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Halliburton Cementing Casing Equipment and Accessories
Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale.
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2001 Halliburton Energy Services
Printed in U.S.A.
Halliburton Cementing Casing Equipment and Accessories
Halliburton Energy Services, Inc.
Floating and Guiding Equipment ............................ 1 Super Seal™ II Floating Equipment ............................................. 1 Super Seal™ II Down-Jet Float Shoe .................................... 1 Super Seal™ II Nonrotating (NR) Float Collar ....................... 1 Super Seal™ II High-Port Up-Jet Float Shoe ........................ 2 Double-Valve Super Seal™ II Floating Equipment ................ 2 Super Seal™ II Tubing-Size Floating Equipment .................. 3 Super Seal™ II Float Shoe .................................................... 3 Super Seal™ II Float Collar ................................................... 3 Pressure Differential Fill (PDF) Float Shoes and Collars ............. 4 Insert Float Valve ......................................................................... 4 Guide Shoes ................................................................................ 5 Load-Carrying Float Equipment ................................................... 5
Inner-String Cementing Equipment ........................ 6 Cementing Plugs ...................................................... 8 Standard Five-Wiper Cementing Plugs ................................. 8 Nonrotating (NR) Cementing Plugs ....................................... 8 Subsurface Release (SSR)® Cementing Plug System .......... 9
Multiple-Stage Cementing Tools ........................... 10 Type-P External Sleeve (ES) Cementer .............................. 10 Type-H External Sleeve (ES) Cementer ............................... 11 Stage Tool Plug Sets ............................................................ 11 Full-Opening (FO) Multiple-Stage Cementer ....................... 12 External Sleeve Inflatable Packer Collar (ESIPC) ............... 13 Type-H Selective-Release (SR) Plug Set ............................ 14
Formation Packer Shoes/Collars .......................... 15 852-Series Formation Packer Shoe/Collar .......................... 15 855-Series Formation Packer Shoe/Collar .......................... 16
Super-Fill™ Equipment .......................................... 17 Super-Fill™ Collar ............................................................... 17 Super-Fill™ Diverter Tool .................................................... 18
Bow-Spring Centralizers ........................................ 19 Welded Bow-Spring Centralizer .......................................... 19 Nonwelded Bow-Spring Centralizer ..................................... 19
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Halliburton Energy Services, Inc.
Floating and Guiding Equipment Super Seal™ II Floating Equipment Super Seal™ II floating equipment is installed in the casing string and becomes an integral part of the casing string. This equipment helps float and cement the casing in the well. The equipment’s basic backpressure and temperature ratings (5,000 psi and 400°F) allow it to be used in most wells. The plastic valve materials and surrounding shear- and shockloadresistant concrete exceed the strength requirements for landing cementing plugs. The valve assembly and the cement holding the valve assembly in place can be drilled out easily with roller-cone rock bits or polycrystalline diamond compact (PDC) bits after cementing operations. No steel or cast-iron materials are used in the drillable portion of the valve assembly. The valve spring is made from a brass alloy. The 2 3/4-in. valves (for 4 1/2- to 20-in. casing) and the 4 1/4-in. valves (for 7-in. and larger casing) are rubber-coated to prevent erosion. The 2 3/4-in. valve is rated for flow rates of 10 bbl/min for 24 hours. The 4 1/4-in. valve is rated at 25 bbl/min for 24 hours. Tubing-size Super Seal™ II floating equipment with a 2 1/4-in. valve has been tested at 6 bbl/min for 24 hours. All Halliburton Super Seal™ II floating equipment exceeds the flow durability and pressure/temperature requirements established by API RP-10F III C. All casing-size Super Seal™ II float shoes and collars are supplied with an autofill feature (at no additional cost). Because of size limitations, tubing-size Super Seal™ II floating equipment is not supplied with an autofill strap. Customers can request Super Seal™ II floating equipment for any casing grade or premium thread.
Super Seal™ II Down-Jet Float Shoe The Super Seal™ II down-jet float shoe includes the Super Seal™ II float valve, which prevents cement backflow from re-entering the casing ID. In addition to the center hole through the float valve, four fluid ports are drilled in the outer case below the float valve. These ports direct some of the fluid downward during circulation. Pressurized fluid jets out of the side ports and the guide nose, helping remove cuttings and filter cake, creating turbulence around the shoe, and improving cement distribution and casing-to-formation bonding. Additionally, the external jets on the outer case provide an alternative cement flowpath if the bottom center port becomes blocked in the event that casing is landed on the bottom of the hole.
