Patent CA-2915601-A1 (CA)
Inventor: MARCIN JOZEPH R
IPC: E21B33/16
Filed: 2015-12-21
Abstract: facing drop plug seat surface is defined on or adjacent a free uphole end of the sleeve. The inner mandrel or outer housing form an uphole facing stop surface that contacts a downhole facing surface of the sleeve when the inner mandrel is in the second position.  The downhole valve is structured to expose a bypass across the inner mandrel at least upon receipt of, and application of fluid pressure in an uphole direction against, an object on a downhole facing restriction surface defined within the interior bore. The inner mandrel comprises a cylindrical stem part mounted to slide axially within a receptacle, defined within the interior bore, between a seated position against an uphole facing stop surface and an unseated position where the bypass across is exposed. The bypass is defined in part or in whole by a plurality of grooves in the downhole facing restriction surface between an uphole end and a downhole end of the downhole facing restriction surface. When the downhole valve is closed by the second drop plug; pressurizing fluid in the well to an extent sufficient to open a port to an exterior of the downhole valve; and pumping fluid through the port into the exterior of the downhole valve at or above a fracturing pressure of the formation. The downhole valve comprises a sleeve part in the interior bore, and during actuation: a first deflector part pushes a downhole facing surface of the sleeve part radially outward to defeat an uphole facing actuator surface to pass the first drop plug; and a second deflector part pushes the sleeve part radially inward to form the uphole facing drop plug seat surface. [0017]     These and other aspects of the device and method are set out in the claims, which are incorporated here by reference. BRIEF DESCRIPTION OF THE FIGURES [0018]     Embodiments will now be described with reference to the figures, in which like reference characters denote like elements, by way of example, and in which: [0019]     reference characters denote like elements, by way of example, and in which: [0020]     Fig. 1 is a section view of a frac ball. [0021]     Figs. 1A-1F are section views of various frac ball embodiments, with cross-hatching omitted for clarity, and dashed lines used to represent a) the contact area the ball makes with the seat in use, and b) the radial sizes of the ring part and rod part. [0022]     Fig. 2 is an end elevation view of the ball depicted in Fig. 1.     carbon or glass fiber. Referring to Fig. 1, when the composite makes up the rod or pin part 14, plural layers 34 may run with at least one directional component oriented along an axis 16 defined by the interior bore of the ring part, for example if layers 34 run parallel to axis 16 as shown. In one case the layers 34 run up to sixty degrees offset axis 16.  Referring to Fig. 3, when the composite makes up the ring part 12, plural layers 34 may run with at least one directional component, defined by the layers 34, perpendicular to an axis 38 defined by the rod part 14, for example if layers 34 are perpendicular to axis 38. In one case the layers 34 run between ninety and thirty degrees offset axis 38. Orientation of layers 34 as above may be advantageous when the composite used is anisotropic, i.e. stronger in some directions than in others. Anisotropic layered materials may be shear-sensitive across the interface between layers 34. Thus, by orienting layers 34 in the manners shown in Figs. 1 and 3, the seat surface 29 will never impart a force whose entire magnitude is directed against and parallel to the layers 34. The adhesive polymer may comprise polyether ether ketone (PEEK), Torlon, Teflon, PGA polyglycolic acid, plastic, or other suitable materials or epoxies. Glass, carbon, or other fillers may be added to increase the strength of the composite. In some cases between 20 and 60% filler may be used, for example 30% glass fibers, with GIO discussed below having 50% glass in one case. The composite may have a sufficient number of layers 34, such as 1000 layers of glass weave. The adhesive polymer may be injected into the fiber, particulate, or woven filler matrix under pressure, to wet the fibers. The resulting matrix provides the strength of glass in tension with the strength of epoxy under compression, and lacks the brittleness of the initial glass or carbon fiber. [0050]     Suitable composite materials may be chemically resistant, non-conductive, and resistant to degradation, such as by being insoluble in downhole fluids and acid so as to not degrade when contacted by wellbore fluids. Suitable materials include G10 and FR-4.  Such materials may have relatively high strength, low moisture absorption, excellent electrical properties and chemical resistance. FR-4 and G 10 are grade designations assigned to glass-reinforced epoxy laminate sheets, tubes, rods and printed circuit boards (PCB). FR-4 is a composite material composed of woven fiberglass cloth with an epoxy resin binder that is flame resistant (self-extinguishing). The "FR" stands for flame retardant, and denotes that safety of flammability of FR-4 is in compliance with the standard UL94V-0. FR-4 is created [0053]     Downhole valves [0054]     If the well or tubing contains plural downhole valves, plugs of various sizes may be used to each target a particular downhole valve. In such a case each plug 10 will be small enough so that it will not seal against any of the seats it encounters prior to reaching the desired seat. For this reason, the smallest ball to be used for the planned operation is often the first ball placed into the well or tubing and the smallest ball seat is positioned in the well or tubing the furthest from the wellhead, for example at the toe end of a deviated well.  