BAKER HUGHES, A GE
`COMPANY, LLC AND BAKER
`HUGHES OILFIELD
`OPERATIONS LLC
`Exhibit 1136
`BAKER HUGHES, A GE
`COMPANY, LLC AND BAKER
`HUGHES OILFIELD
`OPERATIONS LLC v. PACKERS
`PLUS ENERGY SERVICES, INC.
`IPR2016-01506
`
`Page 1 of 15
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`US. Patent
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`Jan.21,2003
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`US 6,508,307 B1
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`US 6,508,307 B]
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`1
`TECHNIQUES FOR HYDRAULIC
`FRACTURING COMBINING ORIENTED
`PERFORATING AND LOW VISCOSITY
`FLUIDS
`
`This patent application is a non-provisional application
`based on US. Provisional Application No. 60/145,000, filed
`Jul. 22, 1999.
`
`BACKGROUND OF THE INVENTION
`
`1. Technical Field of the Invention
`
`The present Invention relates to techniques for stimulating
`the production of oil and gas from a reservoir. In particular,
`the present Invention relates to specialized techniques of
`propped hydraulic fracturing, in which the perforations are
`shot in a plane aligned with the direction of probable fracture
`propagation, thereafter the fracturing treatment is performed
`using a low viscosity fluid.
`2. Introduction to the Technology
`The present Invention relates generally to hydrocarbon
`(petroleum and natural gas) production from wells drilled in
`the earth. Obviously, it is desirable to maximize both the rate
`of flow and the overall capacity of hydrocarbon from the
`subsurface formation to the surface, where it can be recov-
`ered. One set of techniques to do this is referred to as
`stimulation techniques, and one such technique, “hydraulic
`fracturing,” is the subject of the present Invention. The rate
`of flow, or “production” of hydrocarbon from a geologic
`formation is naturally dependent on numerous factors. One
`of these factors is the radius of the borehole; as the bore
`radius increases, the production rate increases, everything
`else being equal. Another, related to the first, is the flowpaths
`from the formation to the borehole available to the migrating
`hydrocarbon.
`Drilling a hole in the subsurface is expensive—which
`limits the number of wells that can be economically
`drilled—and this expense only generally increases as the
`size of the hole increases. Additionally, a larger hole creates
`greater instability to the geologic formation, thus increasing
`the chances that the formation will shift around the wellbore
`
`and therefore damage the wellbore (and at worse collapse).
`So, while a larger borehole will, in theory, increase hydro-
`carbon production, it is impractical, and there is a significant
`downside. Yet, a fracture or large crack within the producing
`zone of the geologic formation, originating from and radi-
`ating out from the wellbore, can actually increase the
`“effective” (as opposed to “actual”) wellbore radius, thus,
`the well behaves (in terms of production rate) as if the entire
`wellbore radius were much larger.
`Fracturing (generally speaking, there are two types, acid
`fracturing and propped fracturing, the latter is of primary
`interest here) thus refers to methods used to stimulate the
`production of fluids resident in the subsurface, e.g., oil,
`natural gas, and brines. Hydraulic fracturing involves liter-
`ally breaking or fracturing a portion of the surrounding
`strata, by injecting a specialized fluid into the wellbore
`directed at the face of the geologic formation at pressures
`sufficient to initiate and extend a fracture in the formation.
`More particularly, a fluid is injected through a wellbore; the
`fluid exits through holes (perforations in the well casing
`lining the borehole) and is directed against the face of the
`formation (sometimes wells are completed openhole where
`no casing and therefore no perforations exist so the fluid is
`injected through the wellbore and directly to the formation
`face) at a pressure and flow rate sufficient to overcome the
`minimum in-situ rock stress (also known as minimum
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`principal stress) and to initiate and/or extend a fracture(s)
`into the formation. Actually, what is created by this process
`is not always a single fracture, but a fracture zone, i.e., a
`zone having multiple fractures, or cracks in the formation,
`through which hydrocarbon can flow to the wellbore.