Super Seal™ II Nonrotating (NR) Float Collar Super Seal™ II nonrotating (NR) float collars offer all the features of standard Super Seal™ II float collars, but they are equipped with a NR plug seat that allows NR cementing plugs with locking teeth to latch together during drillout. When these NR plastic plugs are drilled out with PDC bits, they can reduce drillout time by 90%. This equipment is available only with the 2 3/4- and 4 1/4-in. Super Seal™ II valve for 7- to 20-in. casing.
Halliburton Super Seal™ II Down-Jet Float Shoe
Halliburton Super Seal™ II Nonrotating Float Collar
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Halliburton Energy Services, Inc.
Super Seal™ II High-Port Up-Jet (HPUJ) Float Shoe ;À@À@; ;À@;À@;À@;À@ ;À@ ;À@;À@ ;À@;À@;À@;À@ ;À@ ;À@;À@ ;À@;À@;À@;À@ ;À@;À@ ;À@;À@;À@;À@ ;À@ ;À@;À@ ;À@;À@;À@;À@ ;À@ ;À@;À@ ;À@;À@;À@;À@ ;À@ ;À@;À@ ;À@;À@;À@;À@ ;À@ ;À@;À@ ;À@;À@;À@;À@ @ À ; ;À@ ;À@ ;À@ ;À@ ;À@;À@ ;À@;À@ ;À@;À@ ;À@;À@ ;À@;À@ ;À@;À@;À@;À@ ;À@;À@;À@ ;À@;À@;À@;À@ ;À@ ;À@ ;À@ ;À@ ;À@;À@ ;À@;À@;À@;À@ ;À@;À@ ;À@ ;À@;À@;À@;À@ ;À@ @ À ; @ À ; @ À ; ;À@;À@ ;À@ ;À@;À@ ;À@ ;À@ Seal™ II ;À@ Super Halliburton High-Port Up-Jet (HPUJ) Float Shoe
The High-Port Up-Jet (HPUJ) float shoe jets the formation face to remove detrimental mud cake and cuttings, increasing the chances of a successful cement-to-formation bond. The high circulation rates and cement flow rates that are possible with the Super Seal™ II float valve allow turbulent flow at the shoe without damaging the float valve. The HPUJ shoe includes six fluid-discharge ports strategically placed to jet the circulation fluid or cement upward, enhancing fluid turbulence far above the floating equipment. These up-jet ports, along with four (or fewer) down-jet ports, distribute the fluid in the annular space above and below the float shoe, helping prevent channeling near the shoe. Approximately 40% of the fluid pumped through the equipment is discharged at a high velocity through the bottom of the float shoe, removing material in its path and helping maneuver the casing past ledges and tight sections of the wellbore. If the casing string is reciprocated during cementing, cement jetted through the exit ports removes mud cake from the formation face. Field reports indicate that the HPUJ float shoe can substantially reduce the number of casing strings requiring squeeze cementing operations. All casing sizes of the Super Seal™ II HPUJ float shoe use the same autofill strap used for the Super Seal™ II float valve. When engaged, this strap allows the casing to fill automatically with wellbore fluid while it is being run in the hole, saving time and reducing the “ram effect” of running casing.
Double-Valve Super Seal™ II Floating Equipment The double-valve Super Seal™ II float collars and float shoes offer a double float valve, which is more economical than a conventional float shoe and float collar. The double float valve ensures a backpressure seal if one of the valves is damaged by wellbore fluids or if debris between the valve and the valve seat prevents the valve from sealing.
Halliburton Double-Valve Super Seal™ II Float Shoe and Collar
The double-valve floating equipment has the following features: • a 2 3/4-in. valve for 5-in. and larger casing • a 4 1/4-in. valve for 7-in. and larger casing • several standard Super Seal™ II options, such as innerstring options, nonrotating inserts, and high-port up-jets • availability in different casing grades and premium threads Double-valve Super Seal™ II float shoes and collars are supplied with the autofill feature preset in the fill position.
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Halliburton Energy Services, Inc.
Super Seal™ II Tubing-Size Floating Equipment Super Seal™ II tubing-size floating equipment is available in both standard and HPUJ designs. Tubing-size float shoes and collars prevent cement backflow from entering the tubing string. Because of size restrictions, autofill devices are not provided with tubing-size floating equipment. The case material for all standard sizes and grades of equipment is L-80 grade steel. Other material grades and premium threads are available by special order. The 2 3/8-in. float shoe and float collar includes the Super Seal™ 2 1/8-in. valve. Standard float shoes and HPUJ float shoes are available in 2 7/8-in. and 3 1/2-in. tubing sizes. Tubing-size floating equipment should be drilled out with roller-cone rock bits.