After the desired treatments are completed, the direction of fluid flow may be reversed so that the treating fluids and formation fluids may be produced through the wellhead. Because each plug is smaller than the seats past which it traveled, in theory the plugs are free to move in an uphole direction with the fluids through the previously passed plug seats and out of the well. [0055]     Downhole valves, which rely solely on the size of the plug and the seat opening for selecting the tool to actuate, limit the number of valves that can be used in a given tubing string, usually to around twenty to forty valves. In such systems each ball size is able to actuate a single valve and, each plug may have a diameter increase within a predetermined increment, such as 0.125 inches, larger than the immediately preceding plug.  The size of the liner, tubing, or well bore may thus restrict the number of valve assemblies that can be used with differently-sized ball seats. The diametrical clearance between the ball and the above seat may be for example between 0.002 to 0.030 inches, which may be smaller than the incremental diametric difference between balls. Such systems operate more efficiently when drop balls remain in tolerance when seated during the frac because then the balls can be retrieved. If such drop balls become deformed, retrieving the balls may be problematic, and if impossible the only recourse may be to drill or mill out the balls that are obstructing the tubing.. [0056]     Referring to Fig. 6, a downhole valve 54 is illustrated with an outer housing 40, and an inner mandrel 41, forming a compound seat. The outer housing 40 defines an interior bore 83. Mandrel 41 is mounted, for example by threaded connection as shown, in the interior bore 83. The inner mandrel 41 defines an interior passageway 46 between an uphole end 74 and a downhole end 76 of the inner mandrel 41. Referring to Figs. 6-8 in one embodiment the inner mandrel 41 has a first position (Fig. 6) where the inner mandrel 41 is actuatable by a first drop plug 50B to pass the first drop plug 50A downhole and shift to a second position (Fig. 8). Referring to Fig. 8, when shifting into the second position shown the inner mandrel 41 may form an uphole facing drop plug seat surface 84. Seat surface 84 may encircle the interior passageway 46 and may be sized to receive a second drop plug 50B  that has the same dimensions as the first drop plug 50A. In the embodiment shown, when in the seated position under pressure from uphole against a drop plug 50B, the fluid flow across the valve 54 is fully blocked. A mandrel may be a bar, shaft or spindle around which other components are arranged or assembled. The term mandrel has been extended in oil and gas well terminology to include tubular components that may or may not slide within the outer housing 40. [0057]     Referring to Fig. 6, the inner mandrel 41 may further comprise a sleeve part 86 mounted to shift along an axis 85 of the interior bore 83, for example in a downhole direction. When the inner mandrel 41 is in the first position, the sleeve part 86 may form an uphole facing actuator surface that is positioned to receive the first drop plug 50A. An example uphole facing actuator surface is a first uphole facing seat surface 82, which may have a consistent cross-sectional shape about axis 85, and may encircle the interior passageway 46 and be sized to receive first drop plug 50A as shown. Referring to Figs. 7-8, while the inner mandrel 41 is in the second position (Fig. 8), and in some cases while moving into (Fig. 7), the sleeve part 86 may form the uphole facing drop plug seat surface 82, which will be referred to as a second uphole facing drop plug seat surface 82 in distinction with first surface 84. [0058]     Referring to Figs. 6-7, the downhole valve 54 may comprise a first deflector part, such as a deflection ring 91, which may be a separate piece connected, for example by threading, to inner mandrel 41 or outer housing 40, or may be machined in place to the inner mandrel 41 or outer housing 40. Ring 91 may push, for example guide, the sleeve part 86 radially outward to defeat the first surface 84 to pass the first drop plug 50A. The ring 91 may be structured to contact, during actuation, a downhole facing surface, such as nose ramp 92, of the sleeve part 86 to push the sleeve part 86 radially outward.     [0059]     Referring to Figs. 6 and 7, when the inner mandrel 41 is in the first position, the ring 91 may stand in the path, for example in a downhole direction along axis 85, of the nose ramp 92. One or both the ring 91 and a downhole portion, such as nose ramp 92, of an outer wall 87 of the sleeve part 86 may be sloped to cooperate to push the sleeve part 86 radially outward when the inner mandrel 41 is moving from the first position to the second position. In the example shown, both nose ramp 92 and ring 91 are sloped.  