`In practice, fracturing a well is a highly complex opera—
`tion performed with precise and exquisite orchestration of
`equipment, highly skilled engineers and technicians, and
`powerful integrated computers monitoring rates, pressures,
`volumes, etc. During a typical fracturing job, large quantities
`of materials often in excess of a quarter of a million gallons
`of fluid, will be pumped at high pressures exceeding the
`minimum principal stress down a well to a location often
`thousands of feet below the surface.
`
`Thus, once the well has been drilled, fractures are often
`deliberately introduced in the formation, as a means of
`stimulating production, by increasing the effective wellbore
`radius. Clearly then, the longer the fracture, the greater the
`effective wellbore radius. More precisely, wells that have
`been hydraulically fractured exhibit both radial flow around
`the wellbore (conventional) and linear flow from the
`hydrocarbon-bearing formation to the fracture, and further
`linear flow along the fracture to the wellbore. Therefore,
`hydraulic fracturing is a common means to stimulate hydro-
`carbon production in low permeability formations.
`In
`addition, fracturing has also been used to stimulate produc-
`tion in high permeability formations. Obviously, if fractur-
`ing is desirable in a particular instance,
`then it is also
`desirable, generally speaking, to create as large (i.e., long) a
`fracture zone as possible—e.g., a larger fracture means an
`enlarged flowpaths from the hydrocarbon migrating towards
`the wellbore and to the surface.
`
`The Prior Art
`
`The present Invention combines disparate technologies
`from the prior art, which when combined, produce unex-
`pectedly superior results—as evidenced by results obtained
`in an actual field setting, which shall be discussed later.
`The prior art upon which the present Invention is based is
`the general teaching of the shooting perforations oriented in
`the direction in which the fracture is most likely to propa-
`gate. This way, potentially large pressure drops caused by
`the tortuous flowpath that the fluid must take, are eliminated,
`in turn allowing the well operator to perform fracture
`treatments. (See, e.g., H. H. Abass, et al., Oriented Perfo-
`rations: A Rock Mechanics View, SPE 28555 (1994); C. H.
`Yew and Y. Li, Fracturing of A Deviated Well, SPE 16930
`(1987), both papers are hereby incorporated by reference in
`their entirety).
`A second major area of prior art subsumed in the present
`Invention is low viscosity fracturing fluids. In particular,
`such low viscosity fracturing fluids include water and vis-
`coelastic surfactant-based fracturing fluids. (See, e.g., US.
`Pat. No. 5,551,516, Hydraulic Fracturing Process and
`Compositions, assigned to Schlurnberger). These unique
`viscoelastic surfactant-based fracturing fluids shall be
`described in more detail later.
`
`SUMMARY OF THE INVENTION
`
`The novelty of the present Invention resides in the com-
`bination of the steps of properly orienting perforations in a
`well casing relative to pre-determined stress fields, so that
`the perforations are aligned in the direction of likely fracture
`propagation plus the stop of creating a proppcd fracture by
`means of a low viscosity fracturing fluid.
`Preferred embodiments of the present Invention are
`directed to fracturing treatments in very tight gas-producing
`
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`US 6,508,307 B1
`
`3
`formations, and in particular, those having very high stress
`contrasts between the producing zones and the bounding
`layers.
`The present Invention possesses numerous very signifi-
`cant advantages over the prior art. These shall be explained
`below.
`
`Afracture will propagate in the direction perpendicular to
`the formation’s minimum in situ stress. If the perforations
`are not oriented in that direction, the fracturing fluid does not
`take the most direct route into the fracture. Instead, the fluid
`exits the perforation (under tremendous pressure) and begins
`to fracture the formation directly opposite the perforation.
`Eventually, the fluid is redirected towards in the direction of
`maximum in situ stress (i.e., the path of least resistance); it
`is in this direction that the major fracture eventually propa—
`gates. Hence, the lluid—rather than travelling in the most
`direct route (from the perforation directly into the formation)
`takes a more tortuous route into the formation. This effect—
`often referred to as “near—wellbore tortuosity” iis highly
`undesirable. (It is also well documented in the literature, see,
`e.g., R. G. van de Ketterij and C. J. de Pater, Impact of
`Perforations 0n Hydraulic Fracture Tortuosity, 14(2) SPE
`Prod. & Facilities 131 (1999). The reason is that near—
`wellbore tortuosity leads to often large pressure losses—in
`other words, as the fluid is redirected from its immediate exit
`to the direction in which it eventually travels, its pressure
`understandably decreases. In response to this adverse effect,
`the fluid must be initially pumped at higher pressures than
`are actually required (if the perforations had been optimally
`aligned). Higher pumping pressures require greater horse-
`power and therefore increase the cost of the treatment. Aside
`from higher pumping pressures, another response is to use a
`higher viscosity fluid (higher than is ordinarily needed to
`deliver the proppant). Yet higher viscosity fluids also require
`greater horsepower to pump, but more significantly, they are
`more damaging to the newly propped fracture because the
`fluid is difficult to remove from the placed proppant pack.
