ~ccessed by a
plurality of wells. One of the wells is shown as having dual ho,i~on~al bores ~l~tPn~in~
within the reservoir from the bottom of a vertical bore 8. Another well has a
configuration which may be referred to as generally "S" shaped. That is, the well
comprises a vertical bore 10 drilled from the surface 1 through surface layers of
material 2 followed by a horizontal bore 11 which extends within the oil reservoir and
finally a downward bore 12 which passes through various rock formations 4 below the
oil reservoir so as to reach the fracture network 6 in the granite. An additional
horizontal bore 1 1 is drilled laterally from the base of vertical bore 10 and the well is
blocked off, preferably using a non-return valve 13, just above the base of the vertical
bore 10. The well thus acts as a pathway for wide dispersal of geothermal energywithin the oil reservoir.
Figure 10 illustrates a further arrangement in which a separate cold water injection
well, 7, is used to create an artificial network of fractures, 6, in a granite formation 5.
An additional side bore 8 is used to e~ctend the area of artificial fracturing. A single
large rli~meter bore 9 is drilled from the surface 16 vertically into an extensive
reservoir 3 of heavy crude oil. Multiple bores are drilled from the base of bore 9. A
"J" shaped bore 14 and a horizontal bore 13 access different parts ofthe reservoir.
Two "S" shaped bores 11 and 12 extend through rock formations 4 below the
reservoir and access the artificial fracture nçtwork.
Crude oils below 20 degree API gravity are usually considered to be heavy.
The lighter conventional crudes are often waterfiooded to e~h~nre recovery. The
injection of water into the reservoir helps to ~ reservoir pressure and displace
the oil toward the production wells. In general waterfiooding is most effective with
light crude oil of 25 degree API gravity and higher and becomes progressively less
effective with oils below 25 degree API. with crudes of 20 degree and lower,
waterfloods are ess--nti~lly ineffective and thermal recovery becomes nec~ssAly~ Very
few thermal projects are s~lccessfill in recovering oil of less than 10 degree API
gravity. Heavy clude oils have enough mobility that, given time, they will be
producible through a well bore in response to thermal recovery methods Tar sands
21~86~7
WO 94/21889 12 PCT/GB94/00515
contain immobile bitumen that will not flow into a well bore even under thermal
stim~ tion,
For world production of oil of all types, primary recovery (flowing and pumped
wells) averages about ~0 percent of in-place oil. Secondary recovery metho~lc
(waterflooding or gas injection) are used in an effort to m~int~in or restore reservoir
pressure and can improve recovery from 30 to 50 percent of the in-place oil,
depending on reservoir conditions and oil prope,lies.
Fnh~nced recovery processes are dpcign~d to reduce oil viscosity and
capillarity by introducing into a reservoir other sllhs~nces, such as carbon dioxide,
polymers, solvents and micellar fluids in various combinations. Processes of this sort
can further increase recovery from 40 to 80 percent of the in-place oil.
Thermal recovery methods are used to enh~nce the production of heavy crude
oils~ the recovery of which is impeded by viscous resict~nre to flow at reservoir
temperatures. The recovery of the immobile oil in tar sands that will not flow even in
response to therrnal stimulation requires mining.
This is no longer a problem with the ultradeep crude technology (UCT) method
as total heat at varying depths can now be placed directly into the oil bearing formation
from the underlying hot dry rocks (HDR) reservoir and various types of hGI;zolll~l "J"
and "S" type production well bores to drain the reservoir.
Energy from accescible regions of hot rock beneath the earth's surface that do
not contain suff~cient natural porosity or permeability, energy can be extracted from
artificially fractured reservoirs that emlll~te natural geothermal systems. The primary
technique for engineP~ring these so-called hot rock (HDR) geothermal reservoirs
utilises tluid pressure to open and propagate fractures from an inclined well, creal;ng
artificial permeability within a fracture network. This hydraulically stim~ tlod region is
then connected to a second well to complete the underground system. Heat is
extracted by circul~tin~ water from the surface, down one well, through the fractured
rock network1 and up the second well. The heated water then passes through an
appropriately designed power plant on the surface where, for inct~nce~ electricity or
process steam is generated. The cooled fluid is then reinjected to complete a closed
loop cycle. Thus, effluentc from HDR systems are practically non-existent.
Because hot dry rock systems do not require contained hot fluids and high
permeability, the HDR resource - the ~ccecsible thermal energy in the earth's crust - is
much larger and more widely distributed than natural geothermal systems. Numerous
estim~tes place the accPccible HDR resource base somewhere between 10 and 13
million quads in the U.S.A.~ and over 100 million quads worldwide. ~Ccecci~le isdefined as the normal depth attainable using conventional drilling technology (about 10
K~n).
215~G~
WO 94/2l889 13 pcTlGs94loo5
The recovery o~ heavy crude oils is impeded by a vis~o~s lesistan~e to flow at
reservoir temperatures. The heating ~f heavy crudes marke~ly proves their mobilit,v
and promotes their recovery. Heat ma~ be introduced into th~ reservoir by injecting a
hot fluid. such as steam or hot water, or by burning some of the heavy oil in the
r reservoir (a process referred to as in situ combustion or fire flooding).
The bitumen in tar sands can be recovered by sufface mining methods.
A common method involving the use of steam to recover heavy oil is known as
steam soak, or cyclic steam injection, it is essçnti~lly a well-bore stim~ tiorl tec~ln~ e
in which steam generated in a boiler at the surface is injected into a production well for
a number of weeks, aPter which the well is closed down for several days before being
put back into production. In many cases there is a significant increase in output. It is
sometimes economic to steam soak the well several times, even through heavy oil
recovery using declines with each succeedirig treatment. Steam soaks are
economically effective only in thick permeable reservoirs in which vertical (gravity)
cl~;nage can o~cur.
Con~nuous steam injection heats a larger ~ ion of ~hereservoir and achieves
~he most e~cient heavy oil recoveries known are s~ flo~d; na~, this ~echniq~ is a
displacement process similar to waterflooding. St~rn is pumped into i~jecti¢n ~lls
and the oil is displaced to production wells.
Because of the relatively high cost of steam, water is sometimes injected at an
optimum time to push the steam toward the production wells. Since the steam serves
two filnctions, the heating and transportin,~ of the oil, some steam must always be
circulated through the rock formation with~ut con(ienCing Even in some of the most
f~vourable reservoirs, it is necessary to consume an amount of energy equivalent to
burning roughly 25 to 35 percent Qf the heaYr oil produced in order to generate the
required amount of steam. The mechanics ~f heavy oil displ~cPmPnt in an in situ
combustion operation is similar to that in the steam-flooding process. Steam is
produced by vaporising water that has been injected therein with heat from the in situ
combustion of some of the oil in the reservoir. After the in place heavy oil has been
ignited the burning front is moved along by continuous air injection, in one variation of
the in situ combustion process known as forward combustion, air is injected into a well
so as to advance the burning front and heat and displace both the oil and water to
surrounding produced wells.
A modified form offorward combustion incorporates the injection of cold
water along with air to recover some of the heat remains behind the combustion front.
The air-water combination minimice5 the amount of air injected and the amount of in-
place oil burned (to between 5 and l O percent), in another variation of in situcombustion called reverse combustion, a short-temm forward bum is initi~ted by air
21~86~7
WO 94/21889 -, 14 PCT/GB94/0051~--
injection into a well that will eventually produce oil, after which the air injection is
switched to ~djacent wells. This process is used for recovering ~A~ lllely viscous oil
that will not move through a cold zone ahead of a forward-combustion front.
The costs associated with the generation of heat within a heavy oil reservoir
and the success of the recovery process are influerlced by the depth of the reservoir.
In general shallower reservoirs are c~nrii~tps for steam soaks and steam floods
while deeper reservoirs for in situ combu~rion. Solvent extractions also have been
used to recover heavy oils, in this process a solvent emulsifying solution is injected into
a heavy oil reservoir. The fluid dissolves or emlllcifies the oil as it advances through
the permeable reservoir. The oil and fluid are then pumped to the surface through
production wells. At the surface, the oil is separated from the fluid and the fluid is
recycled.
The ultradeep crude technology (UCT) uses the method of hot dry rock (HDR)
geothermal energy (high pressure steam) to utilise natural heat contained in the earth's
crust for thermal enhanced oil recovery, it can provide a non-polluting energy in the
form of high pressure steam or hot water.
Few people have considered that the earth's internal heat is one of our largest
supplies of energy, in fact almost anywhere in the world it is already possible to drill
holes deep enough to reach temperatures sllfficiently high to produce high pressure
steam and high pressure water, this heat, geothermal energy, is produced mostly by
disintegration of naturallv occurring unstable forms of uranium, thorium and potassium
because the rocks soil and gravels that make up the earth's outer crust conduct heat
poorlv, much of the heat remains stored in the solid rock at considerable depth in most
places a hole drilled from the surface passes first through layers of se~iimPnts and
fractured rock that are kept cool as ground water circulation temperature begins to
increase quite rapidly as typically occurs in any in~nl~ting material between a hot body
and it's cool surroundings this temperature increase and the increasing pressure of the
material above it cause the rocks to become progressively drier as well as hotter, the
typical hot dry rock (HDR) situation worldwide. It can help mitigate the continued
warming of the earth through the greenhouse effect and the accelerating destruction of
forests and crops by acid rain, two of the major environmPnt~l consequences.
The use of fossil fuels to run steam generator plants to produce stearn to
therrnally ~h~nce reservoirs on and offshore to produce oil that would not otherwise t
be recoverable from S degree API and above, one offshore field discovered north of
the Shetlands was capped and abandoned as the viscosity of the oil in place was 2
degree API it was not fluid enough to be produced without stearn, that could not be
produced offshore until now with this (UCT) production system.
2158G37
WO 94/21889 15 PCT/GB94/00515
HDR energy (steam) or high pressure hot water is available virtually
everywhere on the earth's surface with the resources temperature inexorably h~creasul~g
with depth. The actual quality or grade of the (~)R) resource at a specific location
~vill control development costs, the primary p~eter d~t~ h~ing the local grade of
the resource is the average temperature gradient or conversely the drilling depth
required to reach a temperature suitable for the specified thermal enh~nced oil
recovery, either high pressure steam or hot water. Unlike hydrothermal or
geoplt:s~,~lred resources that require inr~ig~nous hot fluids, hot dry rock systems need
omy hot rocks at ~ccessible depths in the earth's crust (HDR) resources range fro~m
low-grade regions having norrnal to near normal temperature gradients of 20 C to 40
C/km to high grade regions with above-normal gradients greater than 40C/km. Thelower-grade gradients is distributed more or less uniformly throughout the world.
While the higher grade resources are found frequently within or near active natural
geotherrnal areas.
For the (HDR) concept to work in practice the underground system must be
properly engineered, a large open fractured reservoir should be created providing
artificial permeability where i~ does not exist naturally to permit efficient heat
extraction by circ~ ting water in addition, optimally placed well(s) that maximise the
efficiency of the heat-mining process must access the reservoir stim.~l~tion methods in
the hot crystalline rock are used to properly engineer an (HDR) system. A method of
drilling "J", "U" and "S" type wells and horizontal branch from the "J" loop for oil and
~ras hot rock geotherrnal and heaw oil and tar sands produ.,ion with the use of caliper
thrust units (CTU) (hydraulic) used to thrust forward, (add weight) to the drill bit with
the ald of a dn~ ng mud motor w~lth near bit s,tabiliser unit used in conjunction with
coiled tubing or drill pipe.
To recover heavy oil, tar sands and oil shale the technic~l criteria requires:-
A. Ability to generate heat into the reservoir at efficient rates.
B. Ability to displace the heated oil.
C. Ability to recover the oil in a controlled manner.
An initial well is drilled into non-porous porosity of 1 part in 10000 granite.
The well at this point is drilled horizontal to a given point then drilled upwards in a "J"
type configuration into the oil bearing forrnation and if necess~ry can even be taken
along horizontally from the top of the vertical "J" or "S" loop or by injection well and
production extraction well drilled laterally or horizontally through the oil bearing
formation then vertical or laterally down in to the HDR reservoir the extraction well is
then plugged back above the oil formation. Production wells are then pattern drilled
into the reservoir from the surface, with hot water the gas phase can be supplied by
carbon dioxide C02 or nitrogen injection into the (HDR) reservoir on the closed loop
2158637
WO 94/21889 16 PCT/GB94/00515 --
system, to fully sweep the oil reservoir. The main cold water injection line into the
(HDR) in the horizontal section is fractured along its length, cold water is iniected into
the well at pressure to hydraulically fracturing the (HDR) reservoir to produce super
heated steam at very high te.npe.atllrçs above 300C depending on the depth ofthe
injection well. A method to producé stearn by (HDR) is by an injection well, and a
second intersecting well into the fractured zone to produce well head steam, butobviously steam driven to the surface then fed by flow lines to various parts of the field
for re-injection into the oil reservoir would be costly and would lose ten,pclalure very
quickly, in the same way as produced steam by stearn g-,nelation on the surface. The
(UCT) method quick]y places the total heat from the steam/hot water directly into the
oil reservoir driving the oil to the production wells in the pressurised closed HDR
circulation loop.
Subterranean hot spots are so wide spread all over the world with (HDR)
reservoirs created in myriad locations such as offshore, as all oil fields have underlying
granite formation with subterranean hot spots that can be utilised. Above average
values of heat are obtained when hot rocks are overlaying by thick se~liment~ ofhydrocarbon that provide insulation.
The bore hole is drilled to target depth, then the water is pumped in to the well
bore at pressure. This, combined with depth of head pressure in the well bore column
of thousands of feet, makes the pressure at the well bottom far too great for the rocks
to resist, so they simply fracture, explosive charges may be used to induce fractures.
The water is then forced up through the hcrizontal or lateral and up the "J" loop
vertical of the well bore and comes out as superheated steam in the oil, tar sands, or,
oil shale formation where the pressure and heat is so great that the oil is forced up
through the production well bore system under pressure to the well heads to the
separation and extraction plant where the cold water is then returned back down the
injection well on a closed loop svstem. Further injection of solvents and or gas may
also )e injected into the well bore injector, producing large quantities of super heated
steam or hot water and follow up hot water sweep after the steam breakthrough which
correspondingly lowers oil to steam ratios to up to 50% attributing higher recoveries.
The (UCT) high pressure method of steam drive makes this a very attractive
proposition even with low well head prices.
By making optimal use under the (UCT) method steam and hot water in the
early stages of the project in addition to limiting wastage of heat, it is eApe~,~ed that the
steam or hot water that is kept in the formation in this way will ultim~tely improve the
oil production from the other producers.
Also selective production from the deeper parts of the reservoir can be
expected to induce steam or hot water entry into this reservoir area or other underlying
wO 94/21889 ~15 ~ 6 3 7 pcTlGs94loosls
forrnations and improve the vertical steam/water distribution with a very high oil to
steam/water ratio is expected production water is fully recycled so it is returned to the
(HDR) injection well, sea water under offshore is ideal for this process fl~ching the
brine back by return line may also be needed in this process to keep the reservoir
fractures clear.
High pressure hot water can be produced at about 130 degrees C and above at
lower drilling depths, this would be ideal for hot water at pressures from 1,000 to
4,000 PSI depending on the formation with ultra high flow rates delivered by high
pressure pumps to fully sweep the whole of the reservoir to Illtim~tely improve the
heat flow within the reservoir.
It has been impossible to exploit for crude oil, heavy crudes, tar sands and oilshales economically and environmentally under reservoir conditions until now, and was
not possible offshore. Production at any dépth by the (UCT) method under pressure in
the formation with vertical, lateral and horizontal well bores, considerable amounts of
crude can now be produced by pressure fracturing. Injection is controlled from the
HDR injection well by the cold water and/or carbon dioxide Co2 into the oil reservoir
from the hot rocks then superheated steam or hop water is driven up at pressure via
the vertical or horizontal well through the vertical "J" loop well bore into the oil
reservoir, the pressure forces the crude oil through the production well bores drilled
into the reservoirs outlying wells, they will need to be piped into the closed loop
svstem as the hot front is pushed towards them as the pressure lowers at the
fi~rthermost point of the reservoir. .~ fracture occurs in the hydraulically connected oil
bearing sand in the well bore when hvdraulic pressure in the hole is larger than the
stress produced by the overburden weight.
A vertical bore is drilled to target depth below the oil reservoir, then drilledho.izonlally under the reservoir (large bore holes can then be drilled with the TCU
method) then multiple vertical upward bores are drilled into the oil reservoir. The oil
flows into holi ~ontal collection bore area by gravity and is pumped to the surface
under pressure by the main vertical bore to the wellhead on a closed loop system. This
method is extremely efficient at extracting most of the oil from the reservoir. The
system can be used in conjunction with (HDR) (EOR) thermal steam drive Fig. 2, 5and 8 "J" type drilling.
The process of high pressure reservoirs is derived from the capability of
hydrocarbons to dissolve in water at near critical conditions so the pressure is above
3000 PSI and temperature above 300 degrees centigrade, and are efficient in densely
fissured reservoirs for heavy and light oil, te~ L.Ires of 3 80 degrees centigrade to
480 degrees centigrade are required for oil shale recovery, so deeper well bores are
required.
21586~
WO 94/21889 18 PCT/GB94/00515 --
To drill extended reach horizontal wells and vertical wells from the holi~onl~l
and horizontal wells from the vertical known as "S" "U" and "J" type drilling and
horizontal from the "J" type loop drilling for oil, gas, hot dry rock geothermal, heavy
oil, tar sands and oil shales and production wells with the use of thrust calliper units
(hydraulic) used to thrust forward (add weight to the drill bit or bits) along with the
trajectory control drilling mud motor with near bit stabiliser all used in conjunction
with coiled tubing or drill pipe. The coile~d tubing carries an internal multicore
electrical conduit for control purposes ~MWD) improving drilling control, to improve
the link between the coiled tubing unit for drilling (MWD), exploration, production
and work-over wells from the sm~llest to the largest wellbores.
