Abstract:
The present invention is a method and apparatus for a one trip completion of fluid production wells. A completion tool string includes a pressure activated cementing valve, an external casing packer, a pressure activated production valve, an opening plug and a plug landing collar and a closing plug and seat. This tool series is assembled near the end of a production tube string upstream of the well production screen.

Description:
The present application is a Divisional of U.S. patent application No. 10/126,397 filed Apr. 19, 2002 now U.S. Pat. No. 6,729,393, which was a Continuation-In-Part of U.S. patent application No. 09/539,004, filed Mar. 30, 2000, abandoned. 

   FIELD OF THE INVENTION 
   The present invention relates to petroleum production wells. More particularly, the invention relates to well completion and production methods and apparatus. 
   DESCRIPTION OF THE PRIOR ART 
   The process and structure by which a petroleum production well is prepared for production involves the steps of sealing the production zone from contamination and securing production flow tubing within the well borehole. These production zones are thousands of feet below the earth&#39;s surface. Consequently, prior art procedures for accomplishing these steps are complex and often dangerous. Any procedural or equipment improvements that eliminate a downhole “trip”, is usually a welcomed improvement. 
   Following the prior art, production tube setting and opening are separate “trip” events. After a well casing is secured by cementing, a production string is then positioned where desired within the borehole and the necessary sealing packers set. In some cases, the packers are set by fluid pressure internally of the tubing bore. After the packers are set, a cementing circulation valve in the production tube assembly is opened by tubing bore pressure, for example, and annulus cement is pumped into position around the production tubing and above the production zone upper seal packer. 
   This procedure leaves a section of cement within the tubing below the cementing valve that blocks the upper tubing bore from production flow. The blockage is between the upper tubing bore and the production screen at or near the terminal end of the tubing string. Pursuant to prior art practice, the residual cement blockage is usually removed by drilling. A drill bit and supporting drill string must be lowered into the well, internally of the production tubing, on a costly, independent “trip” to cut away the blockage. 
   SUMMARY OF THE INVENTION 
   An objective of the present invention is to position well production tubing within the wellbore, secure the tubing in the well by cementing, and open the tubing to production flow in one downhole trip. In pursuit of this and other objectives to hereafter become apparent, the present invention includes a production tubing string having the present well completion tool assembly attached above the production screen and casing shoe. 
   This completion tool assembly includes an alignment of four basic tools in serial downhole order. At the uphole end of the alignment is a pressure actuated cementing valve followed by an external casing packer. Below the casing packer is a pressure actuated production valve and below the production valve is a bore plug landing collar 
   With the tubing string downhole and the open hole production screen located at the desired position with the well production zone, an opening plug is deposited in the tubing bore at the surface and pumped down the tubing bore by water, other well fluid or finishing cement until engaging a plug landing collar. Upon engaging the landing collar, the plug substantially seals the tubing bore to facilitate dramatic pressure increases therein. Actuated by a pressure increase within the tubing bore column, the external casing packer is expanded to block the borehole space annulus between the raw borehole wall and the packer body. An additional increase in pressure slides the opening sleeve of the pressure activated cementing valve into alignment of the internal and external circulation ports. Upon alignment of the circulation ports, tubing bore fluid such as cement is discharged through the ports into the wellbore annulus space. Due to the presence of the expanded external casing packer below the circulation ports, the annulus cement must flow uphole and around the tubing above the packer. 
   When the desired quantity of cement has been placed in the tubing bore at the surface, the fluidized cement within the tubing bore column is capped by a closing pump-down plug. Water or other suitable well fluid is pumped against the closing plug to drive most of the cement remaining in the tubing bore through the circulation ports into the annulus. At the circulation port threshold, the closing plug engages a plug seat on the closing sleeve of the pressure actuated cementing valve. With a first pumped pressure increase acting on the fluid column above the closing plug seat, the cementing valve closing sleeve slides into a circulation port blocking position. 