`And aside from this, higher viscosity fluids tend, on average,
`to be require additional breakers, thus further increasing the
`cost of the treatment.
`
`the primary advantage of
`Again, as we have stated,
`properly oriented perforations is that it allows lower pump-
`ing pressures,
`thus increasing treatment cost. In addition
`though, this allows the use of lower viscosity fluids. In the
`present Application, we have found that particular types of
`low viscosity fluids when used in conjunction with precisely
`oriented perforations, give rise fractures of surprising effec-
`tiveness. By “effectiveness” we mean fractures of optimum
`height—substantial height yet still that do not reach the
`bounding (non-producing) layers; and optimum length. The
`enhanced length is due to the remarkable ability of the fluids
`of the present Invention to clean—up, or be removed from the
`fracture after the fluid has successfully delivered the prop-
`pant. As we shall demonstrate, the conventional polymer-
`based fluid, under the same conditions, would give rise to a
`fracture out of zone (based on computer modeling results).
`BRIEF DESCRIPTION OF THE FIGURES
`
`FIG. 1 is a diagram of an embodiment of a tool string
`positioned in a cased wellbore.
`FIG. 2 (2A and 2B) are diagrams of tool strings according
`to one embodiment used to perform natural orientation.
`FIG. 3 is a diagram of a tool string according to another
`embodiment
`that
`includes an inclinometer sonde and a
`
`motor capable of rotating portions of the tool string.
`FIG. 4 is a diagram of a modular tool string according to
`a further embodiment that is capable of connecting to a
`number of different sondes.
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`FIGS. 5 and 6 illustrate position devices in the tool strings
`of FIGS. 2A and 2B.
`
`FIG. 7 illustrates relative bearing and azimuthal angles
`associated with a downhole tool.
`
`DETAILED DESCRIPTION OF THE
`PREFERRED EMBODIMENTS
`
`The present Invention is particularly applicable in reser-
`voirs that meet certain criteria,
`in particular: very low
`permeability (typically gas) and high stress contrasts
`between the pay zone and the confining zones.
`A principal benefit of the present Invention is that in tight
`gas wells,
`the well operator can attain a more effective
`fracture. By “more effective” we mean that
`the fracture
`height is controlled so that it is confined to the pay zone, and
`also that the fracture length is maximized. By maximizing
`fracture length we are referring to the effective fracture
`length, which is nearly always diminished in polymer-based
`fluid treatments due to stagnant fluid which remains in the
`fracture tip, thus reducing the effective fracture length far
`below the true fracture length. The fluids of the present
`Invention exhibit far better “clean-up,” i.e., they are more
`easily removed (flowed back) from the fracture. Therefore,
`fracture effectiveness is maximized—its height is carefully
`controlled so that does not break out of zone and the length
`is maximized due to superior fluid clean up.
`
`The Preferred Perforation Orienting Systems
`In the following description, numerous details are set
`forth to provide an understanding of the present invention;
`however, it will be understood by those skilled in the art that
`the present invention may be practiced without these details
`and that numerous variations or modifications from the
`
`described embodiments may be possible. For example,
`although reference is made to perforating strings in some
`embodiments, it is contemplated that other types of oriented
`downhole tool strings may be included in further embodi-
`ments. Some methods and apparatus for orienting downhole
`tool strings are presented in US. Pat. application Ser. No.
`09/292,151, Orienting Downhole Tools, which is incorpo-
`rated herein in its entirety.