Thus, an uphole facing surface 90 of ring 91 may be sloped radially outward with increasing distance from the nose ramp 92, and the downhole facing surface, such as nose ramp 92, may be sloped radially inward with increasing distance from the ring 91. The sloping of nose ramp 92 may extend to the first seat surface 82 as shown. The first deflector part need not be a ring 91, and may be a suitable deflection mechanism, such as dogs, balls, latches, pins, or guides. The use of a first deflector part, which operates using energy from the pressurized drop plug 50A, may act to reduce the pressure threshold, for example to less than 2000 psi and in some cases 1500 psi or less, required to shift from first to second position. Part of the reason for the reduced pressure threshold is that the first deflector part and second deflector part convert the axially directed force of the sleeve part 86, imparted by ball 50A, into lateral (radial) force to expand the seat 82 and contract the seat 84 while at the same time increasing such lateral force by a force advantage from the structures of the first and second deflector parts, for example shallow slope wedges as shown. In one case the pressure required to defeat the first seat 82 is 1500 psi or less, for example 1000 psi or less. Reducing the pressure threshold reduces the chance that ball 50A will be deformed during the pressure up. [0060]     Referring to Figs. 7-8, the outer housing (tool body) 40, or in this case the inner mandrel 41, may form a stop surface, such as uphole facing stop surface 93, that contacts a downhole facing surface, such as downhole end 94 of the sleeve part 86, when the inner mandrel 41 is in the second position. The stop surface 93 may form a downhole end wall of a recess 88 that extends radially outward from ring 91 in order to provide a channel for the downhole end 94 of sleeve part 86 to deflect radially outward into.  Once in contact with stop surface 93, further downhole axial movement of the sleeve part 86 is restricted, permitting a relatively larger capacity for pressure tolerance when seating drop plug 50B, as compared to if no stop surface were used. Recess 88 may be an annular groove within an interior cylindrical wall surface 95 of inner mandrel 41 or outer housing 40, the surface 95 providing a cylinder in which sleeve part 86 is permitted to slide axially. [0061]     Referring to Figs. 7-8, a second deflector part, such as a ramp part 100 within wall surface 95 of inner mandrel 41, may bend the sleeve part 86 radially inward to form the second seat surface 84. Second seat surface 84 may act as a bidirectional seat for balls 50A  and 50B, although in some cases sleeve part 86 is configured to reset to the first position after seating ball 50A under flow back and upon application of force in an uphole direction against ball 50A. Referring to Fig. 6, when the inner mandrel 41 is in the first position, one or both the ramp part 100 and the restriction 99 may stand in the path, for example in a downhole direction along axis 85, of an uphole portion, such as flared tail ramp 98, of an outer wall 87 of the sleeve part 86. Referring to Figs. 6-8, one or both the ramp part 100 and the tail ramp 98, in this case both, are sloped to cooperate to push the sleeve part 86 radially inward when the inner mandrel 41 is moving from the first position to the second position.  The second deflector part, for example ramp part 100, may be sloped radially inward with increasing distance from the tail ramp 98 of the outer wall 87, and the tail ramp 98 may be sloped radially inward, at least initially, with decreasing distance from the ramp part 100. [0062]     The second deflector part may comprise a cylindrical inner wall, such as wall surface 95 of restriction 99, that encircles the outer wall 87, and the second deflector part may have a part, such as ramp part 100, that narrows radially inward to the cylindrical inner wall 87 in the downhole direction. The outer wall 87 may conform to the shape of the cylindrical inner wall surface 95 in an axial direction, for example all the way between the restriction 99 and the uphole portion of the outer wall 87, at least when the inner mandrel 41 is in the second position. Such a configuration reduces or eliminates voids between sleeve part 86 and inner wall surface 95, increasing the structural integrity, and capacity, to withstand relatively higher pressures when the valve 54 is closed as compared to a valve 54 that has a void between wall surfaces 95 and 87. [0063]     In one case the second seat surface 84 may be defined on or adjacent a free uphole end 96 of the sleeve part 86. By positioning the second seat surface 84 on a free terminal end, there is relatively less resistance to the deformation that occurs to form seat surface 84 while shifting to the second position. Thus, the pressure threshold required to shift from first to second position is further reduced relative to a system that bends an intermediate part of sleeve part 86 inwards. [0064]     The compound seat sleeve part 86 may be made of a suitable material such as a ductile material. Ductile materials may be drillable or non-drillable, and include ductile cast iron or a medium strength aluminum alloy. Non-drillable and other hard materials may be used to make the compound seat sleeve part 86 without a significantly