Super Seal™ II Float Shoe The Super Seal™ II standard float shoe attaches to the lower end of the casing string. This float shoe includes the Super Seal™ II backpressure valve assembly, which prevents cement in the annulus from re-entering the casing ID. The plastic valve and stem materials are surrounded by drillable concrete, making the equipment easy to drill out with PDC or roller-cone rock bits. The high-strength, durable rounded nose safely guides the casing to the bottom of the hole. This equipment is available in all tubing and casing sizes with API 8-rd and buttress threads. The standard casing grade is K-55 material. Customers can request any casing grade and premium thread by special order.
Super Seal™ II Float Collar The Super Seal™ II float collar includes the Super Seal™ II backpressure valve, which prevents cement pumped into the casing/wellbore annulus from re-entering the casing ID after cementing operations. The float collar is normally installed one or two joints above the float or guide shoe. All casing-size Super Seal™ II float collars include an autofill feature (at no additional cost). This feature, which is installed between the valve and pressure seat, is deactivated by flow rate. The autofill feature allows wellbore fluids to enter the casing from the first joint, reducing surge pressure on the formation and reducing casing fill time from the surface. When the autofill feature is pumped loose with a high fluid rate, the float valve is returned to a dependable Super Seal™ II backpressure valve. The autofill feature will deactivate if the flow through the valve reaches a predetermined rate (4 to 6 bbl/min for the 2 3/4-in. valve and 6 to 8 bbl/min for the 4 1/4-in. valve).
Halliburton Super Seal™ II Tubing-Size Float Shoe and Collar
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Halliburton Super Seal™ II Float Collar
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Halliburton Energy Services, Inc.
Pressure Differential Fill (PDF) Float Shoes and Collars The pressure differential fill (PDF) float shoe and collar include a convertible float valve. This valve allows casing to fill while it is run in the hole, and it allows fluid circulation at any time without deactivating the fill unit. PDF float shoes and collars can be run in the same casing string. They allow fluid to enter the bottom of the casing while maintaining a constant differential pressure between the inside and outside of the casing at the floats. This pressure maintains a constant fluid height inside the casing. PDF floating equipment is supplied in the differential-fill mode, and it is ready to be run in the hole. After all casing has been run, a weighted plastic ball is dropped in the casing from the surface and pumped through the tool. This procedure deactivates the differential-fill option. After the ball passes the float collar and/or shoe, the PDF flapper closes against its seat, preventing cement from reentering the casing ID. The PDF floating equipment is supplied in either a float collar or a float shoe in common casing sizes. All equipment run with these tools must have an ID large enough to allow passage of the weighted ball that releases the backpressure valve. Tool sizes from 4 1 /2 to 6 5/8 in. require a 1 3/8-in. diameter ball, while tools 7 in. and larger require a 2 3/8-in. diameter ball. Halliburton Pressure Differential Fill (PDF) Float Shoe and Collar
PDF floating equipment should not be used in wells deviated more than 30° from vertical, and it should not be drilled out with PDC bits. PDF equipment cannot be used with Super Seal™ II floating equipment.
Insert Float Valve
Halliburton Insert Float Valve Self-Fill Unit
The insert float valve is a backpressure check-valve assembly installed between the pin and box ends of API 8-rd or buttress thread casing joints. The insert float valve is used for casing flotation and cementing operations in wells with moderate temperature and depth. It can be used for differential pressures up to the collapse pressure of the lightest weight of J-55 casing in the casing size in which it is run. The insert float valve can be installed in long or short API 8-rd or buttress casing couplings. Because of limited space between the casing box and pin, insert float valves are not available for premiumthread casing. One or more insert valves can be run in a casing string or in conjunction with a guide shoe. Because they are made from aluminum, insert float-valve assemblies can be drilled out easily with a medium-tooth, roller-cone rock bit. PDC bits should not be used to drill out insert valves.
Halliburton Insert Float Valve
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The insert float valve has a large flow area and can be easily converted to autofill equipment if an orifice self-fill unit is installed. The self-fill unit includes a weighted plastic ball and plastic orifice tube. The orifice tube holds the flapper open until a weighted plastic ball is dropped into the casing. Once the ball reaches the ball seat, pressure is applied to shear out the plastic orifice tube, which allows the valve to close. This equipment operates efficiently in mud systems containing high concentrations of lost-circulation material.