`Referring to FIG. 1, a formation zone 102 having pro—
`ducible fluids is adjacent a wellbore 104 lined with casing
`100. The location of the formation zone 102 and its stress
`
`characteristics (including the minimum and maximum stress
`planes) may be identified using any number of techniques,
`including open hole (OH) logging, dipole sonic imaging
`(DSI), ultrasonic borehole imaging (UBI), vertical seismic
`profiling (VSP), formation micro-imaging (FMI), or the
`Snider/Halco injection method (in which tracers are pumped
`into the formation 102 and a measurement tool is used to
`
`detect radioactivity to identify producible fluids).
`Such logging techniques can measure the permeability of
`the formation 102. Based on such measurements, the depth
`of a zone containing producible fluids can be determined.
`Also, the desired or preferred fracture plane in the formation
`102 can also be determined. The preferred fracture plane
`may be generally in the direction of maximum horizontal
`stresses in the formation 102; however, we contemplate that
`a desired fracture plane may also be aligned at some
`predetermined angle with respect to the minimum or maxi-
`mum stress plane. Once a desired fracture plane is known,
`oriented perforating equipment 108 may be lowered into the
`wellbore to create perforations that are aligned with the
`desired plane.
`In another embodiment, oriented perforating may also be
`used to minimize sand production in weak formations. In
`
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`US 6,508,307 B1
`
`5
`addition, oriented perforating may be used to shoot away
`from other downhole equipment to prevent damage to the
`equipment, such as electrical cables, fiber optic lines, sub-
`mersible pump cables, adjacent production tubing or injec—
`tion pipe, and so forth. Oriented perforating may also be
`practiced for doing directional squeeze jobs. If the current
`surrounding the pipe contains a void channel, the direction
`of that channel can be determined using a variety of methods
`and tools such as the USIT (Ultrasonic Imaging Tool). Once
`the direction is known, oriented perforating may be executed
`accordingly. Further embodiments may include oriented
`downhole tools for other operations. For example, other
`downhole tools may perform oriented core sampling for
`formation analysis and for verification of a core’s direction,
`for setting wireline-conveyed whipstocks, and for other
`operations.
`With a vertical or near vertical wellbore 104 having a
`shallow angle of trajectory (e.g., less than about 10°), it may
`be diflicult to use the force of gravity to adjust the azimuthal
`orientation of a perforating gun string or other tool string
`carried by a non-rigid carrier (e.g., wireline or slick line)
`from the surface. According to some embodiments of the
`invention, an oriented perforating string includes an orient-
`ing mechanism to orient the perforating string in a desired
`azimuthal direction. It is contemplated that some embodi-
`ments of the invention may also be used in inclined well-
`bores.
`
`Several different embodiments of oriented perforating
`equipment are described below. In a first embodiment, a
`“natural orientation” technique is employed that is based on
`the principle that the path of travel and position of a given
`tool string (or of substantially similar strings) within a given
`section of a well
`is generally repeatable provided that
`steering effects from the cable (e.g., cable torque) are
`sufficiently eliminated (e.g., by using a cable swivel). It may
`also be necessary to keep most operational and tool condi-
`tions generally constant. Such conditions may include the
`following, for example: components in the tool string;
`length of tool string; method of positioning (e.g., lowering
`and raising) the tool string; and so forth. Thus, in the natural
`orientation technique, a first orientation string including a
`positioning device may be run in which a measurement
`device can determine the position and orientation of the
`string after it has reached its destination. The positioning
`device in one embodiment may be a mechanical device (e.g.,
`including centralizing or eccentralizing arms, springs, or
`other components). In another embodiment, the positioning
`device may be an electrical or magnetic device. Once the
`natural orientation of the tool string is determined based on
`the first trip, the tool’s angular position may be adjusted
`(rotated) at the well surface to the desired position. Asecond
`run with a tool string including a positioning device is then
`performed by lowering the tool string into the wellbore,
`which tends to follow generally the same path.
`In a variation of this embodiment, it may be assumed that
`in wells that have suflicient inclination (e.g., perhaps about
`20° or more), the positioning device will position the tool
`string at some relationship with respect to the high or low
`side of a wellbore once the tool string has been lowered to
`a predetermined depth. An oriented device in the tool string
`may then be angularly aligned at the surface before lowering
`into the wellbore so that the oriented device is at substan-
`tially a desired orientation once it is lowered to a given
`wellbore interval. In this variation, one run instead of two
`runs may be used.