This method is also efficient for producing lower pressure/te.np~ re
steamihot water into the reservoirs by the (HDR) method at lesser drilling depths. The
HDR geothermal concept is a proven method of producing high or low pressure stearn
and or hot water no obstacle has been found that would hold back its development,
HDR reservoirs can be found in regions of previously impermeable crystalline rock
with thermal/flow properLies to allow for efficient heat/steam flows, in New Mexico
(HDR) temperatures were as high as 232 degrees centigrade at under 4krn depth, and
to create even larger HDR reservoirs you would only need to pump cold water downfor longer periods of time since the reservoir producing the steam volume is directly
proportional to the amount of water injected in to the HDR reservoir, so one would
only need to hydraulically fracture the reservoir at the outset.
Water under high pressure can be used to open and extend the fractured area.
This dilated region of hot jointed crystalline rock is referred to as (HDR) hot dry rocks
, the drilling of the vertical/lateral injection well or wells bore and the production wells
or wells vertical lateral then into the horizontal, then vertical again into the HDR
reservoir.
The producing steam well bore can either be plugged above the oil bearing
zone or a none return valve placed down hole so as to allow for injection or other
agents, and temperature recording equipment as shown in Fig. 9 item: 13 further side
tracked hol-zolltal wells can also be drilled from each vertical bore as item: 9 further
steam injector horizontal bore can also be run from producing steam well shown in Fig.
9 item: 11, the scope to drill this type to produce (HDR) steam injected into an oil
bearing reservoir from undemeath has vast enhanced oil recovery potential and is the
most economical way to produce oil from a reservoir and the only way in which toproduce heavy oil offshore and above all is en~,iro.,.-.~"l,.lly safe, with ab--n~nce of
water. UCT steam or hot water is injec~ed continllollcly from one well bore or more
upwards from hot dry rocks (HDR) into the reserwir causing the viscosity of the oil to
be reduced until it becomes mobile and can be displaced or produced by gravity
215~6~7
WO 94/21889 19 PCT/GB9~/00515
drainage or vertical and horizontal in surrounding wells in a closed loop or open
system. The principal advantage is high pressure, volume and heat retention in the
process of steam tr~ncmission to the oil reservoir. When the steam is driven upwards
and forward into the reservoir, it is the only safe method to produce ultradeep oil
bearing formations also with the possible aid of injecting high te~ el~L-Ire super
critical carbon dioxide Co2 in to the (HDR) reservoir increasing recovering effi~iency
due to the action of Co2 with oil or other types of stim~ nts and the res--ltingrlicpl~çement and sweep efficiencies. UCT high grade steam quality will enter into
sand body to allow partial coking or in-situ sand consolidation without undue reservoir
permeability damage.
Wells over 5,000 feet in depth could not normally be drilled for use with
generated steam to enhance oil recoverv because heat loss would be great and
e~ciency so low that steaming is not a viable technique, the UCT method overcomes
all of these problems as the total heat is placed where it is most needed in the oil
bearing formation, there is no limitation to depth of oil production with this (UCT)
method, this method also increases the amount of original oil in place (OOIP) to be
produced as none is used to produce the steam normally, between one third and a
quarter of all oil produced is used by the steam generators to produce the steam. This
alone is a tremendous cost saving. When using the (UCT) method it allows you to
drill larger bore holes to inject steam in to the reservoir at much larger qu~ntiti~ than
surface type injection methods, also with long horizontal (HDR) drilled section~ to
cover all points of the reservoir for high pressure fracturing and steam drive of soak.
The basic difficulty was distributing heat induced into the reservoir along with the total
v olume of the oil heavy crude, tar sands and oil shale increasing their viscosity and
making them mobile. This is now possible with the use of the (UCT) method when the
high pressure steam or other agent is released into the formation (reservoir) from
underneath the reservoir in horizontal and "J" type drilling (large bore drainage system)
the pressure is so great with high injection rates forming fractures and fissures for the
heating up of the reservoir oil by uniform thermal stimul~tion of the reservoir.With this efficiency ~f the warm up in saturated ~dj~cent zones by means of
thermal agent injection temperatures of 200 degrees C to 500 degrees C are possible
for the stimulation of the reservoir by bottom hole reservoir injection in the active zone
between injection and production wells temperature is dependent on the depth and heat
flow gradient of the underlying basement (HDR injection well or wells), the heat flow
in granite, projected bottom hole temperatures increase with di~e~ ent crustal
sllccec~ions of sediment~ry rocks / shale / coal / lim.ostone / mudstone / sandstone to
cover 200 degrees C at 4km depth with all granite formation temperature is only about
2 15~7
WO 94/21889 20 PCT/GB94/0051~--
120 degrees C for the same depth the main temperature in underlying granite formation
is about 30 degrees C for each lkm depth.
In high grade (HDR) resources drilling will result in signific~ntly lower
reservoir development costs for example, for a 60 degree c/km resource one needsonly to drill to about 4km ( 13,0~0 feet) depth for initial rock temperatures of about
250 degrees C.
Heavy oil deposits require the creation of fractures to induce artificial
injectivity and significantly enlarge the interface between oil sands and injected fluid.
This improves heat transfer by convection and conduction fractures created during the
stimnl~tion process are acting as natural ch~nnPIc for fluid and heat transfer into the
reservoir.
The UCT method is expected to be used for either high pressure, low volume
steam/hot water of low pressure~ high volume steam/hot water and high pressure high
volume steam/hot water.
As ste~ming temperatures continue through the reservoir, the heated oil is
driven to the producing wells by a complex array of displ~cement meçh~nismc
incl~l~ing hot gas driven water displacement, hot water drive and steam or solvent
assisted steam/hot water drive in a closed loop system.
Injection of fluids at significant rates can only be achieved by exceeAin~ the
parting or fracturing pressure of the formation continued injection with only partial
withdrawal of fluid can cause reservoir pressures to increase until in-situ formation
stresses are exceeded, this high pressure injection can induce formation movement,
~ood communication between the injector wells and producers is vital for m~rimllm
production in this closed loop system.
The major thermal losses from conventional steam generators can be
categorised as follows:-
A. Steam generator inefficiencies chiefly heat losses in the existing gas flue gas.
B. Heat loss from surface transmission lines.
C. Down hole heat losses - function of well construction and steam te~ c-~Lure.
D. Ancillary equipment and pollution control equipment utility control equipment.
Excessive water production in a field can be drawn and re-injected down the
HDR injection well. Engineering and cost considerations are foremost in simplicity
with pressurised hot water for enhanced recovery in all type of reservoirs high
viscosity crudes, heavy crudes and tar sands in commercial quantities, with heatcontent of the (HDR) water/fluid transferred to the oil reselvoir unlike generated heat
from a small amount of steam fraction obtained by flashing the hot water, a continuous
hot water flood would be superior to steam injection by oil field gen~tola in some
reservoirs.
21S~G~7
WO 94/21889 ~1 PCT/Gs94/00515
The normal method of steam drive has always been used from the surface down
to the formation and never upwards into the formation from underneath the reservoir.
With superheated steam the method of fractures and channelling for efficient sweep of
the reservoir by steam drive (flooding) to increase Illtim~te recovery using this (UCT)
method in the reservoir in the high injection rates can give rise to reservoir ch~nn~lc
and subsequent oil flows.
Normal steam drive, flood, cyclic thermal recovering uses large ~nno--ntc of
produced crude to operate the steam generator with the limited depth restrictions due
to heat loss and very expensive to run. With the (UCT) method there are no heat
losses, no running costs, other than the cold water injection, with at least a twenty five
vear life span before deepening or expanding the HDR reservoir, with no air pollution,
this will allow the reservoir to remain very hot, accomplishing good production rates,
about 600 tar sand occurrences are known to exist in the United States of America
alone.
The handling of the effluent water is part of the production cycle being re-
injected into the cold vater injection well down to the hot dry rocks, again this may
possibly be treated first, in some cases before being re-cycled for produced steam,
a ain injection rates can be high and pressure also. It is also possible to inject raw
sewage into the (HDR) reservoir to produce steam in the same way.
One major problem when using hot water or steam for enh~nced oil recovery
for increased production and extraction of oil from the reservoir, compared to
conventional production methods, to produce one barrel of oil large amounts of hot
water or steam has to be injected into the reservoir. but some of the produced water is
obtained from underground wells, however the extra barrels of waste water produced
could not be re-introduced back into the reservoir, only by re-injection into the
reservoir of old gas wells, or through pipelines and pumping stations or by the costly
method of vapour co~-~p~es~i\te plants to allow the re-use ofthe water in the
environment, but with the HDR/EORlthermal (UCT) method the solution to this
problem is very simple. just increase the injection flow rate pressures to allow the
(HDR) hot dry rock reservoir to grow in size to allow extra storage of produced water
within the crystalline rock reservoir for future use, solving a major em,i,on.--~..t~l
problem when producing oil with minim~l equipment cost on this closed loop system.
Enhanced oil recovery and heavy crude, tar sands by (UCT) method of
production development on offshore platforms are far cheaper to produce with less
equipment needed on the platforms, and could be the only method to steam drive areservoir offshore. this alone is a tremendous cost saving offshore, due to govellllll~,nt
regulations covering oil fired boilers.
WO 94/21889 21~ 3 G 3 7 " PCT/GB94/00515
Steam or hot water injection is the most advanced e~h~n~ed oil recovery
technology for crude oil production, in some cases it may be n~ceS.cA. y to use
additives, like foaming agents to plug the steam filled zones so that it is driven into
those parts of the reservoir that are still saturated with oil, in order to increase the
l-ffisiency it is necess~ry to use additives to decrease interfacial tension and .~.eclul-i
completions to allow for production after steam breakthrough.
Steam injection into a high fissured re~servoir will prefc.~bly flow through thefissure and continuously condense against the walls of the matrix blocks until these
blocks have reached steam temperature, the con~enced water will be removed rapidly
from the steam zone by gravity. As a result of the high fissure permeability during the
heating process, oil will be expected from the matrix blocks as a result of the thermal
expansion and thermally induced solution gas drive. The oil which amounts to some
15% ofthe oil in place is produced almost imme~i~tely and renders the recovery
balance for the steam process right from the start.
Heavy oil occurrences of economic importance occur in most countries in
sandstone or limestone at depths of between 150 ft and 1400 ft. As numerous
evaluations show resources of oil shale in the world are very significantly larger than
first thou_ht running into trillions of barrels of oil. The oil shale reserves in Colorado,
U.S.A., alone are 4-5 trillion short tons, oil shale, tar sands and heavy oil occupy the
lower part of the hydrocarbon scale if they are located in the order of increasing
density and viscosity. The deposits can be effectively developed ony by using heat or
hot agents, that is, by thermal methods, there are four methods to develop heavycrude~ tar sands and oil shale deposits.
~. Open pit mining plus hot agent processing of the rock in the plant.
B. Mine development plus same as "A".
C. Mine well drainage, drilling wells in the mine vertically and injection of hot
agent heat into the well bore.
D. Well drainage drilling the well from the surface injector of hot agent from the
surface to the reservoir.
Most countries in the world have granite formations which underlie oil bearing
formations, the granite formation has a high geothermal gradient potential for
HDR/UCT production, the vast amount of heavy crude oil, tar sands and oil shale and
conventional oil by the (UCT) enhanced recovery method. These resources are
guaranteed for the future cnntinuation of the oil industry.
Steam injection quality is the key factor in steam zone formation, some higher
quality will be problematical. The effect of steam quality on oil recovery has a dual
role, it deterrnines heat input, and it also determines the two phase flow in the rock.
The quality of steam can be controlled in hot dry rock enh~nced oil recovery
2158~3~
WO 94/21889 '3 PCT/GB94/00515
(HDRIEOR) thermal ultradeep crude ~echnology (UCT) by depth of hot dry rock
reservoir, or with carbon dioxide co2, with a super-critical carbon dioxide condition.
The artificial lifting of crude oil from reservoirs with steam, hot water and
wa.er-flood creates constant ch~nP:~s that effect artificial liPc design. The lifted liquid
volume increases while the percent of crude oil in the produced fluid decreases. This
increased expense and decreased return on capital will cause many producing wells to
become marginal and some uneconomic, so the need to lift greater produced fluid
volumes more efficiently is required. The closed loop production system with theultradeep crude technology - hot dry rock - enh~nced oil recovery is very efficient for
this purpose, with very high injection and produced fluid flow rates with no extra
artificial lifting equipment, with no restrictions on depth for producing reservoir fluid,
work-over well costs are minimaL efficiency is high, capital costs low and
environmentally good with high capital return.
~ :xtra heavy crude oil, tar sands, and oil sands are bitumens or petroleum like
liquids or semi solid occurring naturally in porous and fractured media, oil illlyle~ ed
rock, bitumens have viscosities greater than 10,000 m~as. Crude oils have viscosities
less than 10,000 mPas. These viscosities are gas free as measured and re~l~nced to
original reservoir temperature extra heavy crude oil have densities greater than 1,000
Kg per cubic metre (AF~I gravities less than 10 degrees). Heavy crude oils have
densities from 934 to 1000 Kg per cubic measure (AF~I gravities from 20 degrees to 10
degrees inclusive). These densities (AF~I gravities) are referenced to 15.6 degrees C
(60 degrees F) and the atmospheric pressure.
Crude oil with densities less than 934 Kg per cubic measure (A~I gravities
greater than 20 degrees) are classified as medium light, other crude oil below 20
degree A~I gravities are classified as heavy, extra heavy crude oil, tar sands, oil said
and oil shale. These are world wide at depths as great as 14,000 feet in rocks of
various lithologies and ages, in all climatic regions both on shore and offshore. A vast
amount of reservoirs that have been discovered have been plugged and abandoned or
else never tested. The amount of heavy crude oil also extra heavy crude oil, tar sands
and oil shale resourced runs into many trillions of barrels.
Thermal processes are the predominant recovery methods the processes are
primarily aimed towards a viscosity reduction and hence increase the mobility of this
type of crude oil for production. The technological advances in the (UCT) recovery
methods, if we take one nil field in California where 4000,000 barrel per day of heavy
crude is produced in the field, to produce this, 100,000 of crude per day is required to
run the steam generators, to produce the steam to recover the 4000,000 barrels, most
of the oil produced in this reservoir ranges from 1 1 degrees to 15 degrees API. With
the (UCT) method, the production would be 500,000 barrels per day, as no crude oil is
21~53~
WO 94/21889 . 24 PCT/GB94/00515
required to run the steam generators. If we take 18 USD per barrel, this is a saving of
It800,000 USD per day, so using the (HDR) (UCD) method is a very small price to
pay for the increased production, and will also be eA~ ...ely economical.
The (UCT) method is expected to be used for either high pressure, low volume
steam or low pressure high volume steam and high pressure volume steam. As
steaming temperatures continue through the reservoir the heated oil is driven to the
producing well by a complex array of ~licplacpmpnt mPçh~nicmc inrl~ ing hot gas
drive, water displacement, hot water drive and steam drive or solvent ~cei~ted steam
drive and even compressed air within oil shale formation as air with oil is exotherrnal
and will aid in the recovery of oil from the kerogen rocks by the large wellboredraining system and the (HDR) method. One of the North Sea oil fields, Efofisk in
the Norwegian sector, used cold water re-injection for the EOR to recover extra oil in
place within the reservoir, thermal recovery would nave been much more productive,
with a far greater recovery rate. but, the wel! was offshore and the depth of the
reservoir was too great, for it to be used.
With the (UCT) method it can now be used to recover even more oil, within
the reservoir, obviously these numbers are small, compared to the Vene~el~n Orinoco
deposits, if the production reached 10,000,000 barrels per day, and the savings on that
level of production are enormous. The heavy oil deposits of Canada, Vento7--
~Columbia, U.S.A, the Russian Commonwealth of Independent States and China,
amount to over twelve trillion barrels, even two trillion barrels of crude produced,
would still be twelve times as much as Saudi Arabia's stated recoverable reserves of
165 billion barrels.
Development of the economically marginal resources, and the development of
increased recovery efficiencies (EOR), a vast amount of heavy crude, tar sands and
heavy shale are present in the world. The very best extractions costs are one barrel
burnt to produce the steam for about twenty barrels produced, but normally it is one
barrel used to produce the steam, for every three produced. Environment~lly and
equally important is the sulphur and nitrogen sulphides from the stack gases by
scrubbers. The recovery factor using (UCT) method could include increase recovery
rates of over 90% of the oil in place in the reservoir with this new innovative
production technology (UCT) these include water, gas, solvent, surf~ct~nts and
polymers.
The ideal way to produce the oil from the reservoir is to drill vertical, then
horizontal under the formation, then vertical into the reservoir using the (UCT) drilling
method with large bore hole as described in figure 6, with the use of "J" type well
drilling, and using the horizontal well for collecting the oil by gravity drainage, then
produced to the surface by the vertical well.
21~$637~
¦~ WO 94/21889 ~5 PCT/GB94/00515
The drilling of "J" type wells can be of larg~ neter, the geology of all oil
fields are a crystalline b~semtont under seflimPnt~ry bas~s are conctit~lted by
metamorphic volcanic rocks and granite. The very high cost of high pressure steam
injection from the surface normally makes uneconomica! to produce crude oil until
now. Vast heavy oil occurrence offshore underlying the huge Frigg and Heimdal gas
fields in the Norwegian sector of the North Sea, the Bressay fields, also close to the
Ninian field, and the Clair field in the U.K. sector, and the Den-Helda field in the
Dutch sector of the North Sea.