negative impact on drillability, because the sleeve part 86 may take up only a relatively small volume compared to the volume of the rest of the inner mandrel 41, which may comprise drillable materials such as ductile cast iron. [0065]     Referring to Fig. 9, the downhole valve 54 may be structured to expose a bypass 160 across the inner mandrel 41 at least upon receipt of, and application of fluid pressure in an uphole direction against, an object, such as first drop plug 50A, on a downhole facing restriction surface 128 defined within the interior bore 83. As shown, several options may be used for locating the bypass 160 within the interior bore 83. In one case the bypass 160 comprises a plurality of flow paths, such as grooves 126 in the downhole facing restriction surface 128, communicating between a downhole end 161 and an uphole end 162 of the downhole facing restriction surface 128. Referring to Figs. 12 and 24, different configurations, sizes, radial depths, and radial spacing between, grooves 126 may be used as is suitable to increase minimum flow area across the downhole facing restriction surface 128, to reduce and in some cases eliminate a pressure drop across the valve when a ball 50 lodges on surface 128. Referring to Fig. 9 the grooves 126 may be radially spaced about restriction surface 128. The bypass 160 may be defined such that the various paths, such as lines 130 or 114, that make up the bypass 160, all maintain axial directional continuity from the downhole end to the uphole end of the bypass 160, to reduce friction and pressure drop through purely lateral or other complex paths. Sloped surfaces and rounded corners and edges may be incorporated to further improve laminar flow across the bypass 160. In some cases interior passages may replace or supplement grooves 126. [0066]     Restriction surface 128 may encircle the interior passageway 46 to form a seat for a downhole object such as ball 50A returned under flow back. The downhole facing restriction surface 128 may connect adjacent, and be located in a downhole direction relative to, a restriction 163 in the interior passageway 46. The restriction 163 may form an inner cylindrical wall surface 164 that extends in an uphole direction to sleeve part 86 if present.  The restriction part 163 may form a close tolerance fit with a drop plug 50A  of a maximum size capable of passing through the downhole valve 54 in a downhole direction, for example capable of passing through sleeve part 86 when sleeve part 86 is in the first position. Thus, as long as ball 50A retains the initial shape ball 50A had when ball 50A  originally passed downhole valve heading downhole, under reverse flow the ball 50A ought to pass through restriction 163 freely, in order to be collected above surface to provide a relatively free flowing well bore. However, in many cases downhole drop plugs become plastically deformed as a result of the large pressures exerted upon such plugs during seating, pressure up, and fracturing. Once a ball 50A is deformed, such a ball 50A is likely to jam or otherwise lodge within cylindrical inner wall surface 164. [0067]     Referring to Figs. 8 and 9, the inner mandrel 41 may comprise a sleeve part, such as a stem part 58. The downhole facing restriction surface 128 may be located on the stem part 58. The stem part 58 may be cylindrical and mounted to slide, in piston fashion, axially within a receptacle 104. Receptacle 104 may be defined within the interior bore 83.  Under flow back pressure without the influence of a downhole object, or under flow back pressure with a downhole object such as drop plug 50A lodged against restriction surface 128, stem part 58 may slide in an uphole direction between a seated position (Fig. 8), where a downhole facing surface 168 such as is defined at a downhole end of sleeve part 58, seats, for example forms a pressure seal, against uphole facing stop surface 166, and an unseated position (Fig. 9) where the bypass 160 is exposed. Referring to Fig. 9, when in the unseated position surfaces 166 and 168 are axially separated. [0068]     Referring to Fig. 9, when the stem part 58 is a cylindrical stem, the interior wall, namely wall surface 164, of the stem part 58 may define part or all of the interior passageway 46 of the inner mandrel 41. The stern part 58 may be positioned coaxially within the outer housing 40 as shown. The receptacle 104 may be located on a collar part, such as housing 78 of inner mandrel 41 or as a part that integrally extends radially inward from outer housing 40. The collar part, such as housing 78, may have an uphole facing surface 170 that extends radially inward from an inner bore surface 118, of the outer housing 40, the inner bore surface 118 being positioned in an uphole direction related to surface 170. The uphole facing surface 170 may encircle an uphole end 172 of the receptacle 104. The surfaces 170 and 118 may define a recess, such as an annular recess 174 with a wider diameter than the receptacle 104, and the inner mandrel 41 may further comprise a centralizer flange 204. The flange 204, seat surface 84, and stem part 58 may be referred to as a check seat. The stem part 58 may be mounted to freely slide into or out of receptacle 104 under varying pressure differentials across the inner mandrel 41. Housing 78 may share a threaded connection 79 