   With the circulation port closed, a second pressure increase that is normally greater than the first develops a force on the plug seat of such magnitude as to shear calibrated retaining screws that hold the seat ring within the tubing bore. When structurally released from the tubing bore wall, the closing plug and plug seat impose a piston load on the short cement column supported by the opening plug and plug landing collar. This column load is converted to fluid pressure on the pressure activated production valve to force a fluid flow opening through the valve. When the pressure activated production valve opens, the residual cement column is discharged through the open valve below the packer. 
   Although the residual cement column is discharged into the production zone bore, the absolute volume of cement dispersed into the bore is insignificant. 
   As the closing plug is driven by the finishing fluid through the central bore of the production valve past the valve opening, the finishing fluid, water or light solvent, rushes through the valve opening to flush it of residual cement and debris. At this point, a clear production flow path from the production zone into the production tubing bore is open. When pressure on the finishing fluid is released, upflowing production fluid sweeps the residual finishing fluid out of the tubing bore ahead of the production fluid flow. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     A detailed description of the invention following hereafter refers to the several figures of the drawings wherein like reference characters in the several figures relates to the same or similar elements throughout the several figures and: 
       FIG. 1  is a schematic well having the present invention in place for completion and production; 
       FIG. 2  is a partial section of the present well completion tool assembly in the run-in condition; 
       FIG. 3  is a partial section detail of the cementing valve run-in setting; 
       FIG. 4  is a partial section of the present well completion tool assembly in the packer inflation condition; 
       FIG. 5  is a partial section of a closed, pressure actuated cementing valve; 
       FIG. 6  is a partial section detail of the open cementing valve; 
       FIG. 7  is a partial section of the present well completion tool assembly in the annulus cementing condition; 
       FIG. 8  is a partial section of the present well completion tool assembly in the cement termination condition; 
       FIG. 9  is a partial section detail of the closed cementing valve; 
       FIG. 10  is a partial section of the present well completion tool assembly in the production flow opening condition; and 
       FIG. 11  is a partial section detail of the pressure actuated production valve. 
   

   DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS 
   The invention utility environment is represented by the schematic of  FIG. 1  which illustrates a well bore  10  that is normally initiated from the earth&#39;s surface in a vertical direction. By means and procedures well known to the prior art, the vertical well bore may be continuously transitioned into a horizontal bore orientation  11  as desired for bottom hole location or the configuration of the production zone  12 . Usually, a portion of the vertical surface borehole  10  will be internally lined by steel casing pipe  14  which is set into place by cement in the annulus between the inner borehole wall and the outer surface of the casing  14 . 
   Valuable fluids such as petroleum and natural gas held within the production zone  12  are efficiently conducted to the surface for transport and refining through a string of production tube  16 . Herein, the term “fluid” is given its broadest meaning to include liquids, gases, mixtures and plastic flow solids. In many cases, the annulus between the outer surface of the production tube  16  and the inner surface of the casing  14  or raw well bore  10  will be blocked with a production packer  18 . The most frequent need for a production packer  18  is to shield the lower production zone  12  from contamination by fluids drained along the borehold  10  from higher zones and strata. 
   The terminal end of a production string  16  may be an uncased open hole but is often equipped with a liner or casing shoe  20  and a production screen  22 . In lieu of a screen, a length of drilled or slotted pipe may be used. The production screen  22  is effective to grossly separate particles of rock and earth from the desired fluids extracted from the formation  12  structure as the fluid flow into the inner bore of the tubing string  16 . Accordingly, the term “screen” is used expansively herein as the point of well fluid entry into the production tube. 
   Pursuant to practice of the present invention, a production string  16  is provided with the present well completion tool assembly  30 . The tool assembly is positioned in the uphole direction from the production screen  22  but is often closely proximate therewith. As represented by  FIG. 1 , the production packer  18  (if necessary), the completion tool assembly  30 , the production screen  22  and the casing shoe  20  are preassembled with the production tube  16  as the production string is lowered into the wellbore  10 . 