The depth of each underlying granite formation will vary in each location hot
spots are found at a depth from 30 degrees C per kilometre depth and above to 70degrees C km.
The right kind of low conductivity se~iiment layer with different crustal
successions can effectively insulate the buriéd granite further ~nh~ncing its geothermal
potential and obviating the need for excessively deep drilling.
There is a granite layer in the earth's crust which completely surrounds the
earth. This granite layer is relatively hot compared to surface temperatures. In some
areas of the world, it is close to the surface, and in others. it is buried below miles of
surface formations. The first step in the process of recovering the heat energy from
this layer is to drill an injection well into the HDR formation which has very low
permeability (e.g. granite) and sufficient temperature (preferably 240 to 330C).
~ext, artificial fractures are created and held open in the rock formation usinghvdraulic stim~ tion techniques. Once the fracture system is created, one or more
productions wells are drilled into the fracture zone so that they connect the fracture
svstem to the surface. ~ater is then circulated under pressure from the surface into
the injection well through the fracture system where it collects heat energy from the
hot rock forrnation, and then to the surface where the heat energy is extracted from the
water using a heat exchanger. The cooled water is then reinjected into the injection
well starting the cycle over again. The low permeability of the fractured reservoir
prevents most of the water from being lost, creating a closed loop system of
continuous circulation. ~3ackup water reservoirs on the surface are used to supplement
the injection well as necessary to keep the reservoir fully charges with fluid until the
reservoir size has stabilised. The heat energy thus collected on the surface may be
used directly to heat the oil reservoir or make electricity. The system for mining heat
energy from hot dry rock (HDR) is ~ssenti~lly pollution free, as coml)ared to
conventional steam power generation plants, which create heat energy by burning
fossil fuels. The well configurations shown in figures 14 and 15 ofthe accG-l-p~lying
drawings are especially beneficial and are estim~ted to be capable of potentially
reducing the cost of geothermal generation by as much as 80%.
wo 94/21889 2 1~ ~ G ~ 7 26 PCT/GB94/00515 ~
Well-Bore Drilling Trajectory Development for Production Wells
By ultra-extended reach horizontal wells "J" shaped wells, reverse wells that
are deviated to the horizontal load, drilled late~ally through a section of the pay zone
then deviated upwards, the upward direction to achieve:-
(a) To drill into a second target or pay~zone areas(b) Extenriin~ recovery high into the pay zone area
(c) To place injector high into the reservoir
(d) Underground access technology, large bore holes are drilled vertically so itreaches under the oil reservoir from which wells can be drilled vertically upwards to
the reservoir, draining the reservoir by gravity is extremely efficient
(e) Horizontal well sections will be lined with slotted liners
(f) Injector and injector producers well bore or bores are on a closed loop
production system
.~11 this achieved with the use of the thrust calliper unit trajectory control
drilling motor.
Drillin~ with Coiled Tubing Units
To drill large diameter or slimhole and horizontal "J" and "U" type wells a
downhole thruster tool is extremely useful to drill long reach wells with coiled tubing
or drill pipe together with special guidance tools, better downhole motors and drill bits
to make the hole with light pressure. With coiled tubing you cannot rotate the string
so normal methods do not allow for rotation of reamers/stabilisers and norrnal use of
directional control unit overcomes all forms of directional well control from the
surface, unlike the norrnal method where tripping the drill string from the hole is
needed to replace directional control tools in the drill string.
This method opens up a completely new field of drilling practices together with
cost saving in exploration and production drilling using coiled tubing drilling units or
conventional drill pipe, coiled tubing can be tripped in very fast and out of the well
with continuous fluid circulation. Unlike norrnal rotary drilling, bottom hole
conditions can be monitored with through tubing electrical cables, kill weight drill
fluids are not required to control the well. Multiple bores can be drilled from the one
bore, drilling can take place with the well under full pressure, back wrapping of the
pipe (tube torquing) is overcome with the thrust calliper units drilling vertically,
ho,izo,.lal "U" and "J" type wells is now possible and even drilling ho,i~o"Lal from the
vertical loop of the "J" type well.
21~637
WO 94/21889 7 PCT/GB94/00515
The downhole positive displacement motor (PDM) is also very adv~nt~eous in
a drilling system. This invention employs trajectory control unit with the drilling motor
and sealed bearings with stabiliser body which will propel itself by hydraulic thrusters,
thrust calliper units anchored against hydraulic drill collars that grind the well bor~. In
place of the drill collars the system elimin~tes the need for drill string weight on the
drill bit and Plimin~tes the limitations of co,-,p- es~;~rely loading the lower part of the
drill string to push the bit through the vertical and holi~u..lal and the "U" type drilling.
Wells which are deviated to the horizontal mode, drilled laterally through a section of
pay zone then deviated upwards, either to reach a second pay zone or extend higher
into the pay zone or place injections well high in the reservoir, are ideal for drilling hot
dry rock, geothermal injection and production of steam wells, also "J" type well for
heavy oil production in combination with the hot rock drilling to inject into heavy oil
and tar sand formations from the one bore hole. The wells can be deviated through
any range of vectors and are ideal for pressure depleted zones. The system can drill
radials of ~7/8" inside diameter (I.D.) well bores to the largest size well-bore.
Ultradeep Crude Technology (UCT)
Schematic drawing (fi~ure 8) shows where a situation may be encountered,
depth wise with either coiled ~bing or conventional drill string where "J" type drilling
may prove to be costly using present day tubing technology. In this situation, bore
hole (7) will be cold water feed injector and bore hole (9) will be the steam production
outlet line from the hot dry rocks, drilled from the top to intersect the HDR fractures.
The bore hole (9) will run through the oil bearing reservoir. The casing will be cut just
above the oil reservoir as shown at ( 10), by the milling or cutting method, the bore
hole (9) will be side tracked into a horizontal bore hole (11), and the rern~in-ler ofthe
production line (9), intersecting the HDR will then become bore hole (12), producing
steam into the oil reservoir (4), the bore hole (8) is drilled horizontal into the oil
reservoir and item (13) can be drilled in the "J" type configuration, well bore to be
placed from underneath the reservoir.
Schematic drawing (figure 9) shows where a situation is encountered depth
wise showing injector for cold water (item 7) drilled into fractured HDR reservoir and
production extraction steam or hot water well (item 10) is drilled in the "S" type
vertical or lateral from the surface and lateral or horizontal through the oil bearing
foundation, then laterally or vertically down to intersect with the HDR reservoir. The
well bore is then plugged back at item 13. Above the oil reservoir, more than one
injector and/or producer can be drilled in each field if required with each well placed to
a closed loop production system.
2158637
WO 94/21889 ~8 PCT/GB94/00515
The schPm~tic drawing shows figure 12 where high flow rates are required to
be brought to the surface for separation and reinjection of the geofluid into the oil
reservoir.
1. Shows doublet and trilateral well bores for high geofluid production rates.
2. Shows horizontal injection geofluid well bore to oil reservoir.
3. Shows cold water/geofluid injection ~HDR) well.
4. Shows horizontal production geofluid well bore.
5. Shows oil reservoir.
6. Shows formation above oil reservoir.
7. Shows hot dry rock fractured reservoir.
9. Shows side track laterals.
10. Shows side track radials.
11. Shows horizontal/lateral well bore.
The sr-henl~tic drawing shows figure 13 where a shaft/tunnels are drilled and
horizontal twin wells are drilled with coiled tubing units. The top well bore is for
water/steam geofluid injection, and the lower well bores for oil production, the HDR
production well is placed in the mine shaft floor with vellhead flow lines connected to
the horizontal geofluid injector well bores, and the cold water/geofluid surface injector
is drilled from the surface to the HDR reservoir.
1. Shows surface HDR injector.
~. Shows formation.
3. Shows granite formation.
4. Shows oil reservoir.
5. Shows lateral injector.
6. Shows horizontal producer bores.
7. Shows horizontal injector geofluid bores.
8. Shows radial bores.
9. Shows radial bores.
10. Shows doublet production bores.
11. Shows lateral production bores.
12. Shows ho.i~on~al Droducer bores.
13. Shows horizontal injector geofluid bore.
14. Shows producer wellhead.
15. Shows mine shaft and tunnels.
16. Shows hot dry rock (HDR) reservoir.
21S8~7
WO 94/21889 '9 PCT/Gs94/00515
Figure l shows vertical and extended reach, horizontal large di~met~r bore
holes through three reservoir showing:-
1. Shows vertical well bore.
'. Shows horizontal well bore.
3,4 & 5. Shows oil or gas vertical fractured reservoirs.
6. Shows coiled tubing unit or drilling rig.
7. Shows earth foundation.
8. Shows "J" the well bores.
Figure 2 is "U" type drilling showing:-
1. Shows vertical well bore.
~. Shows vertical well bore (upwards).
3. Shows fractures from the well bore.
4. Shows horizontal well bore.
5. Shows earth foundation.
6. Shows I part in 10,000 granite foundation.
Figure 3 is showing "J" type drilling through two foundation reservoirs
showing:-
1. Shows vertical well bore.
~. Shows horizontal well bore.
3. Shows upwards vertical well bore.
4. Shows reservoir.
5. Shows reservoir.
6. Shows earth foundation.
7. Shows horizontal well bore.
Figure 4 showing multiple horizontal bore holes from the one vertical well bore
showing:-
1. Shows vertical well bore.
2. Shows horizontal well bores.
3. Shows "J" type well bores.
4. Shows horizontal well bores.
5. Shows reservoir.
6. Shows reservoir.
7. Shows earth foundation.
2 ~ 7
WO 94/21889 ~ PCT/GB94/00~15
Figure 5 is "J" type drilling with a horizontal well bore from the "J" loop withvertical or horizontal production wells to the reservoir from the surface, the "J" type
well is drilled vertical into hot dry rock founrl~tiQn of one part 10,000 granite and
fractured then up into the heavy oil reservoir from the horizontal into the vertical and
then horizontally showing:-
1. Shows vertical well bore.
~. Shows horizontal well bore.
3. Shows upward vertical well bore.
1. Shows horizontal from the loop.
5. Shows fractures.
6. Shows granite one part in 10,000 formations.
7. Shows reservoir crude oil.
8. Shows earth foundation.
9. Shows horizontal production.
10. Shows vertical well bore.
11. Shows vertical well bore.
1~. Shows "J" type well bore.
Figure 6 is showing "J" type drilling with multiple vertical "J" type loops fromthe horizontal under the oil reservoir with multiple vertical upward well bores into the
oil reservoir showing:-
1. Shows vertical well bore.
. Shows horizontal well bore.
3. Shows vertical upward "J" loop well bores.
4. Shows oil reservoir.
5. Shows earth foundations.
6. Shows earth foundations.
Figure 7 shows coiled tubing units drilling a vertical highly deviated well thenho.i ~o,-~ally in hot dry rocks then vertically upwards into the oil reservoir then
horizontally from the "J" loop for maximum steam drive in the reservoir. The second
coiled tubing unit is drilling production wells vertical then horizontal in the formation
under the reservoir and vertically upwards into the reservoir then horizontally from the
"J" type loop for maximum production by the use of the drainage system with large
well bores showing:-
1. Shows coiled tubing unit, or drilling rig.
'. Shows formation.
WO 94/21889 3 l 2 1 5 8 ~ ~ 7 PCT/GB94/00515
3. Shows oil reservoir.
. Shows formation.
S. Shows one in 10,000 granite formation.
6. Shows vertical bore.
7. Shows horizontal bore.
8. Shows vertical upward bore.
9. Shows horizontal bore from the "J" type loop.
10. Shows coiled tubing unit.
11. Shows vertical bore.
12. Shows horizontal bore.
13. Shows vertical upward bore.
14. Shows horizontal bore from the "J" type loop.
15. Shows fractures in granite (heat reservoir).
Figure 8 shows a diagrammatic view of the drill, and production of an oil
reservoir and a hot dry rock steam injection method, showing:-
1. Shows coiled tubing unit or drilling rig.
2. Shows formation.
3. Shows formation.
. Shows oil reservoir.
5. Shows granite formation.
6. Shows hydraulic fractures HDR reservoir.
7 Shows cold water injection water well.
8. Shows vertical and horizontal production well.
9. Shows vertical and horizontal production well.
10. Shows cut and milled casing from original bore hole intersecting HDR fracture.
11. Shows horizontal side track from (9).
1~. Shows intersecting bore hole drilled from (9).
13. Shows vertical and "J" type production well bore.
Figure 9 shows a diagrammatic view of drilling and production of an oil
reservoir and hot dry rock steam injection method, showing:-
1. Shows formation.
~. Shows formation.
3. Shows oil reservoir.
. Shows formation.
5. Shows granite formation.
6. Shows HDR hydraulic fractures reservoir.
215~(~37
WO 94/21889 ,2 PCT/GB94/00515
7. Shows cold water injection well.
8. Shows production oil well vertical "S" type.
9. Shows horizontal well bore from (8) "S" type.
10. Shows steam outlet bore to oil reservoir.
I 1. Shows steam outlet horizontal, lateral or vertical "S" type.
1~. Shows steam outlet downward vertical from the ho,i~onL;ll or lateral.
13. Shows plug back or none-return valve or te--lpe-dl-lre recolding equipment.
Figure 10 shows a diag~A,~"..~Iic view ofthe drilling and production of an oil
reservoir and a hot dry rock steam injection method, showing:-
1. Shows drilling rig or coiled tubing unit.
~. Shows formation.
3. Shows oil bearing formation (reservoir).
~}. Shows underlying formation.
5. Shows crystalline granite formation.
6. Shows fractured crystalline reservoir.
7. Shows large bore cold water inlet bore with injector.
S. Shows side track cold water injector bore.
9. Shows injecting steam production bore from HDR reservoir to oil reservoir.
10. Shows horizontal or lateral portion of(9).
1 1. Shows downward vertical or lateral bore of ( 10).
1'. Shows downward vertical or lateral bore side track down from (10).
13. Shows side track from (9) to horizontal and lateral bore to HDR.
14. Shows downward vertical or lateral bore side track down from (13).
15. Shows plug back above formation or to use bore (9) for temperature record;ngorsteam bleed (flash) of line, or production line.
16. Shows drilling rig or coiled tubing unit.
Figure 1 1 shows a diagrammatic view of the drilling and production of an oil
reservoir and a hot dry rock steam injection method, showing:-
1. Shows vertical production bore hole.
',3,4 & 5. Shows horizontal production screens.
6. Shows thermal set packer.
7. Shows special injector screen for steam.
8. Shows production injector base casing outlet.
9. Shows vertical cold water inlet injector casing.
10. Shows lateral inlet injector casing.
WO 94/21889 33 215 ~ ~ 3 7 PCT/GB94/00515
11. Shows oil bearing reservoir.12. Shows fractured hot dry rock reservoir.
13&14. Shows two pairs of lateral and horizontal side track production bore
holes.
15. Shows upper forrnation.
16. Shows crystalline granite formation.
17& 18. Shows well heads for tie-in to the closed loop production and
separation
units.
.~dvantages of the present invention
(1) Allows the use of "J", "S", "U" and horizontal from the "J" loop wells to bedrilled in hydro carbon, geothermal (HDR) type wells.
(2) Allows the use of hot dry rocks (HDR) steam reservoirs to be fractured
offshore for sea water injection and steam production into oil bearing forrnations for
high enh~nced oil recovery (EOR).
(3) Allows light oil. heavy oil, tar sands, oil sands, oil shale to be produced onshore
and offshore, with high pressure steam and other agents form subterranean crystalline
rock formations (granite) that underly oil bearing formations.
(4) Allows the oil to be produced by "J" type drilling in horizontal well bores, that
are drilled through the oil bearing formation then drilled upward into the reservoir with
large or small bore holes to drain the reservoir, an~ horizontal from the "J" loop also.
(5) Allows hot drv rocks (HDR) to be used for oil recovery in any type of
reservoir.
(6) Allows a production method whereby the intersecting bore hole to a hot dry
rock (HDR) reservoir, where the top portion of the well bore is cut away from the
bottom portion by cutting or by milling, and where the top portion is sidetracked into
the horizontal for use as production method in the oil reservoir and the bottom portion
of the bore hole is used as a produced steam injection link into the oil reservoir, the top
portion of the well bore may also if required be plugged back, or used for running,
holding te.,lpe,atllre recording equipment.
(7) Allows the use of coiled tubing drilling for (HDR) hot dry rock geotherrnal
drilling, also in "J", "S" and "U" type drilling in conjunction with oil HDR/EOR oil
production.
(8) Allows production under pressure at the well head by the use of a closed loop
system between the HDR well and oil reservoir.
21~8637
WO 94/21889 34 PCT/GB94/00515
(9) Allows the use of any directional and orientation controlled tools to be used to
drill hot dry rock (HDR) geothermal energy type wells, to be used on conj~n~ion with
enh~n~ed oil recovery methods.
( 10) Allows the use of carbon dioxide Co2 or nitrogen to be used ~injected) with
hot water or steam for thç gas phase in enh~n~ed oil recovery with the ultradeep crude
technology (UCT), hot dry rock (HDR), enh~nced oil recovery (EOR) method, or on
its own.
( I l) Allows the use of HDR steam/hot water to be used for EOR rnethodc when the
geofluid is returned to the surface in conjunction with the drilling of UCT methods.
( 12) Allows the use of horizontals, laterals/doublet~/triplets and radiais to be used
on HDRIEOR/UCT injectors and producers.
( 13) Allows the use of carbon dioxide Co2 to be used in the super critical condition
to stim~ te oil recovery through the use of ~IDR/EOR.
(14) Allows the use of carbon dioxide Co2 to be used in the super critical condition
to clean drilling cuttings at the surface.