with outer housing 40, and may be provided as a separate module that can be inserted, removed, and retrofitted, into a housing 40. [0069]     Referring to Figs. 9, 10, and 11, the centralizer flange 204 may be defined by a plurality of fins 108, that extend radially outward from an uphole end 175 of the stern part 58 toward the inner bore surface 118 into the annular recess 174. The centralizer flange may have or define an axial passage or passages, such as is defined by the gaps 200 between a plurality of fins 108 radially spaced from one another, the fins 108 forming part of the centralizer flange. Gaps 200 may define part or all of the bypass 160. Thus, upon surface 128 seating ball 50A under flow back, pressure from downhole acts against ball 50A  and translates ball 50A and stem 58 together in an uphole direction. Referring to Fig. 9, once stem 58 clears uphole end 170 of housing 78, or at an earlier point if housing 78 defines bypass grooves or interior passageways in the receptacle 104 wall or interior to the uphole end 170, bypass 160 is defined within the annular space between stem part 58 and inner wall 118, and in the gaps 200 between fins 108. A downhole facing stop surface 112 may be located in the interior bore 83 in an uphole direction from the receptacle 104 for contacting an uphole facing surface 110, and restricting uphole travel, of the centralizer flange. Such a structure leverages the relative large flow area in the outer annulus between the stem 58 and surface 118. The centralizer flange also acts to centralize the stem part 58, such that, on normal flow in a downhole direction, the stem part 58 is able to center and enter the receptacle 104, if the stem part 58 has for whatever reason unseated itself from the receptacle 104. Such structure also permits re-setting, at least in embodiments that lack a compound seat that cannot be shifted back into the first position under reverse flow.  Each fin 108 may define an outer wall surface 116 that contacts and slides along surface 118 and may provide the centralizing function of the centralizing flange. An uphole facing surface 197 of each fin 108 may be sloped radially inward with decreasing distance downhole. One or both the leading downhole facing surfaces 202 of stem 58 may be sloped radially inward with decreasing distance from surface 166 or the uphole facing surface 170 of housing 78 may be sloped radially inward with increasing distance from the stem part 58, to funnel or guide the ball 50 into the interior passageway 46. [0070]     Referring to Figs. 12 and 13, an example is illustrated of a valve 54 that incorporates stern part 56 and housing 78 but lacks the compound seat of valve 54 from Fig.  6. Thus, valve 54 is not able to pass a ball of the same diameter required to seat the valve 54.  Referring to Fig. 25, a further embodiment of a valve 54 is shown lacking a compound seat but having a bypass in the form of grooves 126 in a downhole facing restriction surface 128 in a housing 78 threaded to outer housing 40. Referring to Figs. 24 and 26, embodiments of valve 54 with a compound seat sleeve part 86 are shown, but lacking a cylindrical stem part 58 and receptacle 104. The Fig. 26 embodiment lacks a bypass 160 altogether.  In some stages bypass 130 may be eliminated to ease manufacturing. In some cases bypass 114 provides a greater minimum flow area than bypass 130. [0071]     In some cases the valve 54 may incorporate stem part 56 and receptacle 104 to define bypass path 114 when stem part 56 is unseated, but with or without grooves 126 or bypass path 130. When a drop plug is landed on a seat and pressured up at some point the drop plug can start to plastically deform, subsequently requiring a reverse pressure of 2000, 5000 psi, or more to unseat, particularly if the drop plug becomes extruded into the seat bore.  One advantage of having a compound seat and bypass path 114 is that if the drop plug becomes stuck on the uphole facing seat surface 84 during pressure up, internal bypass is still possible without unseating the drop plug because flow back pressure need only dislodge stem part 56 to expose bypass path 114 in order to overcome the blockage. In some cases if the drop plug is stuck on seat 84 the stem part 56 requires lower pressure to unseat than the drop plug requires to unseat from the seat 84. For example, the stem part 56 may require 500 or less, for example 200-400 psi, to unseat. By contrast, in an example with a compound seat and only bypass 130, if the drop plug became stuck on the seat no internal bypass is possible without first unseating the drop plug under pressure.     [0072]    The bypass 160, for example annulus 106, grooves 126, or both combined, may have a minimum cross-sectional flow area that is equal to 0.3 or more times a minimum cross-sectional flow area of the interior passageway 46 of the inner mandrel 41. The minimum cross-sectional flow area of the interior passageway 46 is understood to be calculated when the restriction surface 128 has not been obstructed or blocked to any degree by a downhole object or drop plug. In the examples shown the minimum cross-sectional flow area of the interior passageway 46 of the unrestricted valve 54 is defined as the bore area bounded by the seat surface 84 in a plane perpendicular to the axis 85, and is referred to in Tables 1-3 below as the ball seat area. The minimum cross-sectional flow area of the flow path 114 is defined by the area of the annulus 106 in a plane perpendicular to the axis 85, and the minimum cross-sectional flow area of the flow path 130 is defined by the combined cross-sectional areas of the grooves 126 measured at the point along each groove 126 that represents the minimum flow area of each groove 126. Thus, when both annulus 106 and grooves 126 are present the minimum cross-sectional flow area of the bypass may be the combined flow areas of annulus 106 and grooves 126 (see Table 1). [0073]    In further cases the bypass 160 has a minimum cross-sectional flow area that is equal to one or more times, for example between one and ten times (see Table 1), the minimum cross-sectional flow area of the interior passageway 46 of the inner mandrel 41. In some cases all or a plurality of the valves 54 along the tubing string may incorporate bypasses that are sized to permit at or above the minimum flow areas discussed above. In some cases (Table 3) the minimum cross-sectional flow area defined by grooves 126 or the functionally equivalent structure is one or more times the minimum cross-sectional flow area of the passageway 46. For example, a tubing string may incorporate a series of valves arranged from smallest ball seat diameter at the toe end of the string, to largest ball seat diameter closest to the uphole end of the tubing string. In Table 3, a group of such valves in a string each define a bypass flow area (measured by grooves 126) that is one or more times the minimum flow area of the respective valve passageway 46, with the group including at least those valves whose ball seat diameters are 75% or less the maximum ball seat diameter of the valves in the string. As shown in Table 1, in some cases all of the valves in the string may have a bypass flow area that is one or more times the minimum cross-sectional flow area of the passageway 46 of the respective valve 54. As shown in Table 1, the use of grooves 126 and fins 108 / annulus 106 in the same valve 54 provide synergy by combining inner and outer bypass paths, across lines 130 and 114, respectively, in order to increase the flow rate across the valve 54, and reduce the impact of a lodged ball 50A, in some cases reducing such impact to the point where the valve 54 need not be drilled or milled out. In case drill or mill-out is still desired, drillable materials may be provided for the inner components of the valve 54, and a rotational lock 176 may be provided between the stem part 58 and the outer housing 40, for example between stem part 58 and housing 78 that threads to outer housing 40. Table 2 shows an example for a valve that either lacks grooves 126 or that has a ball 50B stuck on the uphole facing seat surface 84. [0074]     Table 1: Comparison of bypass flow area (inches2) available across downhole valves sized for various ball sizes, with the downhole valves incorporating bypasses through annulus 106 and grooves 126, and with a ball seated on the downhole facing restriction surface 128.    [0075]     Table 2: Comparison of bypass flow area (inches2) available across downhole valves sized for various ball sizes, with the downhole valves incorporating bypass through annulus 106, and with a ball seated on the uphole facing seat surface 84 so as to block grooves 126. This data would be the same if no grooves 126 were present and a ball were seated on the downhole facing restriction surface 128 instead of on the surface 84.    [0076]                                                                Table 3:  Comparison of bypass flow area (inches2) available across downhole valves sized for various ball sizes, with the downhole valves incorporating bypass through grooves 126 (no annulus 106), and with a ball seated on the downhole facing restriction surface 128.    [0077]     Referring to Figs. 14-23 and 27-28 the downhole valve 54 may be incorporated into a fracturing sleeve 65. Referring to Figs. 27-28, a fracturing sleeve 65 may operate as follows. A first drop plug 50A may be pumped down a well 44 (Fig.  14) through, and out a downhole end 76 of the downhole valve 54. If a compound seat such as sleeve part 86 is present, the drop plug 50A may actuate the sleeve part 86, for example by contacting first seat 82 in the first position to shift sleeve part 86 in the downhole direction (an intermediate position between the first and second positions is shown in Fig.  27), to form second seat surface 84 and move into the second position (shown in Fig. 28).  Referring to Fig. 28, a second drop plug 50B is then pumped down the well 44 to seat the second drop plug 50B on the second seat surface 84 to close the downhole valve 54. The second drop plug 50B may have the same dimensions as the first drop plug 50A if a compound seat such as sleeve part 86 is used, and otherwise the second drop plug 50B will have a larger diameter than plug 50A. [0078]     Referring to Fig. 28, from the second position the downhole valve 54 may be closed by the second drop plug 50B, by pressurizing fluid in the well 44 to an extent sufficient to open a port 73 to an exterior 180 of the downhole valve 54. The port 73 may open by a suitable mechanism such as follows. In the example shown the inner mandrel 41 may be mounted to slide axially within the outer housing 40 to expose the port 73. Thus, when in the initial position an outer sleeve housing 182 of mandrel 41 blocks port 73.  