   With respect to  FIG. 2 , the completion tool assembly  30  comprises a pressure activated cementing valve  32 , an external casing packer  34 , a pressure activated production valve  36  and a plug landing collar  38 . Each of these devices may be known to those of ordinary skill in some modified form or applied combination. 
   As shown in greater detail by  FIG. 3 , the pressure actuated cementing valve provides circulation ports  40  and  42  through the inside bore wall  60  of the tool and the outer tool casing  62 . Axially sliding sleeve  44  is initially positioned to obstruct a fluid flow channel between the inner ports  42  and the outer ports  40 . This position is secured by a calibrated set-screw  64 , for example, for a well run-in setting. Upon a satisfactory down-hole location, the sleeve  44  is positionally displaced, as shown in by  FIGS. 6 and 7 , by high fluid pressure applied within the tool flow bore from fluid circulation pumps. Force of the fluid pressure shears the retainer screw  64  to allow displacement of the sleeve  44  from the initial obstruction position between the flow parts  40  and  42 . When the ports  40  and  42  are mutually open, well cement may be pumped from within the internal bore of the tool and tubing string through the ports  40  and  42  into the well annulus around the tubing string. Use of the term “cement” herein is intended to describe any substance having a fluid or plastic flow state that may be pumped into place and thereafter induced to solidify. 
   Closure of the fluid channel through ports  40  and  42  is accomplished by a second sliding sleeve  46  as illustrated by  FIGS. 8 and 9 . A landing seat  48  for a closure plug  54  is secured to the inside bore wall of the tool by shear screws  49 , for example. Procedurally, the cement slurry tail is capped by a wiper closing plug  54 . The closing plug is pumped by water or other suitable well working fluid down the tubing string bore until engaging the plug landing seat  48 . When the plug engages the seat  48 , fluid pressure in the bore may be increased to 1000 psi, for example, within the tool flow bore. Such pressure is admitted through fluid ports  66  against the end area of closing sleeve  46 . Force of the pressure shears the retainer screw  68  and shifts the sleeve  46  against the sleeve  44  and between the circulation ports  40  and  42 . Additional pressure against the closing plug and seat  48 , 5000 psi, for example is operative to shear the assembly screws  49  and drive the plug  54  and seat  48  further along the tool bore. 
   The external casing packer  34  is any device that creates a seal in the wellbore annulus around the tube string. A common example of a casing packer provides an expansible elastomer boot around an internal tube body. An internal bore of the tube body is coaxially connected with the production tube string. The expansible boot is secured to the tube body around the perimeter of the two circumferential edges of the boot. A fluid tight chamber is thereby provided between the boot edges and between the tube body and the inside surface of the expansible boot. This chamber is connected by a check valve controlled conduit to the interior bore of tube body. Hence, pressurized fluid within tube body expands the boot against the casing or borehole wall. 
   A simplified example of a pressure actuated production valve  36  is shown by  FIG. 11  to include an annular chamber  70  between an internal bore wall  72  and an external jacket  74 . The external jacket  74  may be slotted pipe or a screen to pass the desired fluid flow. The internal bore wall is perforated by a plurality of apertures  76  distributed along the axial length of the bore wall. These apertures  76  are initially closed by a fluid pressure displaced fluid flow obstacle such as a sliding sleeve similar to the sleeve  44  in the cement valve. Alternatively, the aperture  76  may be initially closed by reed members  78  shown by  FIG. 11  as having a frangible assembly with the internal bore wall  72 . A predetermined magnitude of fluid pressure within the tool flow bore partially ruptures the reed  78  connections to the bore wall  72  to bend the reeds  78  to a fixed open position. 
   The plug landing collar  38  may be an extension of the production valve sleeve that continues an open flow continuity of this tool flow bore through a plug seat  56 . 