Halliburton Energy Services, Inc. Guide Shoes Guide shoes and down-jet guide shoes have the following primary purposes: • They protect the casing string from the impact associated with landing casing on bottom. • They direct casing away from ledges, reducing the chance of sidewall cave-in. • They help casing pass through narrow, deviated holes and areas with hard shoulders. The standard guide shoe has a large-ID hole through its center, allowing maximum cement pumping rates and the passage of self-fill orifice tubes and balls dropped in the casing string. The rounded nose of these guide shoes is made from high-strength cement that can be drilled out easily with roller-cone rock bits or PDC bits.
Halliburton Guide Shoe
Down-jet guide shoes have additional side ports in the steel case that allow fluid to discharge through both the cement nose and the ports. The jetting action of the fluid pumped through these ports helps remove wellbore cuttings and filter cake.
Workstring Bit guide (Helps bit re-enter casing before drillout)
Load-Carrying Float Equipment Load-carrying float equipment provides the following advantages: • It supports large-diameter casing and scab liners. • It eliminates large-diameter plug containers. • It enables the operator to reciprocate large-diameter casing during a cement job. • It is easily drilled with standard rock bits; no mill is required. • There is no cast iron to be drilled out. Load-carrying float equipment is special, high-strength inner-string cementing equipment designed to transfer casing weight to the drillpipe through the float equipment. This transfer is made possible with float equipment that has an internally threaded receptacle that can be connected to an adapter on the workstring. This connection allows the casing load (up to 400,000 lb) to be transferred to the workstring. After the large-diameter casing or scab liner is cemented, the workstring is rotated several turns clockwise to disconnect it from the casing or liner. Load-carrying float equipment and bit guides for centralizing the top of the scab liner are available in all casing sizes.
Halliburton Down-Jet Guide Shoe
Drillpipe centralizer Casing being cemented Load-carrying sealing adapter Load-carrying Super Seal™ II float equipment
Load-Carrying Float Equipment
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Halliburton Energy Services, Inc.
Inner-String Cementing Equipment Inner-string cementing equipment allows large-diameter casing strings to be cemented through drillpipe or tubing that is inserted and sealed in floating equipment. Inner-string cementing has the following advantages: • It can be less costly than cementing large casing with the conventional plug-displacement method. • It does not require large-diameter cementing plugs. • It reduces cement contamination. • It reduces the amount of cement that has to be drilled out of large-diameter casing. • It decreases cementing displacement time. • It reduces casing collapse when surface packoff is used. Inner-string cementing requires installation of a stab-in float shoe or float collar in the casing string. The casing string is run into the well in the usual manner. The inner string is then run in, with the sealing adapter made up on the lower end and stabbed into the floating-equipment sealing sleeve.
Halliburton Super Seal™ II Float Collar with Sealing Sleeve
The sealing sleeve is built into the floating equipment to provide a sealing-sleeve/bore receptacle for the inner-string sealing adapter. Concrete is molded around the sealing sleeve to secure the sleeve within the floating equipment. The floating-equipment top is also tapered to form a surface that helps guide the sealing-sleeve adapter into its sealing sleeve. Two centralizers should be run on the inner string: one centralizer directly above the sealing adapter, and another one joint above the first centralizer. This arrangement will help the inner string enter the stab-in floating equipment. After the inner string (usually drillpipe) has been stabbed into the floating equipment, cement is pumped through the inner string and floating equipment into the casing/wellbore annulus. After cementing has been completed, the check valve in the floating equipment prevents cement from reentering the casing, and the sealing adapter and inner string can be pulled from the casing.
Halliburton Super Seal™ II Float Collar with Sealing Sleeve and Latchdown Plug
Floating equipment with a latchdown plug seat is also available. This floating equipment is built with a combination sealing sleeve and latchdown plug seat. The combination sleeve, which is held in place by concrete, provides (1) a sealing surface for the inner-string sealing adapter on the top and (2) a bore configuration to latch and seal the nose of a latchdown plug on bottom. After the last cement is displaced down the inner string, a top latchdown cement plug is launched down the inner string. The nose of the latchdown plug seats and latches into the float equipment sleeve immediately after passing through the inner-string sealing sleeve. After latching in, the plug nose provides a seal and withstands pressure from above and below.