Housing 182 may mount housing 78, for example by a suitable method such as threaded connection. Opening of the port 73 may be initially restricted unless a pressure is applied above a predetermined threshold, such threshold being determined by a suitable mechanism such as pressure-rated shear pins 132 in correspondingly-shaped apertures 134.  Once pins 132 are sheared as shown, pressure in the valve 54 slides the mandrel 41 in the downhole direction, with downhole travel limited in some cases by contact between an uphole facing stop surface 138 of the outer housing 40 and a downhole facing surface 136 of inner mandrel 41. [0079]     A suitable lock, such as the combination of a split ring 140 and corresponding recess 142 in sleeve housing 182, may be provided to lock the inner mandrel 41 in the position shown after port 73 is opened. Referring to Figs. 27 and 28, a split ring 140 may be initially energized radially inward against a biasing force of the ring 140 to assume a compressed orientation within a recess 142 in sleeve housing 182, but as soon as downhole travel carries housing 182 to the point where recess 142 aligns with a recess 144 in the outer housing 40, ring 140 is permitted to radially expand to occupy parts of both recesses 142 and 144 to prevent further axial travel of sleeve housing 182. A rotational locking mechanism, such as a key 137 may be provided to engage part of outer housing 40, for example a key slot 139, in order to prevent relative rotation of inner mandrel 41 and outer housing 40 during drill or mill out. [0080]     Referring to Fig. 28, once seated and opened, fluid may be pumped down well 44 through the port 73 into the exterior 180 of the downhole valve 54, for example at or above a fracturing pressure of the formation, to treat the formation. Proppant or other treatment agents such as gel may be carried by the fluid into the formation as needed. [0081]     Once the fracturing operation is completed, the well 44 may be put under flow back or production, to permit fluids to flow in an uphole direction through valve 54.  Referring to Fig. 9, flow back may act to unseat the second drop plug 50B and lodge the first drop plug 50A or a downhole object on the downhole valve 54, exposing a bypass 160 as discussed above with reference to Fig. 9 and other embodiments. [0082]     The compound seat, if present, may be configured to move into the second position under a sufficiently lower pressure, for example 500 psi or lower, than the pressure required to open the frac sleeve, in order to avoid prematurely opening the frac sleeve. In one example, the frac sleeve is set to shear open at 2500 psi, the compound seat is set to collapse inward (second seat 84 - into the second position) at 1500 psi and release the ball on the ramp (first seat 82) at 1000 psi. Therefore, once the operator builds pressure to 1500 psi the seat 82 would collapse, the seat 84 would form, and the ball would be released nearly instantaneously. [0083]     Referring to Figs. 14-23, a series of views are provided to illustrate various stages of a multi-stage treatment operation incorporating downhole valves 54 incorporated within frac sleeves 65. Referring to Figs. 14-15, the tubing string 190 shown in the well 44 incorporates a series of downhole valves 54 arranged in the following repeating pattern in the uphole direction: a) a packer 66, such as hydraulic packer 66A, actuated to seal off the annulus between the well 44 and tubing string 190, b) a downhole valve 54, such as valve 54A containing a compound seat, c) a second packer 66, such as packer 66B, actuated to seal off the annulus between the well 44 and tubing string 190, and d) a downhole valve 54, such as valve 54B, lacking a compound seat. The alternation of compound seat valves with non-compound seat valves doubles, for example to forty, eighty, or more, the number of fracturing zones that can be isolated along a well 44 relative to a given tubing string 190 that lacks compound seats. [0084]     Operation of the embodiments of Figs. 14-23 may proceed as follows. Referring to Figs. 14-15, a drop plug 50A of a first size is pumped down the well 44 to seat upon valve 54A. The well 44 is pressured up to open port 73A in valve 54A, and the zone between packers 66A and 66B is fractured. Referring to Fig. 17, a drop plug 50B of the first size is then pumped down the well 44 to seat upon valve 54B, and the well pressured up to open port 73B and fracture the formation isolated between packers 66B and 66C.  