`In other embodiments, a motorized oriented tool string
`includes a motor and one or more orientation devices
`
`6
`lowered into the wellbore, with the tool rotated to the desired
`azimuthal or gravitational orientation by the motor based on
`measurements made by the orientation devices.
`Referring to FIGS. 2A—2B, tools for performing natural
`orientation of downhole equipment (such as a perforating
`string) are shown. In one embodiment, natural orientation
`involves two runs into the wellbore 104.
`In another
`embodiment, natural orientation may involve one run into
`the wellbore. In the embodiment involving two runs, a first
`run includes lowering an orientation string 8 (FIG. 2A) into
`the wellbore to measure the orientation of the string 8. Once
`the orientation of the tool string 8 is determined based on the
`first trip, the angular position of device 28 may be adjusted
`(rotated) with respect to the tool string 8 at the well surface
`to the desired position.
`Next, a tool string 9 (FIG. 2B), which may be a perfo-
`rating string, for example, is lowered downhole that follows
`substantially the same path as the orientation string 8 so that
`the tool string 9 ends up in substantially the same azimuthal
`position as the orientation string 8. Thus, the first trip is used
`for determining the natural orientation of the tool string 8
`after it has reached a given interval (depth), while the second
`trip is for performing the intended operation (e.g.,
`perforating) in that interval after the tool string 9 has been
`lowered to the given interval and positioned in substantially
`the same natural orientation.
`
`On the first trip, a gyroscope device 10 may be included
`in the string 8 to measure the azimuthal orientation of the
`string in the wellbore interval of interest. An inclinometer
`tool 25 which can be used for providing the relative bearing
`of the orientation string 8 relative to the high side of the
`wellbore may also be included in the string. A few passes
`with the orientation string 8 can be made, with the relative
`bearing and azimuthal orientation information measured and
`stored in a log. Each pass may include lowering and raising
`the orientation tool string 8 one or more times. The tool
`positions for the up and down movements in a pass may be
`different. The direction (up or down) in which better repeat-
`ability may be achieved can be selected for positioning the
`tool.
`
`The orientation string 8 and the tool string 9 are designed
`to include as many as the same components as possible so
`that the two strings will substantially follow the same path
`downhole in the wellbore. On the second trip, the gyroscope
`device 10 may be removed from the string 9, but
`the
`remaining components may remain the same. Next,
`the
`device (e.g., a perforating gun 28) in the tool string 9 for
`performing the desired operation is oriented, at the surface,
`to place the device at an angular position with respect to the
`rest of the string 8 based on the natural orientation deter-
`mined in the first
`trip. Any special preparation such as
`arming guns may also be performed prior to re-entering the
`well for the second trip. The inclinometer tool 25 may
`remain in the tool string 9 to measure the relative bearing of
`the tool string 9 to determine if tool string 9 is following
`generally the same path as the orientation string 8.
`Removal of the gyroscope device 10 is performed to
`reduce likelihood of damage to the gyroscope. However,
`with a gyroscope that is capable of withstanding the shock
`associated with activating a perforating gun 28, the gyro-
`scope device 10 may be left in the string 9. Further, in
`oriented downhole tools that do not perform perforation, the
`gyroscope may be left
`in the tool string as the shock
`associated with perforating operations do not exist.
`The gyroscope device 10 in the orientation string 8 is used
`to identify the azimuthal orientation of the string 8 with
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`US 6,508,307 B1
`
`7
`the
`In one example embodiment,
`respect to true north.
`gyroscope device 10 may be coupled above a perforating
`gun 28. Weighted spring positioning devices (W'SPD) 14A
`and 14B are coupled to the perforating gun 28 with indexing
`adapters 18A and 18B, respectively. The indexing adapters
`18A and 18B may allow some degree (e.g., 5°) of indexing
`between the gun 28 and the rest of the tool string. Based on
`the desired orientation of the gun 28 with respect to the rest
`of the string, the gun 28 can be oriented by rotating the
`indexing adapters 18A and 18B to place the gun 28 at an
`angular position with respect to the rest of the string 9 so that
`the gun 28 is at a desired azimuth orientation once the string
`9 reaches the target wellbore interval.