(15) Allows the use of water/steam, light fraction hydrocarbons and/or gas, i.e. C2
or N, all in solution at pressure to aid petroleum recovery in light, medillm or heavy
cn~de oils, when used in the hot dry rock (HDR), Pnh~nced oil recovery (EOR)
method, in a closed loop system, to be used underground or at the surface for
reinjection to the reservoir.
( 16) Allows the ultradeep crude technology (UCT) method to be used in large bore
holes. shafts or tunnels with coiled tubing drilling into the reservoir with twin
horizontal bores and radials for maximum oil recovery, with a steam wellhead in the
mine shaft.
( 17) Allows the use of propants in the form of pellets made from ceramics high
temperature elastomer compounds above 350C to keep the HDR reservoir fractures
open.
( 18) Allows the use of HDRJUCT geofluid or hot water/steam to move paraffins
and asph~ltines The heavy hydrocarbons that settle out and clog production
casings/tubings and pipe lines, either by reservoir produced HDR/UCT geQfl~lid, or by
bring the geofluid to the surface for reinjection into the well before or pipelil-e to clear
them.
( 19) Allows the use of produced geofluid (hot H20/steam, light fraction
hydrocarbons and/or gas) to be used to reduce the viscosity of any heavy, mPn'illm or
light oil underground or at the surface.
(20) Allows the use of an expansion chamber (polished bore) receptacle, to receive
super heated hot water through large bore injection casing, to flash to steam by choke
outlet rubes through the base of the receptacle unit.
WO 94/21889 35 2 ~ 3 7 PCT/GBg4l005l5
(21 ) Allows the use of milled tooth drilling bits (PDC) polycrystalline dial"ol~d
compacts inserts and/or diamond inserts type drilling bits (heads) with ultraAligh
pressure flow nozzles/inserts. The ultra/high pressure fluid can be supplied from direct
surface equipment, to the bit down-hole or converted to ultra/high pressure by other
means, in the drilling bit (head) body downhole, to cut the rock/formation prior to the
crushing/cutting action with the drilling head, to be used for enh~nced oil recovery
(EOR) methods in conjunction with hot dry rock (HDR) method ultradeep crude
technology (UCT).
High Flow Rates
Figure 14 showing ideal well injection and production geometry for high
production flow rates with single injector well and twin trilateral production wells.,
allows for high flow rates due to in-situ two-way (sides) growth stress in the HDR
reservoir e.g. 2,000 GPM injector and 2,000 GPM producing through trilateral
production system
1. Shows injection well.
2. Shows production well to surface or downhole packer for reservoir heat input
(geofluid).
3. Show production well to surface or downhole packer for reservoir heat input
(geofluid).
4. Shows oil geofluid production well.
~. Shows oil geofluid production well.
6. Shows trilateral production well geometry.
7. Shows trilateral production well geometry.
8. Shows horizontal production steam/hot water/gas production HDR well
(geofluid).
9. Shows horizontal production steam/hot water/gas production HDR well
(geofluid).
10. Shows oil forrnation.
11. Shows hot dry rock ¢HDR) fractured reservoir.
12. Shows hot dry rocks.
13. Shows overburden formation.
14. Shows ground surface.
Near Critical. Critical and Super-Critical Fluid Recovery Method
Extraction of soluble organic matter from se~iiment~ y rocks by near critical,
critical and super-critical gases including N2 with light fraction hydrocarbons and hot
water/steam.
WO 94/21889 2 15 ~ 6 ~7 36 PCTIGB94/00515
Adding C02 alone to hot water/steam at pressure will substantially improve the
oil (hydrocarbons) recovery rate as the CO2 will dissolve in the oil phase and cause the
oil to swell and lower the gravity with hot water/steam drive, all in a closed loop
injection and production system, to provide added volume for riicpl~cpmpnt of oil from
the hydrocarbon strata.
A small increase in pressure induces a large increase of density, the viscosity of
super-critical fluids is lower than that of liquids, the diffusion coefficient is about one
hundred times greater for super-critical than for liquid.
The telnpelaLllre at which production to the hot dly rocks for injection in to the
hydrocarbon reservoir is important, at low pressure the fluid has properties of a gas
which means that for an increase or temperature the solubility decreases at highpressure, the fluid has properties of a liquid and an increase of temperature results in
an increase of solubility, hot water/steam, light fraction hydrocarbons and near critical
carbon dioxide CO ~ all in a gaseous slurry will provide an ideal enh~nced oil recovery
(EOR) sweep fluid for a pressurised closed loop production system (UCT-EOR-
HDR).
215~37
wo 94/21889 37 pcTlGss4loo5ls
Adiustable reamer/st:lbiliser
One aspect of the present invention provides an ~djuct~hle reamer/stabiliser tool. This
tool is a valuable aid in the drilling of multidirection~l wells, such as those required to
implement the first part of the invention. Reamers and stabilisers are convPntion~l
drilling tools but the tools according to this aspect of the present invention are
struct~lrally distinct and advantageous compared with the known tools.
One distinctive feature of the reamer/stabiliser of the present invention is that it is
adjustable. That is, the radial extent of the tool is capable of fine ~ljuctment - to suit
the particular diameter of the well bore at any particular location. Such a feature is
extremely advantageous when one wishes to drill multidirectional wells.
The reamer/stabiliser is referred to as such since it can be used either as a rearner or as
a stabiliser, according to the operative blades selected for fitting to the body of the
tool. An embodiment of the tool is shown in figure 16. A cross-sectional view, taken
across the diameter of the tool and showing the tool body and operative blades, is
shown in figure 20. Figures l 7, 18 and l 9 show variations of the operative blades
which can be fitted to the body ofthe tool. The operative blades shown in figures 16
and 20 are stabiliser blades whereas those shown in figures l 7, 18 and l 9 are reamer
blades. The tool is inserted at the required location in the down hole well string.
With reference to figure 16, the tool body l is coMected to the drill string at one end
by the pin connection 35 and at the other end by a box connection 36. Box conl~eclion
36 is provided in an end locator sub-assembly 2 ~tt~ched to the tool body 1. Theoperative blades 13 are carried by the main tool body and are, of course, arranged for
radial movement with respect to the tool body. As shown, the blades have a generally
trapezium shaped cross section with the shorter of the parallel sides being inner most.
The inclined edges/surfaces rest on respective angle blocks 11,12. As indicated in
figure 20, four blades are located around the circull~lence of the tool and each is
seated in a respective guide slot 46.
.
Each blade guide slot has a fixed angle block 12 a~ the end ofthe slot adjacPrlt the pin
connector 35 and a moveable, or thrust, angle block l l at the other end of the slot.
The angle blocks each have an inrlined surface, on which the respective inclinedsurfaces of the blade l 3 rest. The trust angle block is capable of movement in the slot
in the longitu~lin~l direction of the tool body. It will be readily appreciated that such
Wo 94/21889 ?~ ~- 5 ~ ~ 3 ~ 38 PCT/GB94/0051~; --
movement changes the ~ict~nce between the angle blocks 11 and 12 and thus causesthe inrlinPd surfaces of the blade 13 to slide over the inclined surfaces of the angle
blocks. This has the result of moving the blades radially with respect to the tool body.
The blades are retained in the tool body by means of pivotal links 15 by wnich they are
~.tt~ched to the angle blocks.
.
Movement of the thrust angle blocks, and thus movement of the blades, is achieved by
respective tel~metry control units, eg 62. Each tcl~ control unit cor~l~.ises a
piston 17 connected to the respective thrust angle block by a connecting rod 22. A
return spring 29 acts to retum the angle block to the position in which the respecLi~e
blade is fully retracted. Movement of the piston 17, and hence block 11 and blade 13,
is controlled by an operator above ground by means of telemetlv.
In the illustrated embodiment, movement of piston 17 is achieved in the following
manner. Acting on the face of the piston 17 is a toggle rod ''3 . The toggle rod 23 is
coupled to a tooth shaped latch 24, which interacts with two latch flats 26 and 27
which are of different longitudinal extent. The flats abut a fluid pressure piston 28.
Piston 28 moves under pressure of fluid in chamber 7 and control of component 8.Component 8 is a conventional unit which is operated by pressure pulses induced in
the hydraulic fluid contained in the central bore of the drill string/tool body. The
pressure pulse is electronically analysed and inlet/outlet valves to chamber 7 ~ct..~ted
in accordance with predetermined pulse formats. The pressure pulses are
controlled/initi~ted above ground to control operation of the tool downhole.
A device is provided within the tool in order to indicate the state of expansion or
contraction (radial position) of the blades to an operator above ground. This device
comprises a venturi flow dart 3 7. Movement of the thrust angle blocks affect flow
past the dart and the change in flow rate is detect~ble above ground.
The adjustable rotary reamer/stabiliser is an ideal tool to be used in all types of
multi-directional drilling operations, the assembly uses adjustable integral blades either
straight or helix with barrel roller cutters or balls to reduce friction and drag down-
hole from the ~ccl-mul~tor unit fitted to the top end of the reamer/stabiliser body.
The system is controlled from the surface by hydraulic pressure which actu~tes
the telemetry unit controllers (TUC's) fitted into the side pockets of the body, either
three or four, subject to the configuration of the blades, which is controlled by
hydraulic pressure supplied by the ace--m--l~tor, when the drilling assembly is picked
up from the bottom of the well allowing the weight of the assembly to activate the
WO 94/21889 39 21. 5 ~ ~ 3 7 PCT/GB94/00515
downward force of the accum~ tor, to exert differential pressure across the faces of
the three or four pistons, allowing the pistons to travel forward to activate the toggle
and latch system within the telemetry unit controllers unit (TUC's).
With the toggle and latch in the back position the reamer/stabiiiser blades are in
the minimum gauge position, and when the toggle and latch are in the forward position
the reamer/stabiliser blades are in the full gauge position.
The action of the thrust piston travelling forward by the di~re,lLial pressure
across the tool allows the drive angle block to travel forward, pushing the angle faces
of the helix type, or straight blade, against the angled face of the fixed forward block,
allowing the blade to travel outwards in a controlled manner by the two co~ ec,~ g
roller links which are held in place by the roller pins. When pressure is exerted on to
the fluid pressure piston next time, the toggle and latch is released into the second
position, this allows the spring pressure on the back seat of the thrust piston to pull the
blade back into the closed position in a reverse blade action. The appro~",ate time to
operate the valve in the forward or closed position is the velocity of pressure
tran~mic~ion and can be considered i~ct~nt~neous in the order of 1470 metres/second
or 4850 feet/second when using typical hydraulic oil. The use of drilling fluid would
slightly increase this time. Using either fluid, opening and closing of the valve will be
very fast.
The advantage of this type of actuation is that it is operated from the .-.;.. ;.. ~
gauge to the maximum gauge position by the method known as the hydraulic toggle
and latch, operated by the weight set acc~lm~ tQr by over pull on the drill string, this is
particularly useful in high torque situations. The other advantage of this type of tool is
that it can be used as a near bit or string type of reamer/stabiliser. It is also important
for the driller on the rig floor to know when the tool has been activated, this is done by
a flow in~lic~tor dart fixed to the internal venturi sleeve, fixed inside the venturi sleeve
is a sliding venturi piston with seals, either three or four ret~ining pin locators
depending on the number of blades used within the body of the reamer/stabiliser, the
r~ g pins are then secured into the body of the thrust angle block allowing the
sliding venturi piston to travel forward with the thrust angle block by three or four
oblong slide portscut through the body of the stabiliser and the internal venturi sleeve
allowing for the locator pins to travel back and forth by the movement of the thrust
angle block and the sliding venturi piston and allowing restricted flow through the
venturi piston by the flow indicator dart.
In the activated locked position, ie maximum gauge, the flow inr~ic~tor dart ~,vill
restrict the flow through the sliding venturi piston that will be in the fol ~a,d position,
this will give a 200psi flow restriction when the tool is in the full gauge locked position
and the head of the flow indicator dart is inside the venturi piston and there will be a
215~3~
WO 94/21889 40 PCT/GB94/00515
corresponding 200psi pressure drop on the drillers surface pressure gauge, in~ir~ting
to the driller which position the tool is in, ie. minimllm or maximum gauge of the
reamer/stabiliser.
The body of the reamer/stabiliser is grooved either in the straight configuration
for straight blades or spiral grooved fro the helix shaped blade. The blades are shaped
to the ~ meter of the body in a convex outer shape and a concave lower shape with
parallel sides.
The blade openings in the reamer/st~bili~er body are milled out, either three orfour depending on configuration, to allow a good fit of the reamer/st~bilispr blade with
the two angled blocks. The two end faces of the reamer/st~bili~er are m~hin~ to
matching angles to correspond with the thrust angle blocks. In the box end of the main
reamer/stabiliser body three or four cylinder ret~ining ports are drilled to house the
above mentioned telemetry unit controllers in the body housing toggle and latch, these
are retained in position by three or four end blanking plugs. Full circu.l~rence flow
ports are m~chin~d into the main reamer/stabiliser body to allow full flow differential
pressure across the three or four piston faces.
The bore of the main reamer/stabiliser body is bored out to a pre-set depth
larger than the main bore to accommodate the main internal venturi sleeve that houses
the flow indicator dart and venturi piston. This is secured in position by an end sub
with a box connection at one end and a pin connection at the other which fits into the
main reamer/stabiliser body. The other end of the reamer/stabiliser body can be either
a pin or box connection by is shown in the drawing as a pin connection. The end sub
also overlaps the end retaining seal plugs securing the telemetry unit controller in
place, this safeguards against the loss of any components down-hole.
The reamertstabiliser blades are held in position within the angle blocks by twoball type forged links and held in place in the angle blocks and blade by four roller pins,
completely secured within the reamer/stabiliser body with no possibility of losing any
components down-hole.
The thrust piston within the telemetry unit controller is threaded into the thrust
angle block securing it within the main reamer/stabiliser body. The fixed angle block is
held in place by round locator pins fitted to the underside of the angle block. The
bottom ends of the pins are milled halfway across their rii~meter. They are then fitted
through pre-drilled holes in the bottom of the blade recess through the main
reamer/stabiliser body into the main bore, this allows the internal venturi sleeve to
locate itself into the half round milled out windows locking the fixed angle blocks into
position. This then allows forward motion when the valve is activated pushing the
thrust piston, whereby the thrust angle block travels forward opening the blades from
minimllm gauge position to maximum gauge position, travel ofthe blades for
WO 94/21889 ~ l 2 ~ 5 8 6 ~ 7 PCT/GB94/0051~
maximum gauge, ie. increasing diameter, is controlled by the allowance given to the
forged links within the angle blocks and main body.
The adjacent faces of the two angle blocks and blade are self ~ -ct~ble to the
wear occurring within the connecting roller links and the inner link housing of the two
blocks and blade. The pattern of the reamer/stabiliser blades can be either or angled
roller type reamer cutters or spherical balls ~nc~rslll~t~d within a housing and secured
within boreholes in the reamer/stabiliser blade or, ideally, angled cross type barrel
roller cutters of various types that are secured within milled out hollcing~ within the
reamer/stabiliser blade by roller bearing pins fitted through the sides of the
reamer/stabiliser blade. The total ~c~çmhly is çn~pslll~ted within the blade by the
main reamer/stabiliser body. This total design allows for no component part to work
loose through vibration, therefore no component part can be lost in the hole.
This adjustable angle rotary roller reamer/stabiliser allows true vertical, lateral
and horizontal drilling control, free from excessive torque and drag experienced in
highly deviated lateral and hori~ontal wells.
It should also be noted that either one ore two reamer/stabilisers can be used
eccentrically when employed with drilling mud motors for fine tuning the directional
control by use of the predetermined settings of the return springs of the hydraulic latch
valves, allowing for one blade to remain in the closed position while the other two are
open, this allows the stabiliser to lay within the well bore eccenl,ically north facing
while the other stabiliser lies within the well bore eccentrically south facing, ie. one up
one down. This allows the down-hole adjustable stabilisers to be free from torque and
drag in this mode. The roller action and honing of the well bore allows the drill string
to be pushed with ease with weight on the bit, allowing for faster rates of penc~l ~Lion.
The new concept of the adjustable rotary roller reamer/stabiliser which can be
activated and de-activated down-hole by a simple pressure change through the
telemetry unit controller, will change the face of directional drilling techniques. In the
past, the dri!ler would have to pull out of the hole (trip) to change the stabilisers gauge
or to ream the hole. The use of a single adjustable stabiliser might provide a semi-
steerable system. The present invention allows for the use of two making it a fully
steerable system by altering the gauge between the two positions and will be able to
simplify, and easily follow the planned curvature of the well path, giving very accurate
trajectory control.
The configuration of the adjustable angle rotary roller reamer/stabiliser in itsvarious forms can be substituted with other types of blades as shown in figures 17, 18
and 19.
It has long been recognised in the drilling industry that angle type rotary
e~llc~ are ideal for full gauge hole reaming and drill stabilisation, and is ideal for
21~8637
WO 94/21889 42 PCT/Gs94/00515
directional drilling control, but the conventional reams (which have on many occasions
fallen apart down-hole) this together with the enormous cost of fishing for broken
parts left down-hole. Repair and re-dressing of stabilisers, real.le,~. etc. make this
invention highly desirable for all types of drilling control in high extended reach lateral
and horizontal wells, and in particular with the new laws of the non-use of oil base
muds, when water base muds are used this re~duces the torque and drag on the drilling
assembly.
This invention has been developed as a near bit integral and string a~ -stable
bladed rotational angle roller reamer/stabiliser and will radically change the current
stabiliser market. This is due to the wall contact and full roller driving action of the
bottom barrel roller that stops the old slide drilling action of the bottom hole assembly.