After the inner string is retrieved, the latchdown plug serves as a backup to any backpressure valves located in the casing string below. Pressure can be applied inside the casing immediately after the latchdown plug has been landed and the sealing-sleeve adapter has been pulled from the sealing sleeve. 6
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Halliburton Energy Services, Inc.
Casing string Centralizer
Sealing sleeve adapter Super Seal™ II float collar Sealing sleeve
Super Seal™ II float shoe
Halliburton Inner-String Cementing Method without Top Cementing Latchdown Plug
Halliburton Inner-String Cementing Method with Top Cementing Latchdown Plug (Cementing Completed, Top Plug Latched, and Inner String Being Pulled)
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Halliburton Energy Services, Inc.
Cementing Plugs Cementing plugs are normally used during cementing operations to cement casing in a wellbore. They offer the following advantages: • They wipe mud sheath from the casing ID. • They separate cement from wellbore fluids during cementing operations. • They help prevent overdisplacement of cement slurry. • They provide a surface indication when the cementing job is complete. • High-pressure cementing plugs allow casing to be pressure-tested immediately after cement displacement and before checking floats.
Standard Five-Wiper Cementing Plugs The five-wiper cementing plug is Halliburton’s primary cementing plug. Five-wiper plugs are available in 4 1/2through 20-in. casing sizes with standard plastic and aluminum inserts as well as 24-tooth nonrotating (NR) plastic inserts.
Halliburton Standard Five-Wiper Cementing Plugs
Standard five-wiper cementing plugs are manufactured with plastic and aluminum inserts. Aluminum inserts increase the strength and temperature ratings of the plugs. These inserts should be used when the bottomhole circulating temperature (BHCT) exceeds 300°F. They should be drilled out with conventional roller-cone rock bits. The recommended landing pressures for aluminum-insert five-wiper plugs vary depending on casing size, but they are normally higher than the recommended landing pressures for wiper plugs with plastic inserts. Five-wiper plugs are designed to land and seal on Super Seal™ II floating equipment. These plugs should not be used on floating equipment with tapered tops. Plastic-insert plugs can be used in wells with BHCTs below 300°F. After cementing operations, the plastic-insert plugs can be drilled out easily with roller-cone rock or PDC bits.
Halliburton Nonrotating (NR) Cementing Plugs
Standard five-wiper cementing plugs are available in either standard or oil-resistant versions.
Nonrotating (NR) Cementing Plugs Designed for use with Super Seal™ II nonrotating (NR) float collars, top and bottom nonrotating (NR) plugs have locking teeth that prevent the equipment from spinning during drillout, which reduces drillout times and associated rig costs. The high-strength plastic inserts used in NR plugs increase plug-landing pressures and allow easy drillout with both PDC and roller-cone rock bits. NR plugs are available for 7- to 20-in. casing sizes. All NR plugs are made of a synthetic service compound that is compatible with all water-based and synthetic mud systems. Five-wiper highstrength NR cementing plugs can be used with highstrength float collars to pressure-test casing immediately after cementing operations are completed. Casing and tubing latchdown plugs and baffles are also available in all common casing and tubing sizes. 8
Halliburton Energy Services, Inc.
Subsurface Release (SSR)® Cementing Plug System The subsurface release (SSR)® cementing plug system allows cementing operations to be performed from a floating vessel or fixed platform that uses a subsea wellhead. The SSR cementing plug set is installed in the top joint of the casing string and is made up to the bottom of an installation tool that is attached to the casing string. The installation tool and casing string are lowered on a drillpipe string, landed and sealed in the subsea wellhead on the ocean floor. When the tool and string have landed, the well can be circulated before cementing operations.
Bottom Plug Releasing Ball
Top Plug Releasing Dart
The bottom SSR plug is released ahead of the cement by a weighted plastic ball dropped down the drillstring. The ball lands on a seat of the bottom plug, releasing the bottom SSR casing plug. When the bottom SSR plug lands on the float collar, a bypass mechanism allows the cement to pump around the ball. After all the cement has been mixed and pumped into the drillpipe, a drillpipe releasing dart is launched from the surface to wipe the drillpipe ID and release the top SSR casing plug. The drillpipe plug latches and seals in the top SSR plug. The top SSR plug is then pumped to a pressure shutoff on the float collar. Standard SSR plugs and NR SSR plugs are available in top or top-and-bottom plug sets for 7- to 20-in. casing sizes. Drillpipe releasing darts are available for use with 4 1/2-, 5-, 5 1/2-, and 6 5/8-in. drillpipe sizes. NR plug sets are also available for 9 5/8- by 10 3/4-in. combination casing strings. Combination plug sets that meet individual requirements are available on request. SSR plug sets are available with aluminum, plastic, and composite plug inserts. Plastic and composite plug sets can be drilled with standard/bi-center PDC or rock bits, while aluminum insert plug sets should be drilled only with roller-cone rock bits. Top SSR plugs are available in standard and NR designs from 7 in. through 20 in.