`According to some embodiments, one or more WSPDs 14
`are adapted to steer the string in a natural direction and to
`reduce the freedom of transverse movement of the orienta-
`tion string 8 as it is lowered in the wellbore 104. The WSPD
`14A is located above the gun 28 and the WSPD 14B is
`located below the gun 28.
`In each WSPD 14, one side is made heavier than the other
`side by use of a segment with a narrowed section 30 and a
`gap 32. Thus, in a well having some deviation (e.g., above
`1° deviation), the heavy side—the side with the narrowed
`section 30—of the WSPD 14 will seek the low side of the
`
`wellbore 104. Each WSPD 14 also has a spring 16 on one
`side that presses against the inner wall 106 of the casing 100
`to push the other side of the WSPD 14 up against the casing
`100. The WSPDs also reduce the freedom of movement of
`
`the orientation string 8 by preventing the orientation string
`8 from freely rotating or moving transversely in the wellbore
`104. The offset weights of the WSPDs 14A and 14B aid in
`biasing the position of the tool string 8 to the low side of the
`wellbore 104.
`The inclinometer tool 25 includes an inclinometer sonde
`
`inclinometer sonde)
`(such as a highly precise bi-axial
`attached by an adapter 12 to the gyroscope device 10 below.
`The inclinometer tool 25 may also include a CCL (casing
`collar locator) that is used to correlate the depth of the
`orientation string 8 inside the casing 100. As the orientation
`string 8 is lowered downhole, the inclinometer sonde pro-
`vides relative bearing information of the string 8 and the
`CCL provides data on the depth of the tool string 8. Such
`data may be communicated to and stored at the surface (or,
`alternatively, stored in some electronic storage device in the
`tool string 8) for later comparison with data collected by an
`inclinometer sonde in the gun string 9. If the relative bearing
`data of the orientation string 8 and the gun string 9 are about
`the same, then it can be verified that the gun string 9 is
`following substantially the same path as the orientation
`string 8.
`Referring to FIG. 7, the azimuthal angle of the tool string
`8 or 9 can be defined as the angle between north (N) and a
`reference (R)
`in the inclinometer tool 25. The relative
`bearing angle of each of the orientation string 8 and tool
`string 9 is measured clockwise from the high side (HS) of
`the wellbore 104 to the reference (R) in the inclinometer tool
`25. In one embodiment, the reference (R) may be defined
`with respect to one or more longitudinal grooves 50 in the
`outer wall of the inclinometer tool 25. The positions of the
`sensor(s) in the inclinometer tool 25 are fixed (and known)
`with respect to the longitudinal grooves 50. Further, when
`the string 8 or 9 is put together, the position of the compo-
`nents of the string 8 or 9 in relation to the grooves 50 are also
`known.
`
`10
`
`15
`
`30
`
`35
`
`40
`
`45
`
`50
`
`55
`
`60
`
`65
`
`8
`to keep torque applied to the carrier 26 from swiveling the
`orientation string 8 as it is being lowered downhole, a swivel
`adapter 24 may be used. The carrier 26 is attached to the
`string 8 by a carrier head 20, which is connected by an
`adapter head 22 to the swivel adapter 24. The swivel adapter
`24 in one example may be a multi-cable or a mono-cable
`adapter, which decouples the tool string 8 from the carrier 26
`(torsionally). Thus, even if a torque is applied to the carrier
`26,
`the orientation string 8 can rotate independently.
`Alternatively, the swivel adapter 24 can be omitted if the
`elasticity of the non-rigid carrier 26 allows the carrier to
`follow the tool string 8 as it is rotating in traversing the path
`downhole.
`
`The orientation string 8 is lowered according to a prede-
`termined procedure from the surface. The steps used in this
`procedure are substantially repeated in the second run of the
`natural orientation technique to achieve the same positioning
`in the second run. The orientation of the string 8 as it makes
`entry into the wellbore 104 is known. The equipment for
`lowering the string 8 is also known. As the orientation string
`8 is lowered downhole, the string naturally positions itself in
`the hole. According to one procedure, the orientation string
`8 is lowered downhole past the well interval defined by the
`formation zone 102. The orientation string 8 may then be
`raised back up to the interval and measurements taken using
`the gyroscope device 10 and inclinometer sonde and CCL 25
`to determine the position of the orientation string 8. This
`procedure can be repeated several times with the orientation
`string 8 to ensure repeatability of orientation.