Due to the unique method of continual rolling of the reamer/stabiliser down-hole,
allowing the drill bit to have a continual cutting action in the well bore face, cutting out
bit walk, and making hole much faster than the old slide method. By altering thegauge of the reamer/stabiliser it is possible to make the hole build hold or drop angle,
as required, the basis of the reamer/stabiliser tool allows the angle barrel rollers, 15 or
20 of them, giving full gauge stabilisation, correct positioning of the drill string in the
well bore which is rotating on barrel rollers, with full width or bore roller movement,
allowing the tool to roll down the well bore ~olimin~ting torque and drag, ~nh~nces
stabilisation, stopping side forces on the drill bit and thereby cutting out bit walk by
rolling across the full face of the wall rather than climb up the side (unlike normal
reamer/stabiliser) allowing increased ability for bits to drill in the direction that they are
aimed. The di,.meter of the reamer/stabiliser is remotely controlled from the surface on
the rig floor, by lifting the drilling assembly from the bottom hole position allowing the
~ccum~ tor to activate the telemetry unit controllers (TUC's)
Figure l 6 shows a radial cross-section of an adjustable rotary reamer/stabiliser.
l. The main reamer/stabiliser body.
2. Shows end locator sub.
3. Shows internal venturi sleeve
4. Shows venturi sleeve seal top.
5. Shows venturi sleeve seal bottom.
6. Shows sliding venturi piston.
7. Shows fluid chamber.
8. Shows piston acc~mul~tor lift sub.
9. Shows acc~mul~tor flow ports.
lO. Shows slide pins.
l l. Shows thrust angle block
12. Shows fixed angle block.
~ WO 94/21889 43 2 1 5 8 ~ 3 7 PCT/GBg4f-rOSl5
13. Shows reamer blades.
14. Shows milled window retainer angle block pins.
15. Shows forged links.
16. Shows bearing pins
17. Shows valve assembly.
18. Shows valve ret~ining plug and piston stop.
19. Shows valve chamber.
20. Shows full flow differential port.
21. Shows internal venturi sleeve ports.
2''. Shows thrust piston.
23. Shows ball toggle rod.
24. Shows tooth shaped latch.
25. Shows valve body cylinder.
26. Shows top flat on valve cylinder.
27. Shows bottom flat on valve cylinder.
28. Shows fluid pressure piston.
29. Shows pressure spring.
30. Shows li~ sub. key anti-rotation.
31. Shows piston seals.
32. Shows housing for reamer/stabiliser blades.
33. Shows bore holes for 14.
34. Shows threaded connection on thrust piston to thrust angle block.
35. Shows pin connection.
36. Shows box connection.
37. Shows flow ports in flow indicator darts.
38. Shows box connection.
39. Shows key way main body.
40. Shows opposing angle faces.
41. Shows bearing link housing.
42. Shows spiral flow cut.
43. Shows seals/sub to piston lift sub.
44. Shows equalising port.
45. Shows bore.
46. Shows reamer blade housing.
47. Shows restricted flow in full gauge position.
48. Shows elongated guide hole for ecc~ ,ic blades (if required).
Figure 17 shows a radial cross-section of an adjustable reamer/stabiliser blade with
spherical cutter balls.
wo 94/21889 ~ ~ 5 $ ~ 3 ~ 44 PCT/GB94/00515
~9. Shows blade body.
50. Shows seal cups.
51. Shows locking pins.
52. Shows spherical balls.
Figure 18 shows a radial cross-section of a reamer/stabiliser blade with cross cutting
barrel rollers.
53. Shows blade body:
54. Shows vertical rollers.
55. Shows guide rod.
56. Shows bushings or bearings.
Figure 19 shows a radial cross-section of a reamer/stabiliser blade with vertical cutter
rollers.
57. Shows blade body.
58. Shows barrel rollers.
59. Shows guide pins.
60. Shows bushings or bearings.
Figure 20 shows an axial cross-section of a reamer/stabliser body.
61. Shows stabiliser body
62. Shows differential flow ports and TCU.
63. Shows full return flow grooves.
64. Shows blade body.
65. Shows full flow bore.
66. Shows reamer/stabiliser body.
WO 94121889 45 215 ~ ~ 3 7 PCTIGB94100515
Trust calliPer~7
Another aspect of the present invention provides a thrust calliper tool This tool is a
valuable aid in the drilling of multidirectional wells, such as those required to
implement the first part of the invention. An embodiment of the tool is shown in figure
T 2 1 .
With reference to figure 21, the tool body 41 is con~f,.iled to the drill string at one end
by the pin connection 31 and at the other end by a box conl-e~,~ ;on 34. Bore gripper
blades 24 are carried by the main tool body and are, of course, arranged for radial
movement with respect to the tool body. As shown, the blades have a generally
trapezium shaped cross section with the shorter of the parallel sides being inner most.
The inclined edges/surfaces rest on respective angle blocks 23,29. As indicated in
figure 22, four blades are located around the circumference of the tool and each is
seated in a respective guide slot 25.
Each blade guide slot has a fixed angle block 29 at the end of the slot ~dj~cent the pin
connector 31 and a moveable, or thrust, angle block 23 at the other end of the slot.
The angle blocks each have an inclined surface, on which the respe.;li~re in~iined
surfaces of the blade ~4 rest. The trust angle block is capable of movement in the slot
in the lon~it~l~lin~l direction of the tool body. It will be readily appreciated that such
movement changes the distance between the angle blocks 23 and 29 and thus causesthe inclinPd surfaces of the blade 24 to slide over the inclined surfaces of the angle
blocks. This has the result of moving the blades radially with respect to the tool body.
The blades are retained in the tool body by means of pivotal links 26 by which they are
~tt~rhe(l to the angle blocks.
Movement of the thrust angle blocks, and thus movement of the blades, is achieved by
respective telemetry control units, eg 2. Each t~l~metry control unit comprises a
piston 18 conntocted to the respective thrust angle block by a connec~ rod. A return
spring 19 acts to return the angle block to the position in which the respective blade is
fully retracted. Movement of the piston 18, and hence block 23 and blade 24, is
controlled by an operator above ground by means of telem~try.
The thrust calliper, as its name implies, provides thrust as well as calliper action. Thus,
with the calliper blades gripping the well bore, the central portion of the tool can be
thrust forward so as to exert forward thrust on a drill bit ~tt~ched to the tool via pin
WO 94/21889 2 1~ 8 ~ ~ 7 46 PCTIGB94/00515
connector 31. The mech~nicm for achieving this thrust is located longih~ n~lly behind
the gripper blades 24 (to the left in figure 21) and is shown in more detail in figure 2S.
Figure 25 also shows the detail of the telemetry control units used to control the
movement of the calliper gripper blades 24.
With reference to figure 25, the mecl~ni~m for controlling movement of the calliper
gripper blades is essenti~lly shown in the upper half of the figure and the Illeçl~A
for forward thrust of the tool is ess~n:ti~lly shown in the lower half of the figure.
However, it will be apparent from the figure that the two mPçh~nicm~ are
interconn~cted such that forward thrust occurs when the gripper blades are e~ctende~
gripping the bore, when forward thrust occurs and that the blades are released after
forward thrust has occurred. Typically two of the thrust calliper tools will be used
together in a drill string. Thus, one tool grips the bore and thrusts the entire drill string
forward. Subsequently the second tool grips the bore and thrusts the entire drill string
forward. The first tool is now in position again to grip the bore and thrust forward,
and so the sequence is repeated. A third thrust calliper tool may also be used in the
drill string. For example, the calliper blades of the third tool can be used to grip the
inner cylindrical surface of a bore liner. Thus, the tool can be used to pull a liner along
the bore behind the drill bit.
Forward thrust is achieved by fluid pressure in ch~mbPr 40. As the tool moves
forward, actuator 61 moves to the end of its travel within its chamber and further
forward movement of the tool causes cam piston 64 to move radially inwards towards
the central longitudinal axis of the tool. This movement of the cam piston operates
control units 1 and 2. These control units have a toggle and latch ~ n;~ and
control the flow of hydraulic fluid into chambers 40 and 33 respectively.
The two control units 50 and 53 which control movement of the calliper gripper blades
are of ecsenti~lly the same design as control units 1 and 2. The detail of one of these
control units is shown in figure '76.
Hydraulic fluid within the drill string is used to operate the various meçh~ ...c A~er
use the fluid is dumped to the annulus between the drill string and the well bore.
The caliper thrust units hereafter t:fe, . ed to as CTU's con~ s of a caliper body
employing the same trust angle blocks and fixed angle blocks together with centre
angle blades as described in relation to the adjustable rotary roller reamer/stabiliser.
~ WO 94/21889 47 215 ~ ~ ~ 7 PCT/GB94/00515
The caliper system consists of the main caliper body with either three (3) or
four (4) oblong caliper housings m~ehined into the caliper body, fitted into each caliper
housing are the two (2) thrust angle blocks and fixed angle blocks together with the
caliper blade well bore gripper seg~ tc, these are activated by a caliper thrust piston
which is controlled by hydraulic pressure feed from the rear thrust collar valve control
sub which is controlled by the forward thrust and return valve system within the centre
valve ~cc~mbly, this caliper thrust unit ~c.cemhly cimlllt~neol-cly applies fo,w~d thrust
to the hydraulic drill collar thrust piston eAe~lulg a fo,w~l motion on to three (3) or
four (4) control pistons on the thrust angle caliper blocks which in turn forces out the
caliper blades locking them into the well bore, and the return action of the caliper blade
is again siml~lt~neous, when no. one (1) telel"~,l.y unit controller opens and no. three
(3) telemet~y unit controller closes the no. four (4) tcl~...el.y unit controller opens and
the no. two (2) telemetry unit controller closes, these valves are sequenced by the cams
and e~m.ch~.c at the end of each thrust and return travel of the hydraulic drill collar
(piston), this then equates to the caliper segments locked into the well bore and the
caliper thrust units travelling forward, adding weight to the forward drilling assembly
and drill bit, sim~llt~neously behind the front caliper the rear caliper p~ UIIIIS the
closing and retracting sequence whereby valve no. seven (7) is open, valve no. five (~)
is closed, valve no. six (6) is open and valve no. eight (8) is closed, this allows fluid
pressure to be exerted on to the centre valve assembly (CTU) forcing the caliper body,
which is now in the closed position, by the opening of valve no. six (6) allowing the
return spring to retract the caliper blades from the locked to the retracted position, this
places the back caliper assembly of the (CTU) in the return position ready for the next
drilling thrust caliper sequence, this is a continual opening and closing movement of
the telemetry unit controller and a thrusting and retracting of the (CTU) by thesequen~ing of the telen~etry unit controller, as described more fully in relation to the
adjustable reamer/stabiliser, whereby valves 1, 5, 4 and 8 will always be in one position
and valves 2, 3, 6 and 7 will be in the opposite position by a pre-dete~,l,hled change in
flow pressure, eg. 400 psi above drilling pressure, the pressure pulse then operates the
toggle/latch assembly on no's nine (9) and ten (10) tele,,l~,l,y unit controllers, then
sh~ttin~ down the pumps to close both front and rear calipers (CTU) for ~ ping the
drilling assembly out or into the well. The length of stroke of the (CTIJ) will be
recorded on the measurement while drilling system (MW~), the h~. .nalion is fed to a
computer when the maximum travel is obtained by the (CTU) rccordi.,g coînp'eta
depth record. The cams and c~mch~ allows the valve sequences to be c~ ged one
set of calipers is retracted while the other set is locked to the well bore and
sim..lt~neo~.sly the (CTU) is thrust forward from the locked calipers adding weignt to
the drilling assembly and drill bit, while the other set of calipers is retracting.
WO 94/21889 ~ ~,5 8 6 3 7 48 PCT/GB94/00515
The operational principle of the tool is by dirrere.~lial pressure across the tool,
when each pair of valves are open to allow di~re.,lial pressure into one side of the
main valve body cylinder.
The tel~metry unit controllers as used in the adj~lct~lF rotary roller
reamer/stabiliser and thrust, caliper units can also be used as a dump valve system as
shown, which are activated at a pre-dete,llunet spring pressure set above the spring
pressure of the other tcle.llctly unit controllers, both of the dump valves will operate as
a pair, either both in the closed position, allowing drilling fluid to leave c~ ..l.e~ and
feed port, which fees the chamber allowing the piston to return to the unlocked
position, allowing the calipers to be retracted, this sequence is cim~ n.oollc on both
front and rear calipers to allow 1, ipp;"g in and out of the well. To allow the calipers to
continually thrust forward, adding weight to the drill bit, at the end of the hydraulic
drill collar travel, allowing the caliper to return to the start position ready for the next
thrust operation, this can be achieved by hydro ...ecl-~nical achl~tinn on the first and
second caliper, whereby one caliper is locked into the well bore by the a~.~tion ofthe
angle blocks exerting pressure the gripper inserts which are forced out under pre..~.ule
locking the caliper to the well bore. Hydraulic pressure is applied to the rear çh~mber
applying force to the centre valve body which is an integral part of the hydraulic drill
collar, thrusting forward and adding weight to the drill bit, when it reaches the end of
its travel within the chamber it strikes the cam striker face on the c~...~l.,~ n end. To
operate the twin caliper drilling system for running the caliper in the well bore, start the
mud pumps and apply the pre-determined drilling fluid pressure, above the normaldrilling pressure, for a set amount of time, then pull back on the pressure to lock the
two telemetry unit controller dump valves (figure 25 items 50 and 53) open, ie.
telemetry unit controller valve (figure 25) open position in hydraulic drill collar (fig,ure
25 item 53) in cylinder body allowing fluid pressure through ports (figure 25 items 13
and 15) to operate the second dump valve (figure 25 item 53) in the open position in
the hydraulic caliper body allowing fluid to leave through port (16) so that the two
calipers are in the closed position. To start drilling increase pump pressure to pre-
determined telemetry unit controller dump valve rate for the present number of
seconds and then pull back on pump pressure to normal drilling fluid pressure, this will
close the two (2) dump valves (figure 25 items 50 and 53) as shown allowing
cim~llt~neously for drilling fluid to enter through inlet flow port (figure 25 item 9) with
the valve (1) in the open position, this allows fluid to enter char"ber, siml~lt~neously
entering the caliper segment flow ports ( 17) to thrust the caliper seg...~ outward,
either 3 or 4 ceg.. 1l~ depending on the amount used and the l~rl,s ,ule thrust pistons
(figure 25 item 19=8) locking the caliper sec~ nl i to the well bore holding the caliper
body secure within the well bore, at the same time as this is happeni"g the spool valve
~ WO 94/21889 49 21 S 8 S 3 7 PCT/GB94100s1s
(figure 25 item 69) in the front chamber is closing, item 3 to stop fluid entering the
chamber item ~0, valve item 1 is opening to allow fluid to enter chamber item 40 to
allow the hydraulic drill collar (piston) item 30 to thrust forward through the loc~ced
caliper, the four hydro mech~nic~l spool and tplpm~try unit controllers are all
5imult~neously operated with the internal cylinder operating mech~nicm by the spool
valve piston item 69 and c~m.ch~Pt item 61 reliefports and return side spool valves, the
spool valve item 4 is open to allow fluid out of charnber item 33 and the tPlemet~y unit
controller item 2 is closed to stop fluid entering chamber item 33 when the hydraulic
drill collar piston item 30 reaches the end of its travel in the caliper body chamber item
33, the spool control valve item 69 is activated in the forward position and opens
exhaust spool valve item 3 to allow fluid to leave exhaust port item 12 and close port
item 1 1 simultaneously operating the camshaft and striker piston item 61 to activate
the cam item 64 to open the telemetry unit.controller item 2 to allow fluid to enter
chamber item 33 and close the telemetry unit controller item 1 to stop fluid entering
chamber item 40 to return the hydraulic drill collar back to the start thrust position
with the calipers in the closed position, when one caliper is in the operating thrust
mode, the other one is in the reverse order returning back along the hydraulic drill
collar as the forward drilling assembly is thrusting forward adding weight to the drilling
assembly and drill bit.
Use of the twin caliper eccentric system with eccentric stabilisers will allow the
measurement while drilling system (MWD) to be placed as close as possible to the drill
bit allowing complete trajectory control when used in the ecce.-L~ic blade setting, it
allows complete directional control with the use of two (2) adjustable rearner/stabiliser,
one near bit and the other first string.
Depending on how the telemetry unit controllers (TUC's) valves are sequenced
before running in to the well. The pair of reamer/stabiliser can be full gauge together
or under-gauge or one under-gauge and the other full gauge, allowing full directional
control, for coiled tubing or conventional drill string drilling. It is also possible to set
the blades iri the reamerlstabiliser in the eccentric positions within the tool body of the
rear one and orientation of this is performed from the rig floor allowing ideal curvature
in directional control when used with mud motors, this can be used with twin calipers
to hold eccentricity of the caliper that is returning back to the start position, this
method is ideal for complete controlled trajectory drilling giving a much smoother
(low-micro) dog-leg well bore precisely along a planned 3D path, red-lcing torque and
drag allowing extra long extended reach drilling, and re~ucing drilling and well costs
dr~m~tic~lly. The twin caliper system fitted to either rotary drill pipe or coiled tubing
allows thrust to the drilling assembly, the trajectory control unit for bit angle face and
orientation unit may also be used if required, the adjustable rotary roller
WO 94/21889 215 ~ 6 3 7 50 PCT/GB94/00515
reamer/stabiliser gives a cutting and rolling action in the well bore reducing torque and
drag and stopping slide drilling the complete system is operated on di~r~
hydraulic pressure with all adjustmentc to the drilling assembly being pc;~ru~l--ed down-
hole purely by an increase in pressure by weight set control from the rig floor by the
weight set accnmnl~tor fitted above the rearner/st~bili~e~ and the llajC~,Lol~ control unit
with orientation unit, by an incrèase in drilling pressure, the caliper system is working
fully autom~iç~lly with normal drilling pressure and can only be stopped by the
increase of a pre-determined pressure to allow the four (4) t~lP ~el~ y unit controller
dump valves to open, allowing tripping in and out of the well bore with the drill string.