Referring to Fig. 18, a drop plug 50C of a second size larger than the first size is then pumped down the well 44 to seat upon valve 54C and pressurized to open port 73C and fracture the zone isolated between packers 66C and 66D. Referring to Fig. 20, a further drop plug 50D of the second size is then pumped downhole to seat upon valve 54D, and pressurized to open port 73D and fracture the zone isolated between an uphole packer (not shown) and the packer 66D. Referring to Figs. 22 and 23, after the fracturing treatment is complete the flow is reversed in the well 44, unseating drop plugs 50A, B, C, and D, which are flowed to surface and collected. lf, as in the example shown, drop plugs 50A, 50B, and 50C are deformed, for example into an egg-shape, and become lodged within valves 54B, 54C, and 54D, respectively as shown, the plural bypass paths across each such valve reduces pressure drop across each valve 54 and prevents flow restriction in the well 44. If desired, the valves 54 can be drilled or milled out, or retained in place as flow back is not restricted. [0085]     Referring to Fig. 3, in one case the rod part 14 is made of stronger material than the ring part. An alloy may be a mixture of two or more elements in which the main component is a metal. The well 44 may be lined with casing with or without perforations, or may be an open hole. Vertical, deviated, and horizontal wells may be treated using the downhole valves disclosed here. The compound seat may be made of ductile material to reduce pressure setting thresholds. The metal part of the plug may be made of suitable materials such as metallic material, aluminum, aluminum alloy, zinc alloy, magnesium alloy, steel, brass, aluminum bronze, metallic nanostructure material, and cast iron or others. In some cases the stronger of the two structural materials may be made of ceramic. The non-metallic or weaker part of the plug may be made of suitable materials such as plastic, composite material, thermoplastic, hollow materials and others. [0086]     Downhole components may be tubular in shape. Each end of a downhole valve may incorporate a tubing string connector, such as a pin or box threaded connector.  Threaded connections, threading, and threads all refer to the same thing - a part that may be threaded to corresponding mating threads on a second component. Other components may be used that are not described, such as subs, sleeves, or other components, such as tubular spans of pipe between valves 54. Various seals, such as 101, 102, 199 and 201, may be provided between components, such as o-rings, packing, or other gaskets. Slips, wickers, plugs, shear-operated packer components, and other components may be used. The tubing string may comprise coiled or jointed tubing. All bores may be cylindrical, may have cylindrical and non-cylindrical parts, or may be non-cylindrical in nature, and may or may not be coaxial with the outer housing 40. The inner mandrel may be supplied as a modular cartridge that can be inserted into or otherwise connected to the outer housing, for example by threaded connection, and in some cases the inner mandrel may be in whole or in part integrally connected to the outer housing. [0087]     A rod part may have a cylindrical, cone or other tapered shape. A  downhole drop plug may comprise a dart, ball (sphere), cone, cylinder, bar, or a wiper ball. Bypass grooves and restriction surfaces may be on a collar extended from the outer housing in a downhole direction from the inner mandrel. A coating may be present around the drop plug.  The uphole facing actuator surface need not seal the ball, and may be other than a seat, for example a lever. The seats or other drop plug contacting surfaces on the sleeve part 86 may be located at intermediate locations between the uphole and downhole ends of the sleeve part 86.     [0088]    Pumping may include dropping the plug down a vertical well. Various locks may be used to restrict axial movement between components, such as ratchets, collets, lock rings, split rings (including C-rings), and others. The methods and devices disclosed here may be used in other than fracturing applications, such as acidizing, disconnecting, tubing draining, and others. In some cases drop plugs may have a hole drilled offset from center to house the rod part. A restriction includes a relative minimum lateral diameter or width in an interior bore or passageway, and may define a flow area of close tolerance with the largest ball size capable of being passed through. Stem and receptacle parts may be other than cylindrical, for example such may have rectangular or polygonal cross-sections. Plural stem parts and corresponding receptacles may be present on a valve [0089]    The sleeve part 86 may be provided in two or more modules to permit greater than two same sized balls to pass and seat the sleeve part 86. Interior bores or passageways may have the same shape, and a bore is not necessarily cylindrical and could have radial projections or be defined as a passageway. Words such as downhole, uphole, up, down, above, below, and others are intended to be relative and not restricted to orientations defined relative to the surface of the earth. Stop surfaces and corresponding surfaces that contact stop surfaces may be defined on shoulders, for example annular shoulders. Packers are disclosed but other wellbore isolation devices may be used to isolate zones. A pressure equalization port 146 may be provided between components. Symmetry may refer to symmetry in cross-section, exterior surface, or both. All the examples shown in the Figures and Tables are intended to be non-limiting. [0090]    In the claims, the word "comprising" is used in its inclusive sense and does not exclude other elements being present. The indefinite articles "a" and "an"  before a claim feature do not exclude more than one of the feature being present. Each one of the individual features described here may be used in one or more embodiments and is not, by virtue only of being described here, to be construed as essential to all embodiments as defined by the claims.