`There may be cases where the orientation string 8 may not
`be able to go past the interval defined by the formation zone
`102, such as when other equipment are located further
`below. In such cases, a modified procedure can be used, such
`as lowering the orientation string 8 into the interval,
`stopping, making the measurement, and then raising the
`string.
`the orientation
`After measurements have been made,
`string 8 is raised out of the wellbore 104. At the surface,
`before the second run is made, the gyroscope device 10 may
`be removed. All other components can remain the same as
`those in the orientation string 8. Like components have the
`same reference numerals in FIGS. 2A and 2B.
`
`In the tool string 9, the indexing heads 18A and 18B may
`be rotated to adjust the perforating gun 28 to point in the
`desired direction. The oriented tool string 9 is then lowered
`downhole following the same procedure used for the orien-
`tation string 8. Because the components of the two strings
`are substantially the same, the strings will tend to follow the
`same path. The inclinometer tool 25 (including the incli-
`nometer sonde and CCL) in the gun string 9 can confirm if
`the string 9 is following about the same path as the orien—
`tation string 8. If the comparison of the relative bearing data
`indicates a sufficiently significant difference in the travel
`path, the gun string 9 may be pulled out, repositioned, and
`lowered back into the wellbore 104.
`
`Further, if desired, additional components (such as a sub
`27 in FIG. 2B) may be connected in the oriented tool string
`9 to make it be about the same length as the orientation string
`8. Tests have shown that repeatability of orientation of the
`strings is good. For example, in a slightly deviated well,
`such as an about 1° well, variation of about 7° in the
`orientation of the gun strings was observed over several
`runs. Any variation below 110° may be considered accept—
`able.
`
`The tool string 8 may be attached at the end of a non-rigid
`carrier 26 (e.g., a wireline or slick line). In one embodiment,
`
`In alternative embodiments, the order of the components
`in tool strings 8 and 9 may be varied. Further, some
`
`Page 10 of 15
`Page 10 of 15
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`

`US 6,508,307 Bl
`
`9
`components may be omitted or substituted with other types
`of components. For example, the CCL may be part of the
`gyroscope device 10 instead of part of the inclinometer tool
`25. In this alternative embodiment, when the gyroscope
`device 10 is taken out to form tool string 9, a CCL may be
`put in its place.
`In a variation of the natural orientation embodiment, one
`run instead of two may be employed to perform oriented
`downhole operations. If a desired fracture plane or some
`other desired orientation of a downhole device is known
`beforehand, an oriented device (such as a perforating gun)
`may be angularly positioned with respect to the WSPDs 14
`at the surface. The WSPDs 14 will likely guide the tool
`string to a given orientation with respect to the high side of
`the wellbore. Thus, when the tool string is lowered to the
`targeted wellbore interval, the oriented device in the tool
`string will be at
`the desired orientation. This may be
`confirmed using an inclinometer, for example.
`Referring to FIG. 5, a more detailed diagram of the upper
`WSPD 14A is illustrated. The housing 200 of the WSPD
`14A has a threaded portion 202 at a first end and a threaded
`portion 204 at the other end to connect to adjacent compo-
`nents in the orientation or tool string 8 or 9. A connector 206
`may be provided at the first end to receive electrical cables
`and to route the electrical cables inside the housing 200 of
`the WSPD 14A, such as through an inner bore 208.
`As illustrated, the upper WSPD 14A includes a segment
`having the narrowed section 30A and the gap 32A. The
`eccentering spring 16A that
`is generally parabolically
`shaped is attached to one side of the housing 200 of the
`WSPD 14A. In one embodiment, the spring 16A may be
`attached to the housing 200 by dowel pins 210. In another
`embodiment, the spring 16A may be made with multiple
`layers. A wear button 212 may also be attached to the
`centering spring 16A gen