The drilling assembly continues closed and mud pressure .,.~ Pd the drilling
assembly continues drilling and thrusting, making hole again, with the four (4)
telemetry unit controller valves fitted in the thrust caliper valve block assembly on each
caliper.
A pair of thrust caliper units can also be fitted to the end of coiled tubing with
drill pipe fitted to the thrust side between the drilling motor and trajectory control unit
(TCU).
To adjust the rotary roller reamer/stabiliser just lift the drilling assembly tooperate the four (4) telemetry unit controller valves in the valve body of the ~ t~ble
rotary roller reamer/stabiliser, again to release. Pressure increases apply to the
operation of the trajectory control unit by the tel~mPtry unit controller valves fitted
into the body of the trajectory control unit and orientation unit, operation depen~ on
the depth but from a 10,000 ft well time is app.o~-n.alely 2.4 seconds, each set of
valves requite separate operation with different pre-determined pressures set above
normal drilling pressure.
Figure 21 shows a radial cross-section of a caliper thrust unit showing:-
1. Shows front caliper inlet piston telemetry unit controller thrust.
2. Shows front caliper inlet piston telemetry unit controller return.
3. Shows front caliper outlet valve control spool thrust.
4. Shows front caliper outlet valve control spool return.
5. Shows rear caliper inlet piston tel,o~etry unit controller thrust (notshown on drawing, reference only).
6. Shows rear caliper inlet piston telemetry unit controller return (not
shown on drawing, reference only).
7. Shows rear caliper outlet valve control spool thrust (not shown on
drawing, reference only).
8. Shows rear caliper outlet valve control spool return (not shown on
drawing, reference only).
9. Shows thrust inlet port.
~ WO 94/21889 51 2 1 5 8 S 3 7 PCT/GB94/00515
10. Shows return inlet port.
11. Shows outlet port return.
12. Shows outlet port thrust.
13. Shows valve operating ports to the TUC dump valve piston assembly.
14. Shows valve operating ports to the TUC dump valve cylinder assembly.
15. Shows valve flow ports to the TUC dump valve piston.
16. Shows valve flow ports to the TUC dump valve cylinder.
17. Shows flow port to caliper thrust piston.
18. Shows caliper thrust piston.
19. Shows caliper piston return spring.
20. Shows fluid chamber return side.
21. Shows seals hydraulic drill collar to cylinder body.
22. Shows end plugs.
23. Shows angle thrust caliper block.
24. Shows caliper blade.
25. Shows caliper housing.
26. Shows forged caliper links.
27. Shows bearing link pins.
28. Shows forged link housing.
29. Shows fixed angle caliper block.
30. Shows hydraulic drill collar (piston) and valve assembly.
31. Shows pin connection.
32. Shows caliper body hydraulic drill collar bore.
33. Shows caliper body cylinder return dump valve port (hydraulic drill
collar).
34. Shows box connection.
35. Shows telemetry unit controller bore.
36. Shows caliper body control sub (cylinder).
37. Shows centre valve assembly of hydraulic drill collar (piston).
38. Shows back caliper body valve sub.
39. Shows pin and box connection caliper body.
40. Shows fluid chamber thrust side.
41. Shows caliper body.
42. Shows seals cylinder for spool valve.
43. Shows valve hydraulic thrust (piston) cylinder.
44. Shows angle block lock pins.
45. Shows hydraulic drill collar torque rod and spool valve.
46. Shows seals cam shaft.
Wo 94/21889 2 1 ~ ~ ~ 3 7 52 PCT/GB94/00515
47. Shows seals in cylinder body.
48. Shows seals hydraulic drill collar piston assembly.
49. Shows seals spool valve piston.
50. Shows outer dump valve (valve body).
51. Shows thread o~ piston hydraulic drill collar.
52. Shows slide pàds and seals.
53. Shows inner dump valve (cylinder casing.)
54. Shows flow pathways.
55. Shows cam/piston valve.
56. Shows cam/piston valve.
57. Shows bore of hydraulic drill collar.
58. Shows thread for striker piston cylinder.
59. Shows cam shaft cylinder body (striker) (rear).
60. Shows cam shaft cylinder body (striker) (front).
61. Shows cam shaft valve body and striker piston.
62. Shows actuator cam cylinder (rear).
63. Shows actuator cam cylinder (front).
64. Shows actuator cam piston.
65. Shows camshaft striker piston cylinder.
66. Shows spool control valve connection.
67. Shows spool valve locator.
68. Shows stirker plates valve control spool.
69. Shows spool valve piston.
70. Shows thread on thrust rod.
Figure 22 is an axial cross-section of the caliper thrust unit showing:-
1. Shows thrust caliper body.
2. Shows thrust pistons (four).
3. Shows hydraulic drill collar.
4. Shows hydraulic drill collar bore.
5. Shows inside diameter (I/D) of well bore.
6. Shows fluid pathways.
7. Shows caliper gripper segmPnt~ (blades).
8. Shows blades closed.
Figure 23 is an axial cross-section of the caliper thrust unit caliper body and
hydraulic drill collar piston valve block assembly showing:-
1. Shows caliper body.
2. Shows hydraulic drill collar piston valve block assembly.
3. Shows telemetry unit controller s(two).
~ WO 94/21889 53 215 ~ ~ 3 7 PCT/GB94/00515
4. Shows flow ports to caliper pistons.
5. Shows torque rod and spool valve.
6. Shows dump valve.
7. Shows inner cam shaft.
8. Shows bore of hydraulic drill collar.
9. Shows hydraulic drill collar.
Figure 24 is a radial cross-section of a caliper thrust unit piston showing:-
18. Shows caliper thrust piston and seals.
19. Shows caliper piston return spring.
22. Shows end plug and piston stop.
43. Shows valve cylinder body.
53. Shows retaining thread to angle thrust block.
54. Shows fluid chamber.
S6. Shows piston seals.
Figure 25 is a radial cross-section of the hydraulic drill collar piston valve
assembly and cylinder body with telemetry unit controllers and valve control spool,
telemetry unit controllers for dump valves showing:-
1. Shows thrust telemetry unit controller.
2. Shows return telemetry unit controller.
3. Shows valve control spool thrust side.
4. Shows valve control spool return side.
9. Shows flow port into item: 1 telemetry unit controller.
10. Shows flow port into item: 2 telemetry unit controller.
11. Shows exhaust out port return side.
12. Shows exhaust out port thrust side cylinder.
143. Shows flow control port to piston dump valve.
145. Shows flow control port to cylinder dump valve.
15. Shows flow port in piston dump valve.
16. Shows flow port out cylinder dump valve.
17. Shows inlet feed to thrust caliper pistons.
21. Shows seal hydraulic drill collar to caliper cylinder body.
30. Shows hydraulic drill collar (piston).
33. Shows cylinder chamber return side.
36. Shows caliper body control sub cylinder rear.
37. Shows hydraulic drill collar piston valve assembly.
38. Shows back cylinder body valve sub.
40. Shows cylinder chamber thrust side.
42. Shows seals for cylinder spool.
WO 94/21889 2 ~5 8 6 ~ ~ ~ PCT/GB94/00515 ~
46. Shows seals striker piston cylinder.
47. Shows seals in cylinder body.
48. Shows seals in hydraulic drill collar piston assembly.
49. Shows seals spool valve piston.
50. Shows cylinder body TUC dump valve.
51. Shows thread on valve control sub hydraulic drill collar.
53. Shows hydraulic drill collar piston valve assembly TUC dump valve.
54. Shows flow port to caliper pistons.
55. Shows control piston to no. 1 TUC.
56. Shows control piston to no. 2 TUC.
61. Shows camshaft and striker piston.
64. Shows control cam.
65. Shows c~rnch~/striker piston cylinder.
66. Shows connection control spool.
67. Shows spring locator (spool valve).
68. Shows striker plates valve control spool.
69. Shows spool valve piston and torque rod.
70. Shows bore for cam.
Figure 26 is a radial cross-section of a TUC with fluid valve spool type
showing:-
1. Shows control unit body (front and rear).
2. Shows pressure control piston (actuator).
3. Shows fluid valve spool.
4. Shows inlet port.
5. Shows outlet port.
6. Shows spring adjuster.
7. Shows male and female threads.
8. Shows actuator housing.
9. Shows toggle bar.
10. Shows latch plate open.
11. Shows pressure inlet port.
12. Shows latch plate closed.
13. Shows toggle latch.
14. Shows toggle housing.
15. Shows spring.
Figure 27 shows a radial cross-section of a dual acting telemetry unit controller
showing:-
1. Shows telemetry unit controller body.
2158~3'7
WO 94/21889 S5 PCT/GB94/00515
2. Shows outlet from pump (off) chamber.
3. Shows inlet from pump (on) chamber.
4. Shows outlet from pump (on) chamber.
5. Shows inlet from pump (off) cll~...b.,l.
6. Shows inlet pilot pressure drilling fluid in.
7. Shows dual piston spool.
8. Shows piston spool return spring.
9. Shows metering piston (angle).
10. Shows metering piston (straight).
11. Shows return springs.
12. Shows metering ports.
13. Shows seals.
14. Shows metering chamber (angle).
15. Shows metering chamber (straight).
I
WO 94/21889 215 ~ ~ 3 7 56 pcTlGs94loo5ls ~
ADVANTAGE OF T~E CALTPER T~RUST UNIT (CTU)
1. Allows the use of angle blocks to thrust out and retract caliper blades in anydown-hole drilling equipment.
2. Allows the use of centre side ports and valve assemblies, used inside thrust
caliper units to control the hydraulic drill çollar for adding weight to the drill bit in any
form of caliper assembly or any down-hole drilling equipment.
3. Allows the use of a toggle/latch pressure pulse valve assembly.
4. Allows the umbilical thrust calipers to stop back wrapping of the tubing (tube
torquing) with coiled tubing drilling unit.
5. Allows the use of a toggle/latch pressure pulse valve assembly with a shear
gate assembly or thrust piston.
6. Allows the use of telemetry unit controllers in hydraulic drilling thrust caliper
units.
7. Allows for continual automatic drilling operation of forward thrust and reverse
with the use of telemetry unit controller (TUC) valves actuated by hydro me~.h~nical
means within a hydraulic drill collar caliper system with down-hole drilling fluid
pressure.
8. Allows for a drilling fluid dump valve system either single use or in pairs with
the telemetry unit controller (TUC) valves.
9. Allows the use of hydraulic and hydro mechanical adjustable down-hole tools
to be used with the telemetry unit controller valve.
10. Allows multiple hydraulic and hydro mechanical adjustable tools to be used and
controlled individually down-hole with the use of telemetry unit controller valves.
11. Allows the use of adjustable down-hole tools to be in coiled tubing operation
without the use of multi-conduit lines for full down-hole tool control.
12. Allows drill pipe to be used with coiled tubing between a pair ofthrust caliper
units (TUC's) and the drilling motor with trajectory control unit.
I WO 94/21889 57 21~ 8 6 3 7 PCTIGB94/00515
Positive disPlacement drillin~ motors
Another aspect of the present invention provides a trajectory control unit and,
preferably, a positive displ~cernent drilling motor with at least one motor housing
trajectory control unit. Such tools are a valuable aid in the drilling of ml-lti(1irectional
wells, such as those required to implement the first part of the invention.
Embo-limPntc of this part of the invention are shown in figures 227 to 43 of theaccompanying drawings.
To drill horizontal wells total control ofthe down-hole assembly is h,.~e.ali~e~to drill long reach wells with conventional drill pipe or coiled tubing. This invention
employs a double motor housing bend sub (telemetry unit controller) fitted to the
bottom of the rotor stator motor housing, with the sealed bearing and output shaft
incorporated in the near bit stabiliser housing and bottom pivot body sub. This
innovation opens up a complete new field for drilling practices, and will realise
significant cost savings over present methods now in use.
The first string stabiliser is adjustable between full gauge and under gauge that
can be used for holding or dropping angle on bottom hole assembly in conjunction with
the double bend (TCU) for kicking offthe well or building angle, allowing a fully
steerable motor system.
Configurations of bottom hole assembly designs can vary, each configuration is
decigned to perform total directional control with the down-hole motor orientated in a
particular direction by drill string rotation or by the orientation unit when used with
coiled tubing, and to drill straight ahead by re-setting the double bend unit. The
straight position by the pre-determined pressure increase to the telemetry unit
controllers (TUC's). This avoids totally dog legs within the well bore which can be
used to plan and select a fully automated down-hole steerable assembly, which will
drill a pre-determined well path.
The trajectory control units, telemetry unit controllers calibrated fluid chamber
allows for 0.25 degree permitted build rate incruments put to 3 degrees, the two bends
are featured in opposite directions which tilts the bits axis from the hole axis to enable
a down-hole system to drill a curve when orientated in the right position. Drilling
straight ahead requires a pressure change or pump on/offto go back to zero, thisallows minimum bit offset red~lcing bit side loading. A single bend motor housing can
also be used to achieve a variety of build rates, this is ideal for re-entry work two
single trajectory control units, giving the drilling motor adjuctm~nt below and above
the motor. The reamer action on the first string stabiliser is employed to smooth the
WO 94/21889 21~ ~ 6 ~ ~ 58 PCT/GB94/00~15 ~
well bore, stabilise the assembly and straighten the well bore where kinks and dog legs
are encountered. These unique features allow directional adjustments to be made from
the rig floor while the drilling assembly is down-hole.
Extended bearing life is obtained by the sealed bearing assembly housed within
the near bit stabiliser body and pivot sub, this allows all of the drilling fluid to be
circulated through the bit for the maximur~ bit hydraulics and cleaning. Sealed bearing
assemblies are lubricated by high temperature oil and fitted with high teml)e-~ re
seals. A dump sub valve is located at the top of the drilling motor to allow drilling
fluid to by-pass the motor and fill the drill pipe while tripping into the hole, it also
permits draining of the drill pipe when tripping out of the well or making a cG.,ne.i~ion,
closure occurs automatically with pump activation.
The universal joint assembly (flex joint) converts offset motion to the rotary
drive sha~, effectively ll ans~ I h~g power from the motor assembly. It is d,o~igned with
al to 2 or multi-helix configuration for high torque low speed output or low torque
high speed output.
The trajectory control unit is controlled by a power section that employs a
helical type screw sleeve and piston, round or square section with seals on the top and
bottom of the piston fitted inside the main cylinder body with top and bottom housing
subs, rotation of the piston is prevented by a guide rod and guide tube running through
the piston and held in place by the top and bottom housing subs, the helical screw
sleeve is fitted with eccentric cams, one facing in the opposite direction. The telemetry
unit controller is fitted into the bottom housing sub and is controlled by the guide tube
running through the piston. The unit is charged by means of a refill valve fitted in the
side of the bottom housing sub allowing the bottom fluid outlet chamber to be
pressurised and pushing the piston to the top start position. The length of the helical
screw and depth together with the fluid outlet chamber will determine the amount of
rotations of the helical screw sleeve before the outlet fluid chamber requires
recharging, rotation of the helical screw sleeve is allowed when fluid from the outlet
fluid chamber is bled out of the telemetry control unit allowing the piston to travel
downwards by drilling fluid entering into the top fluid inlet cha-l-ber via the non-return
inlet valve, this in turn allows the rotation of the eccentric (bottom and top) trajectory
crank cams to allow 0.25 degree angle change each time the telemetry control valve is
operated by a pre-deterrnined pressure increase from the rig floor. This same system
of piston drive power section is also used in the orientation unit, but with a bottom
sealed bearing thrust sub and larger fluid chamber in the telemetry control valve
allowing one (1) degree upwards directional orientation control.
The purpose of the trajectory control unit is to control the direction of drilling
down-hole from the surface. The main elements of the device are; (1) a pivot sub in
wO 94/21889 59 ~15 8 ~ 3 7 PCT/Gsg4/00515
the trajectory unit and a swivel thrust sub in the orientation unit with zero to three
degrees trajectory control and 360 degree directional orientation with one degree or
more increments, (2) the piston drive shaft pressure assembly to produce the
movement and (3) a te~emetry unit controller to control the piston and rotary shaft
movement by pressure impulses injected into the drilling fluid at the surface (pre-
determined momentarily increase in drilling fluid pressure) by means of applyingpressure to force the piston down, powering the drive sleeve is by direct drilling fluid
pressure, the piston pressure is a constant proportion of the drilling fluid pressure.
The number of actuations possible before tripping to lechalge the power
section is determined by piston stroke and helical screw sleeve. The telem~try unit
controller is activated by a pressure pulse in the drilling fluid line and on actuation
metres a defined volume from the power section, the required surface control feature
thus results, correct sizing of the various elements, to achieve for e,~r"ple, one pulse
equals 0.2~ of trajectory change, it is designed to actuate within a window of drilling
fluid pressure, for instance if drilling pressure was normally 1,600 psi the valve could
be arranged to actuate in the trajectory control unit at 2,200 psi for trajectory change,
after actuation the pressure would have to fall back to below say 1,900 psi before
another actuation was possible, this would also activate the orientation unit, but this
would not be significant, as to set directional orientation would be performed last at a
pressure below trajectory change, say 2,000 psi, after actuation the pressure would
have to fall back to 1,700 psi before another actuation was possible.
The reamer/stabiliser fitted with a telemetry unit controller with thrust pistonand rod, this unit consists of a valve housing body and actuator body, the valvehousing body incorporates a thrust piston and rod held in place by a piston return
spring, tension on the spring is adjustable by means of a spring adjuster, the piston and
rod is activated by a toggle and latch fitted inside a toggle and latch housing that
houses a toggle open latch plate, and a toggle close latch plate that is operated by an
actuator piston fitted in the actuator body, when the toggle is on the toggle open latch
the reamer/stabiliser is in full gauge position, when the toggle is in the close latch
position the reamer/stabiliser is in the under gauge position, as shown in the toggle
actuation diagram.