   The above described tubing string assembly is lowered into the well bore  10  with the packer  18  unset and the external casing packer  34  deflated. The cementing valve  32  ports  40  and  42  are closed as shown in  FIG. 3 . The production flow screen  22  is positioned where desired and an opening pump-down plug  50  is placed in the tubing string bore to be pumped by well finishing cement down to the landing collar  38  for engagement with the plug seat  56  as shown by  FIG. 4 . If desired, the plug  50  may also be transferred downhole by water or other well working fluid. With the plug  50  secure upon the landing collar plug seat  56 , fluid pressure within the tubing bore is increased against the opening plug  50  to inflate the packer  34 . This event blocks the well annulus between the production screen  22  and the cementing valve  32 . 
   Next, fluid pressure within the tubing bore is further increased to shift the cementing valve  32  opening sleeve  44  by shearing the set screw  64 , as shown by  FIG. 6 . Shifting the opening sleeve  44  opens a flow channel through the circulation ports  40  and  42 . When the circulation port channel opens, cement flows through the channel and up the borehole annulus around the production tubing as shown by  FIGS. 6 and 7 . 
   The total cement volume requirement for a particular well is usually calculated with considerable accuracy. Accordingly, when the desired quantity of cement has been pumped into the tubing bore, a closing pump-down plug  54  is placed in the bore to cap the cement column. Behind the closing pump-down plug  54 , water or other suitable well working fluid is pumped to complete the cement transfer and settle the closing pump-down plug  54  against the cementing valve plug seat  48 . With the tool flow bore closed by the plug  54 , the flow bore pressure may be increased behind the plug. An increase of tubing bore pressure to 1000 psi, for example, against the plug  54  and seat  48  causes a shift in the valve closing sleeve  46  thereby closing the fluid communication ports  40  and  42 . Illustrated by  FIG. 9 , fluid pressure enters the sliding sleeve annulus through pressure port  66  to bear against the end of the closing sleeve  46 . When sufficient, the pressure force shears the screw  68  and moves the sleeve  46  between the ports  40  and  42 . 
   Thereafter, the tubing bore pressure is increased again, to 5000 psi, for example, to shear the plug seat retaining screws  49  and release both the seat  48  and the closing plug  54 . When released, the free piston nature of the plug and seat unit drives against the residual cement column that was isolated between the opening pump-down plug  50  and the closing pump-down plug  54 . Pressure against the closing pump-down plug  54  is thereby transferred to the residual cement column and consequently to the pressure activated production valve  36 . Referring to  FIGS. 10 and 11 , this increased pressure against the production valve  36  ruptures flow port closure reeds  78  to permanently open the flow ports  76  between a production flow annulus and the tubing bore. Continued pressure against the residual cement column purges the residual cement through the newly opened production valve ports  76  into the well bore below the packer  34 . 
   It will be understood by those of skill in the art that the number and distribution of the flow ports  76  is configured to bridge the length of the plug  54  whereby cement and well working fluid may simultaneously exit the flow port  56  into the wellbore as plug  54  passes the open flow ports as illustrated by  FIG. 11   
   Another active mechanism in the process of opening the production valve  36  is the seal bias of the plug  54  bore sealing fin  58 . The wiping bias of the fin  58  is oriented to seal uphole fluid pressure within the production tube bore from passing between the fin and tubing wall. Conversely, when the static pressure within the wellbore is greater than the static pressure in the production tube bore, the plug  54  sealing fin bias will allow wellbore fluid flow past the fin  58  into the production tube bore. Hence, it is not essential for the plug  54  to be pressure driven past the flow port  76  opening. 
   At this point, the well completion process is essentially complete and the well is ready to produce. However, some operators may choose to transfer a cement contamination fluid into the production zone bore to assure a subsequent removal of the residual column cement from the well bore. 
   Having fully described the preferred embodiments of the present invention, various modifications will be apparent to those skilled in the art to suit the circumstances of a particular well and manufacturing capacity. It is intended that all variations within the scope and spirit of the appended claims be embraced by the foregoing disclosure.