A pressure spring may also be fitted above the helical thrust piston inside the
top fluid inlet chamber for continual pressure on the piston, and without the use of a
non-return valve for drilling with two (2) phase fluids. A single or multi helical screw
or lobe type can be used in the piston and rotary sleeve.
The dual action telemetry unit controller (TUC) allows tripping in and out of
the well in the straight ahead mode. The (TUC) is activated by pump p, es~lre when
the pumps are on. The metering piston in the (TUC) travels forward and allows
2~ss~3t~
WO 94/21889 60 PCT/GB94/00515
rotation of the rotor sleeve allowing trajectory control bit angle face as the piston
displaces fluid from the bottom chamber through the (TUC), when the pumps are shut
off the metering piston returns and displaces fluid from the bottom chamber allowing
the piston to travel downwards rotating the rotor sleeve allowing the bit angle face to
return to the straight ahead position for tripping out of the well. The trajectory control
unit and orientation control ~Init can also be controlled by pulses within the drilling
fluid to activate the telemetry unit controller (TUC) with pulse control unit fitted.
The cam action in the fork can be set for the dual action tPlemetry valve to be
used to change angle with pump on and pump offpositions, ie. pump offstraight ahead
O degree, pump on 1 degree angle (drill), pump off 1.5 degree angle, pump on 2
degree angle (drill), pump off2.5 degree angle, pump on 3 degree angle (drill), pump
offO degree angle well bore to drill straight ahead when down-hole, the first position
would be changed by the setting of $he can face design, this will allow angle face
changes by pump on and offwithout any hydraulic pressure increase or pulse ch~nges
down-hole, a drilling record will need to be recorded on the amount of pump stopping
and starting to determine bit angle face.
The size of the metering chamber determines the amount of piston travel and
rotation of the drive sleeve and degree angle of bend.
Figure 27 shows a radial cross-section of a trajectory control unit (TCU), and down-
hole motor sealed bearing assembly (double bend sub or single).
1. Shows piston helical rotary sleeve.
2. Shows eccentric trajectory crank (cam).
3. Shows anti-rotational cross bar, radial bearings with top and bottom
radial seals.
4. Shows pivot body sub.
5. Shows output thrust sha~L.
6. Shows universal joint assembly.
7. Shows radial bearings output shaft to pivot sub.
8. Shows pivot ball joint with bore and top fork.
9. Shows male (pin) thread pivot sub to body.
10. Shows bottom male (pin) thread pivot ball joint to stabiliser body.
11. Shows pivot ring seat retainer.
12. Shows top stabiliser/output shaft ret~ining housing.
13. Shows top radial seal.
14. Shows thrust (lock ring) bearing.
15. Shows thrust bearings.
16. Shows lower output thrust shaft and bit box connection.
17. Shows stabiliser sleeve.
~ WO 94121889 61 21~ ~ 6 3 7 PCT/GB94100515
18. Shows bottom stabiliser sleeve and bearing housing ret~ining sub.
19. Shows bottom radial seal.
20. Shows seal retaining clip.
21. Shows cylinder body.
22. Shows thrust piston helical.
23. Shows piston guide control tube and seals.
24. Shows piston guide rod and seals.
2~. Shows piston seal.
26. Shows piston helical rotary sleeve.
27. Shows output thrust shaft.
28. Shows bottom bearing and TCU control sub.
29. Shows top bearing and tube control sub.
30. Shows lock nut and seal con~rol tube.
31. Shows lock nut and seal guide rod.
32. Shows helical screw male (sleeve).
33. Shows helical screw female (piston).
34. Shows bearing radial bottom on helical rotary sleeve.
35. Shows bearing radial top on helical rotary sleeve.
36. Shows refill valve port.
37. Shows radial seals for rotary sleeve bottom.
38. Shows radial seals for rotary sleeve top.
39. Shows bore of output thrust shaft.
40. Shows top double (or single) trajectory control unit/sealed bearing
assembly connection to down-hole drilling motor.
41. Shows top fluid inlet chamber.
42. Shows inlet port and non-return valve.
43. Shows inlet port telemetry unit controller (TUC).
44. Shows outlet fluid chamber.
45. Shows outlet fluid port from telemetry unit controller (TUC).
46. Shows flexible connection between swivel sub fork item 8 and item 29
top bearing and tube control sub to item 42 inlet port and item 43 control (TCU) port.
Figure 27a shows a sub-assembly, the detail of which is essonti~lly shown in
figure 34.
Figure 28 shows an axial top section of item 8 pivot ball joint with bore and top
fork.
1. Shows piston helical rotary sleeve.
?. Shows eccentric trajectory crank (CAM).
Wo 94/21889 21~ 8 ~ 3 7 62 PCT/GB94/00515
3. Shows anti-rotational cross bar, radial bearings and with top and
bottom radial seals.
4. Shows pivot body sub.
5. Shows output thrust shaft.
7. Shows radial bearings output shaft to pivot sub.
8. Shows top fork on item 8 pivot ball joint.
Figure 29 shows an axial cross-section of the trajectory control unit, cylinder
body and piston with piston guide control tube and rod.
21. Shows cylinder body.
22. Sows thrust piston.
23. Shows piston guide control tube.
24. Shows piston guide rod.
25. Shows piston seal.
26. Shows piston helical rotary sleeve.
27. Shows output thrust shafe.
Figure 30 shows a radial cross-section of item 46 flexible connection.
47. Shows seal cup with flexible ball joint.
48. Shows seals cup ball.
49. Shows seal cup.
50. Shows seal spring.
51. Shows item 8.
52. Shows item 29.
Figure 31 shows a radial cross-section of a fluid dump valve.
l. Shows box connection.
2. Shows valve body.
3. Shows piston.
4. Shows spring.
5. Shows piston bore.
6. Shows dump port piston.
7. Shows pin connection.
8. Shows dump port body.
Figure 32 shows a radial cross-section of a down-hole drilling motor.
53. Shows motor body.
54. Shows stator (rubber type compound) 1 - 2 or multi-helix.
55. Shows rotor with or wiehout through bore 1 - 2 or multi-helix.
56. Shows top connection female box.
57. Shows bottom connection female box to female box.
58. Shows connection for universal joint to output thrust shaft.
WO 94/21889 63 ~15 ~ 6 ~ 7 PCT/GB94/00515
59. Shows axial cross-section of rotor/stator.
60. Shows axial cross-section of rotor/stator.
Figure 33 shows a diagramatic drawing of a drilling assembly for
directional/horizontal drilling.
1. Shows drill string or coiled tubing.
2. Shows orientation unit if used with coiled tubing.
3. Shows adjustable first string reamer/stabiliser.
4. Shows dump valve.
5. Shows down-hole drilling motor.
6. Shows (single bend) trajectory control unit (TCU).
7. Shows reamer body sealed bearing thrust assembly.
8. Shows drill bit.
Figure 34 shows radial cross-sections of a telemetry unit controller (TUC)
(fluid metering type).
A. Shows initial condition.
B. Shows pressure pulse received.
C. Shows metered volume fills.
D. Shows pulse decays and metered volume empties.
5. Shows control unit body.
6. Shows metering piston.
7. Shows pressure control piston.
8. Shows metering spring.
9. Shows pressure spring.
10. Shows inlet port.
11. Shows outlet port.
12. Shows pressure port.
13. Shows metered volume.
Figure 3 5 shows radial cross-sections of a telemetry unit controller (TUC)
(hydraulic thrust type).
1. Shows control unit body (front and rear).
2. Shows pressure control piston (actuator).
3. Shows thrust piston and rod.
4. Shows spring adjuster.
5. Shows male and female threads.
6. Shows actuator housing.
7. Shows toggle bar.
8. Shows latch plate open.
9. Shows pressure inlet port.
21~g~37
WO 94/21889 64 PCT/GB94/00515
10. Shows latch plate closed.
11. Shows toggle latch.
12. Shows toggle housing.
Figure 36 shows a radial cross-section ofthe to~gle bar and toggle latch with
latch plates, showing the seven (7) positions.
Figure 37 shows a diagra~matic drawing oftwo (2) single trajectory control
units in a drilling assembly.
1. Shows adjustable reamer stabiliser.
2. Shows dump valve.
3. Shows trajectory control unit (TCU) top.
4. Shows down-hole drilling motor.
5. Shows trajectory control unit (TCU) bottom.
6. Shows stabiliser and sealed bearing assembly.
7. Shows drill bit.
Figure 38 shows a diagramatic drawing of a single trajectory control unit in a
drilling system.
1. Shows adjustable reamer stabiliser.
2. Shows dump valve.
3. Shows trajectory control unit (TCU).
4. Shows down-hole drilling motor.
5. Shows stabiliser and sealed bearing assembly.
6. Shows drill bit.
Figure 39 shows radial cross-section of an orientation unit.
1. Shows orientation tool body.
2. Shows piston helical rotary orientation shaft.
3. Shows thrust sub rotary ball assembly body.
4. Shows radial top bearing cup assembly.
5. Shows thrust bearings bottom cup.
6. Shows seals (rotary).
7. Shows top control inlet sub.
8. Shows bottom outlet control sub.
9. Shows control torque tube.
10. Shows control torque rod.
11. Shows torque nut and seal for tube.
12. Shows torque nut and seal for rod.
13. Shows helical piston thrust control.
14. Shows charging valve port.
15. Shows telemetry unit controller (TUC).
~ WO 94/21889 65 21 S 8 G 3 7 PCT/G~94/00515
16. Shows outlet port.
17. Shows rotary ball shaft output sub.
18. Shows pin thread connection.
19. Shows orientation ball top bearing assembly.
20. Shows box connection.
21. Shows inlet port to TUC tube.
22. Showstop chamber.
23. Shows female helical thread piston.
24. Shows male helical thread drive shaft.
25. Shows pin thread from ball to shaft.
26. Shows inlet port to piston.
27. Shows top sub.
28. Shows seals for TUC tube.
29. Shows drive keys.
30. Shows bottom chamber.
Figure 39a shows a sub-assembly which is eccenti~lly the same as that shown in
figure 34.
Figure 40 shows a diagramatic view of a twin bend housing assembly trajectory
control unit (TCU) as per figure 27.
1. Shows adjustable reamer/stabiliser.
2. Shows dump valve.
3. Shows down-hole drilling motor.
4. Shows twin bend trajectory control unit (TCU).
5. Shows stabiliser and sealed bearing assembly.
6. Shows drill bit.
Figure 41 shows a radial cross-section of a universal joint and output thrust
shaft.
9. Shows pin connection.
10. Shows constant velocity universal joint.
11. Shows flow port.
12. Shows bore.
13. Shows output shaft.
Figure 42 shows a radial cross-section of a trajectory control unit (TCU) and
down-hole motor sealed bearing assembly (single bend sub).
1. Shows piston helical rotary sleeve.
2. Shows eccentric trajectory crank (CAM).
Shows anti-rotational cross bar, radial bearings with top and bottom radial
seals.
WO 94/21889 21~ l 66 PCT/Gs94/00515
4. Shows pivot body sub.
5. Shows output thrust shaft.
6. Shows universal joint assembly.
7. Shows radial bearings output shaft to pivot sub.
8. Shows pivot ball joint with bore and top fork.
9. Shows male (pin). thread pivot sub to body.
10. Shows bottom male (pin) thread pivot ball joint to stabiliser body.
11. Shows pivot ring seat retainer.
12. Shows top stabiliser/output shaft ret~ining housing.
13. Shows top radial seal.
14. Shows thrust (lock ring) bearing.
15. Shows thrust bearings.
16. Shows lower output thrust shaft and bit box connection.
17. Shows stabiliser sleeve.
18. Shows bottom stabiliser sleeve and bearing housing ret~ining sub.
19. Shows bottom radial seal.
20. Shows seal ret~ining clip.
21. Shows cylinder body.
22. Shows thrust piston helical.
23. Shows piston guide control tube and seals.
24. Shows piston guide road and seals.
25. Shows piston seal.
26. Shows piston helical rotary sleeve with bearing journals.
27. Shows output thrust shaft.
28. Shows bottom bearing and TCU control sub.
29. Shows top bearing and tube control sub.
30. Shows lock nut and seal control tube.
31. Shows lock nut and seal guide rod.
32. Shows helical journals male (sleeve).
33. Shows helical journals female (piston).
34. Shows bearing radial bottom on helical rotary sleeve.
35. Shows bearing radial top on helical rotary sleeve.
36. Shows refill valve port.
37. Shows radial seals for rotary sleeve bottom.
38. Shows radial seals for rotary sleeve top.
39. Shows bore of output thrust shaft.
40. Shows top double (or single) trajectory control unit/sealed bearing
assembly connection to down-hole drilling motor.
~ wO 94/21889 67 2 ~ 5 8 ~ ~ 7 PCT/GBg4/00515
41. Shows top fluid inlet chamber.
42. Shows inlet port and non-return valve.
43. Shows inlet port telemetry unit controller (TUC).
44. Shows outlet fluid chamber.
45. Shows outlet fluid port from tPlemetry unit controller (TUC).
46. Shows flexible connection between swivel sub fork item 8 and item 29
top bearing and tube control sub to item 42 inlet port and item 43 control (TCIJ) port.
47. Shows micro-logic control valve.
48. Shows battery pack (activator unit/receiver unit).
49. Shows ball bearings.
Figure 42a is basically the same as figure 34.
Figure 42b shows an alternative arrangement to figure 42a.
Figure 43 shows the main mec~nicrn ofthe figure 42b arrangement to a larger
scale.
WO 94/21889 21~ ~ 6 3 ~ 68 PCTlGss4loosls ~
TRAJECTORY CONTROL POSTT~VE DISPLACEMENT DRILLING
MOTORS TRAJECTORY CONTROL UNIT (TCU)
ADVANTAGES
1. Allows trajectory control down-hole from the surface with a double bend
motor body with a helical screw piston and helical screw sleeve controlling eccentric
crank (CAM) via a pivot sub and telemetry unit controller valve to meter a defined
volume of fluid to control piston travel and rotary movement.
2. Allows orientation control down-hole from the surface with a helical screw
piston and helical screw sleeve connected to a rotary thrust bearing sub and telemetry
control valve to meter a defined volume of fluid to control piston travel and rotary
movement.
3. Allows the use of an ~ccllm~ tor (weight set) to control the telemetry unit
controllers thrust piston, to control the movement of the reamer/stabiliser blades within
the reamer/stabiliser body.
4. Allows for a down-hole drilling motor to house the double motor body bends,
and for the bottom section to retain a stabiliser sleeve, held in place on the bottom
bend section stabiliser sleeve body that houses the thrust bearing and radial bearings,
also radial seals in the bottom pivot sub, allowing full thrust loads to be directly
applied to the bottom part of the assembly before the first bend, and radial bearings in
the second bend allowing for shorter bend sub units.
5. To allow total steerability this system employs a positive displacement motorwith a double motor housing bend (trajectory control unit), telemetry control allows
the motor to drill a curve and remain down-hole to drill a tangent section so that the
double bend can be set in the straight ahead position by telemetry control. To remain
concentric with the bit to the hole at all times allowing maximum cutting effir~içncy.
Two stabilisers, the upper one adjustable determines the directional pelro~ ce ofthe
bottom hole assembly.
The two stabilisers and the bit serve as tangency points, the top stabiliser being
adjustable has fine control that defines a constant radius arc oriented hole curvature,
build rate can be adjusted down-hole by telemetry control varying the trajectorycontrol units (double bend motor body) angle setting, allowing total trajectory and
orientation control down-hole from the rig floor by telemetry control.
6. Allows total down-hole control with this system by the use of adjustable first
string reamer/stabiliser and fixed near bit stabiliser with trajectory control units
(TCU's) fitted between the two stabilisers, either one or more trajectory control units
can be used predicting how a given bottom hole assembly (BHA) will perform by
contact points with the bore hole wall~ the two stabilisers and the bit serve as tangency
wO 94/21889 69 ~ 1 5 8 6 3 7 PC; ~B94/00515
points that define a constant radius arc along which the assembly will drill when
ori~nt~tecl Hole curvature, or design build rate, can be adjusted by varying thetrajectory control unit angle, the variable ~ meter and the pl~cement of the first string
reamer/stabiliser. During drilling, build rates can be fine tuned by telemetry control
down-hole to the trajectory control unit for precise directional control.
7. Allows the use for short radius drilling with multiple trajectory control units
fitted with telemetry unit controllers to the drill string or coiled tubing, to build
wellbore inslin~tion to holi~onlal 90 degree on a radius of only 40 feet with short
motor section with precise directional control over in~lin~tion and hole ~imllth and
will drill horizontal extended reach of over 2,000 feet. This system does not require
string rotation which is the cause of critical hole damage, allows fewer trips for BHA
changes.
8. Allows the use for medium radius s~eerable angle build with build rates of up to
20 degrees per lO0 feet with two trajectory control units for horizontal and "J" type
wellbores and caliper thrust units.
9. Allows the use for long radius steerable angle build with one or two trajectory
control units for build rates of up to 5 degrees per lO0 feed for horizontal and "J" type
"U" type wellbores with caliper thrust units.
10. Allows total down-hole directional control without the use of umbilical lines
from the drill floor in single and two phase drilling fluids with coiled tubing or
drillpipe.
11. Allows down-hole control of the trajectory control unit and orientation unit by
the length of the piston helical threads or lobes and drive sleeve helical threads and
lobes, that will deterrnine the amount of rotation of the drive sleeve, the boom chamber
returns the piston back when recharging in the accl.m~ tor type unit, the tel~nnetry
unit controller meters a pre-determined amount of fluid from the chamber allowing
rotation of the drive sleeve for trajectory or orientation control by pre-determined
pressure increases.
12. Allows the use of composite flexible joints in trajectory control unit tools.
13 . Allows the use of any design of the standard or umbilical orient~tion or
trajectory control stabiliser tool, also covers any type of eccentric/concentric type
pump/motor design that can be used in this type of tool to enable its use to give single
control of the drilling unit for directional drilling control, it is intended that any type of
rotor stator piston sleeve system or epitrochoid chamber trirotor (equilateral triangle)
rotor is included
14. Allows total orientation control down-hole with the use of telemetry unit
controller (TUC) and helical screw piston/helical screw sleeve or helical lobes.
WO 94/21889 2~ 5~ ~ 3 7 70 PCT/GB94/0051~ ~
15. Allows the use of an accumnl~tQr type hydraulic power section to control
down-hole drilling tools.
16. Allows the use of a fork type lever with a pivot to swivel (knur~le joint) on a
top and bottom bearing plate housings by the use of ecce..llic or concentric CAMs that
prevents rotation by the use of cross tie bar through the fork to the sides of the body.
17. Allows the use of an adjustable blade type reamer/st~hilicer fitted within the
drill string in conjunction with trajectory control, ori~nt~tion control by hydraulic
pressure increased in the telemetry unit controller, or micro-logic unit by control from
the rig floor down-hole in controlling the tangent control points.
18. Allows the use of a replaceable sleeve or fixed type st~bilicer on a down-hole
bearing assembly used in the telemetry unit controlled, trajectory control unit or
orientation unit for directional drilling control.
19. Allows the use of adjustable bend or bends in the drill string to be controlled
down-hole when drilling by telemetry hydraulic unit control by micro-logic unit or the
increase in drilling pressure for directional drilling and being able to return back to the
straight mode of drilling without pulling the drill string or coiled tubing from the well.
20. Allows the trajectory control unit to be used with or without near bit stabiliser
and or sealed bearing housing.
21. A deflection side pad can also be fitted to the bottom sub figure 18 items 17
and 18 to allow directional drilling control.
22. Allows the use of special high pressure and high temperature elastomers and
rubber type compounds over 350C. Working temperature, with high dulon,~,Ler
(shore-hardness) to stop leakage past the rotor/stator in drilling motors, for use in high
pressure and high temperature wells, allowing thigh flow rates for hydraulic and well
cleaning returns.
23. Allows high pressure and high temperature seals to be used above 350C in all
down-hole tools.
24. Allows an adjustable hydraulic deflection pad controlled by angle blocks to be
used within the motor body housing trajectory control unit behind the adjustable bent
housing.
25. Allows trajectory control, orientation control and side thrust pad control, for
maximum drilling control by micro-logic mud pulse signals, negative type by a
tr~n~mitter surface unit to a down-hole receiver/activator unit in tool bodies, to control
the tel~metry unit controllers.
WO 94/21889 71 ~ PCT/GB94/00515
Compensatin~ underreamer
Another aspect of the present invention provides a comp~ns~ting unde, I ~,an~er. This
tool is a valuable aid in the drilling of multidirection~l wells, such as those required to
implement the first part of the invention. An embodiment of the tool is shown in figure
44 of the accompanying drawings.
This tool uses side ported pistons and cylinders fitted around the outside of the
tool body, around the bore, two three or four to operate the corresponding cutter
arms, this system allows single action to each cutter arm by the hydraulic piston action
onto the thrust piston road, when the pumps are on, delivering down-hole pressure by
drilling fluid onto the pistons, pushing forward the thrust pistons onto the thrust
blocks, that in turn drive the cutter arrns forward and outwards by the use of cam
guide slots in the body of the underreamer housing for the cutter arm assembly, by
milling in curved slots, with corresponding guide pin roller, in the side of the tool
body, like a dowel type pin through the cutter arm, allowing the outward movement of
the cutter arms, and retraction in the reverse operation when the micro-logic
activator/receiver unit, pulse signal in the drilling fluid pressure is received, allowing
the cutter arms to retract into the closed position, by the return springs fitted to the
hydraulic pistons, allowing complete .cim~llt~neous closing and opening, each time the
micro-logic valves are operated.
The underreamer is a tool designed to pass through a restriction, opening up
below the restriction to clean out the hole to full gauge and then close up again to be
retrieved from the well-bore, normally the restriction is the production tubing and
other production accessories in the string.
The underreamer should open out to a diameter of about 0.5 inches less then
the ~i~m~ter if the liner, the tool is again actll?ted by a mid-pulse in the drilling fluid to
activate the control thrust pistons by pressure on the hydraulic pistons, which move to
activate the thrust pistons to force the blades open, by difrerenlial pressure across the
piston faces, when the pressure is released to close the tool, the sequence is reversed
and does not require hydraulic pressure to keep the tool closed, as is the case with
other types of underreamer.
The blades cannot close up when drilling and will always ~iceng~pe when
activated in the closed position. With cutter lubrication and jetting, within the blade
area for any solid particles in the return flow, to be jetted away by the hole
opener/milling tool pressure to stop any solids locking up the tool whilst in use. When
WO 94/21889 21~ 8 ~ 3 7 72 PCT/GB94/00515 ~
used as an underreamer the bottom of the tool is fitted with a cutting type face to form
a flat pilot hole for the underreaming tool.
The hole opener/milling tool works on the same principle and is ideal for
opening up the well-bore below the casing point or for cutting the section of casing
away to expose the well-bore formation for opening up the hole, ie. side tracing for
lateral and horizontal drilling.
The electro-hydraulic hardware consists of a signal ~ n.C,..;~er unit located atthe surface, and a pulse signal receiver unit located in the activator unit, in either the
trajectory control unit, orientation control unit, reamer stabiliser unit, thrust pad unit,
unde~ . eal..er unit and the dump valves on the caliper thrust units, to control the
telemetry unit controllers.
The transmitter unit consists of a single chip microcomputer unit and a power
amplifier, two switches, on/off, activate the microcomputer and solenoid valves,operate the pressure pulse valve.
The receiver unit consists of a pressure tran.~d~lcer and amplifier, analog to
digital converter, single chip microcomputer watch dog power amplifier battery power
supply, with oil/nitrogen accl~mul~tQr, solenoid valve and mud valve, the solenoid
valve is used to activate the mud valve, which controls the telemetry unit controller.
The watch dog is a circuit which is used to reset the rnicrocomputer unit, in case of
failure due to electromagnetic noise, etc. The circuit is also used to avoid uncontrolled
activation of the solenoid valve.
Figure 44 shows a radial cross-section of a compen~ting underreamer, hole
opener/milling tool (cut) showing:-
1. Shows box thread connection.
2. Shows pin and box connection top sub.
3. Shows feed port to pistons.
4. Shows fluid chambers and micro-logic control valve.
5. Shows piston seals.
6. Shows hydraulic thrust piston assembly and thrust rod (open).
7. Shows thrust head return spring (open).
8. Shows connection pin thread to thrust head guide block.
9. Shows thrust head guide block (open).
10. Shows cutter arm swivel pin.
11. Shows cutter arm assembly (2, 3 or 4 arms ( (open) 3.
12. Shows locking guide slot pins in cutter arms.
13. Shows locking guide slots (closed) in tool body.
14. Shows milled tooth cutters on bearings (2, 3 or 4 cutters) or other
types.
21S~37
WO 94/21889 73 PCT/Gs94/0051
15. Shows housing for cutter arm assembly.
16. Shows body of underreamer.
17. Shows box thread connection.
18. Shows thrust head guide block assembly.
- 19. Shows top sub seal.
20. Shows top sub.
21. Shows bore of undel-~ller.
22. Shows battery pack activator/rece.~er urlit.
wo 94121889 21~ 74 PCTlGss4loosls
ADVANTAGES OF T~E COMPENSAT~NG UNDERREAMER
1. Allows the use of two (2), three (3) or four (4) side ported pistons and
cylinders to control cutting arms in underreamers, hole opel-e. ~ and milling tools.
2 Allows full through bore in the underreamers, hole openers and milling tools
with side pistons and cylinders for improved down-hole hydraulics and cle~ning
3. Allows the use of thrust blocks controlled by thrust pistons, to thrust forward
and out the cutter arms in underreamers, hole openers and milling tools.
4. Allows the use of milled curve guide slots in the unde,-ear..cr body, and dowel
type bearing pins in the cutter arms to control the outward and inward movement of
the cutter arm assembly in unde. l ealnel, hole opener and milling tools
5 Allows the use of side hydraulic pistons, cylinders and return springs, to
compensate for the outward and inward action of the cutter arms within underreamers,
hole openers and milling tools
6 Allows the use of a micro-logic activator/receiver unit by rig floor ~ c~ er
controlled drilling mud pulse, for control of the cutter arms in undel ealllt;l ~.
WO 94/21889 75 215 8 ~ 3 7 PCT/GB94/00515
Trirotor Positive Dis~lacement Mud Drillin~ Motor
Another aspect of the present invention provides a Trirotor Positive Displ~cem~nt
Mud Drilling Motor. This tool is a valuable aid in the drilling of multidirectional wells,
such as those required to implement the first part of the invention. An embodiment of
the tool is shown in figures 45 and 46 of the ~ccG-..p~.ying drawings.
The epitrochoidal rotary cylinder and trirotor is an ideal method when used as adrilling mud motor which has advantages over the normal rotor/stator type motor due
to the absence of the rubber compound type ~laLor/rotor which will not perform in
temperatures in excess of 350 degrees F. As the epitrochoidal rotor chamber/trirotor
stator has no rubber compound sealing arrangement.
The epitrochoidal rotor cylinder is rotated round the fixed thrust bearing sub by
the fixed drive pinion gear shaft connected to the fixed thrust bearing sub by a non
rotating constant velocity flexible joint to allow orbital movement of the outerepitrochoidal casing rotor by the force of drilling fluid pumped under pressure through
the peripheral two inlet ports machined into the sides of the epitrochoidal rotor
cylinder, rotating the trirotor and discharging the drilling fluid through the peripheral
two outlet ports.
The long inlet and outlet peripheral ports never close. This leads to volumetricefficiency in excess of 100%. The fixed drive pinion is held in place at the bottom of
the epitrochoidal rotor cylinder in a central position and secured in the trirotor at the
top end by an eccentric crank, and the trirotor is connec~ed to the epitrochoidal rotor
cylinder by a further eccentric crank allowing a fixed orbital motion of the trirotor
within the epitrochoidal rotary cylinder by the fixed inside gear fitted central to the
trirotar faces rotates the epitrochoidal rotary cylinder in a concentric outer rotation
around the thmst bearing sub while the trirotor stator moves in a stationary orbital
movement as fluid is pumped through to both peripheral outlet ports.
The position of the trirotor in the epitrochoidal rotary chamber is shown in
figure 46. The peripheral inlet and outlet ports as shown in figure 46 - 6 outlet port
and - 7 inlet port.
Figure 45 shows epitrochoidal rotor/trirotor stator positive displ~cement mud
drilling motor with fixed orbital trirotor stator and rotary epitrochoidal outer rotor
with rotary stabiliser showing:-
1. Thrust collar.
2. Shows female box connection.
3. Shows inlet chamber.
W O 94121889 21 S ~ 76 P C T/G B94100515
4. Shows fluid ports in fixed orbital flexible joints.
5. Shows top eccentric guide thread.
6. Shows peripheral inlet port.
7. Shows bearing for eccentric crank ~internal gear and pinion).
8. Shows eccentric crank inside internal gear and splined pinion guide.
9. Shows epitrochoidal bore.
10. Shows trirotor stator. -
11. Shows splines on intèrnal gear.
12. Shows splines on pinion.
13. Shows pinion.
14. Shows retaining key for pinion.
15. Shows is fixing recess for pinion in bottom sub.
16. Shows outlet flow port.
17. Shows female box connection for drill bit.
18. Shows bottom sub.
19. Shows splines on pinion.
20. Shows splines on internal gear.
21. Shows peripheral outlet port.
22. Shows pinion bearings in eccentric gear crank.
23. Shows drive head from trirotor stator to fixed flexible joint.
24. Shows main rotor body.
25. Shows bearings for top eccentric trirotor crank.
26. Shows fixed flexible joint.
27. Shows thrust bearing sub.
28. Shows top fluid port.
29. Shows thrust bearings.
3 0. Shows rotary bearings.
31. Shows top sub.
32. Shows stabiliser straight blade or spiral type.
~ WO 94/21889 77 215 ~ 6 3 7 PCT/Gs94/00515
Ulatalobe CavitY Trirotor Displacement Pump/Motor
Another aspect of the present invention provides a Ulatalobe Cavity Trirotor
- Displ~cçmPnt Pump/Motor. This tool is a valuable aid in the drilling of
multidirectional wells, such as those required to implement the first part of the
invention. An embodiment of the tool is shown in figure 47 of the acco,l")~,ying
drawmgs.
This part of the invention provides an ~ tive outer pump casing, with
internal helix, a fixed female external helix outer stator with internal helix and a fixed
male inner external helix fitted to the pump end casing at one end and the central male
external helix/female internal helix rotor driYe head fitted within the two stators by a
constant velocity flexible connecting joint. The use of one male/female cylindrical
rotor, spinning inside the outer female stator and inside the central male stator ensures
that cavities are formed and progress in an upward or downward direction, depending
upon the rotation of the pump or motor. Fluid enters the cavities and is driven through
the rotors, stators/stator.
The lobes on the rotors/stators form cavities between the cylindrical multi-helix
male/female rotor and the male/female stators as the cylindrical male/female rotor turns
about its eccentric rotation around the outer male stator and also eccentric rotation
inside the female stator, fluid enters and leaves the central male/female rotor stator
cavities through the inner and outer feeder pathways on the cylindrical male/female
rotor ends, or by direct feed into the cavities in pumps or motors when the bearings are
not used on the outlet side of the inner male stator and inlet side of the drive head male
and female rotor, but still ret~ining the flow pathways on the drive head shaft rotor
end.
Multi phase fluids can also be pumped by the use of twin outer left hand and
right hand female internal helix stators allowing for centre fluid chamber and outer
fluid feed chambers, the centre male left hand and right hand exterior helix stator with
centre flow recess, the male stator is fixed to the pump casing at the bottom end and
held in position in the main rotor by bearings so that the rotor and the flexible joint
rotate around the inner male fixed stator. The only moving part is the male/female
internal helix cylindrical rotor with left hand and right hand helix, with out fluid
pathways to feed the central rotors, stators through the cavities formed by the contra
rotating helix allowing fluid to be driven to the centre outlet pump chamber. The
cylindrical male/female contra rotating helix rotor has central fluid paLl,~ays to allow
the fluid to enter the centre outlet chamber with the fluid from the outer male
WO 94/21889 2 ~ 3 ~ 78 PCT/GB94/00515
rotors/stators, the outer cylindrical rotors and fixed male stators with one less lobe
than the outer stator and inner rotor both move around the inside of the stator/rotors.
This combined geometry sequentially seals the flow chambers through which the fluid
moves axially, the configuration of the rotors and stators conra rotating act as integral
opposing re~ucing gears and opposing power generation units which delivers high
pump volume with high pressure by the contra rotating multi-helix rotors and stators.
The ultralobe cavity trirotor positive rli~pl~cem~nt pump has only one moving
part, that of the male/female multi-helix drive head rotor with male external helix rotor
and female internal helix rotor, the outer female internal helix stators and the fixed
male external helix stator. The female and male stators can be precision moulded from
durable corrosion resistant synthetic elastomer which is perrn~nently bonded to a steel
housmg.
The drive head cylindrical rotor internal helix is precision moulded and
perrn~ntontly bonded to the drive head rotor but other methods may by used by those
skilled in the art, with the external helix bonded to the central male fixed stator. This
type of design cannot gas lock so pumping free gas is ideal for this system. It is also
ideal for pumping in adverse conditions such as sand, gypsum, salt, parafin, wax, gas
and high viscosity crude.
Multi-helix or 1/2 lobe rotors/stators are covered within the invention.
With the ultralobe cavity trirotor motor rotational power is created when fluid
is pumped through the multi-helix which operates on the Moineau principle
rotor/stator configuration multi stage progressive cavities allowing low and high
speeds with high torque with the use of internal and external multi-helix rotors/stators
allowing a continuous flow of pressurised fluid to pass through the cavities. Special
types of rubber compounds can be used thereby preventing abrasive wear and allowing
the use of wear resistant materials to elimin~te erosive wear on the internal external
rotor/stator system.
The male stator and fema~e stator is fitted with a Cohs~anl velocity flexible
connecting rod assembly. The male/female rotor/stator can also be contra rotating.
Figure 47 shows a radial cross-section of a multiphase flow type ultralobe
cavity trirotor pump showing:-
1. Shows pump casing.
2. Shows fluid transfer chamber.
3. Shows pump chamber.
4. Shows pump end cover.
5. Shows pump end drive cover.
7. Shows female right hand fixed internal helix stator.
8. Shows female left hand fixed internal helix stator.
~ WO 94/21889 79 215 ~ 6 37 pcTlGs94loo5l5
9. Shows left hand and right hand internal and external helix rotor driveshaft.
11. Shows constant velocity flexible joint with flow pathways for fluid.
12. Shows constant velocity flexible joint with flow palh~ays for fluid.
13. Shows centre flow pathways for fluid.
14. Shows male stator bearing hou~ing
15. Shows male stator fixed drive bearing housing bottom.
19. Shows pump end cover fixing studs and nuts.
20. Shows bearing housing.
21. Shows male and female rotor bearing drive.
22. Shows inlet port.
23. Shows outlet port.
24. Shows external cavities.
25. Shows internal cavities.
28. Shows left and right hand external helix fixed male stator.
29. Shows male stator fixing point.
30. Shows joint for male and female internal/external helix cylindrical drive
head rotor.