Halliburton Subsurface Release (SSR) Cementing Plug System
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Halliburton Energy Services, Inc.
Multiple-Stage Cementing Tools During multiple-stage cementing, cement slurry is placed at predetermined points around the casing string in cementing stages. Multiple-stage cementing can be used for the following applications: • cementing wells with low formation pressures that will not withstand the hydrostatic pressure of a full column of cement • cementing to isolate only certain sections of the wellbore • placing different blends of cement in the wellbore • cementing deep, hot holes where limited cement pump times restrict full-bore cementing of the casing string in a single stage Halliburton manufactures two types of external sleeve (ES) stage cementers: the Type-P ES cementer, which is a plug-operated stage cementer, and the Type-H ES cementer, which is a hydraulically opened stage cementer. Both the Type-P and the Type-H cementers have the following features: • short, single-piece mandrel design without threaded or welded segments • field-adjustable opening and closing pressures • clear surface indications of opening and closing • smooth bore after drillout with no exposed sleeves to interfere with the operation of workover tools on subsequent trips in and out of the casing string • drillability with either PDC or roller-cone rock bits • compatibility with second-stage bottom plug sets • external closing sleeve that is locked closed by the top cementing plug • heavy-duty seals and backup rings that prevent seal damage during operations • compatibility with three-stage cementing applications
Type-P External Sleeve (ES) Cementer Type-P external sleeve (ES) cementers can be used in most vertical wells, regardless of depth, pressure, or temperature. The Type-P cementer should not be used in wells deviated more than 30° from vertical when using a free-fall opening plug. Otherwise, the free-fall opening plug will not fall by its own weight through well casing. Type-P ES cementers are available in 4 1/2- to 20-in. casing sizes. The standard case material grade is L-80 steel. Other casing grades and premium threads can be provided at the customer’s request.
Halliburton Type-P External Sleeve (ES) Cementer
During cementing operations, the first-stage cement is mixed and pumped into the casing in a conventional manner. The first-stage shutoff plug, which is launched in the casing after the first-stage cement, lands on the shutoff baffle installed on the float collar. This shutoff plug provides a positive shutoff, which helps prevent cement overdisplacement around the shoe joint. After the firststage cementing operation is completed, a free-fall opening plug is dropped down the casing ID to land and seal in the cementer. Pressure applied to the casing opens the cementer, allowing wellbore fluid to be pumped into the casing/wellbore annulus. Fluid circulation to the surface is normally maintained until the first-stage cement has set up in the annulus. The second-stage cement is then pumped through the open cementer ports, followed by a secondstage closing plug. The closing plug seats in the cementer, and pressure is applied to the casing to close the tool. After both stages are cemented, the cementer seats, and plugs are drilled out with a rock bit or a PDC bit. For information on stage tool plug sets, see Page 11.
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Halliburton Energy Services, Inc.
Type-H External Sleeve (ES) Cementer The Type-H external sleeve (ES) cementer is a hydraulically opened stage cementer that can be used in most wells, regardless of depth, pressure, or temperature. Although the Type-H ES cementer operates much like a Type-P cementer, it can be opened with internal casing pressure in addition to the free-fall plug after the first-stage shutoff plug lands. This design feature saves time by eliminating the need for dropping a free-fall plug from the surface. A baffle adapter is recommended in the casing string above the float collar to seat the first-stage shutoff plug. When the first-stage cementing plug has seated, casing pressure can be applied to hydraulically open the Type-H ES cementer. Normally, the cementer should be opened immediately after the first-stage cement is pumped and the shutoff plug has been bumped. If the well is deviated less than 30° from vertical, the Type-H ES cementer can also be opened with a free-fall plug dropped through the casing ID. The Type-H cementer can be used in highly deviated wells, in horizontal wells, and above an openhole completion or slotted liner. After the second-stage cementing operation, a second-stage closing plug pumped behind the second-stage cement closes the cementer. Lock rings in the external closing sleeve lock the cementer in the closed position. After both cementing stages, the cementer seats, and plugs are drilled out with a roller-cone rock bit or a PDC bit. Type-H ES cementers are available in 4 1/2- to 20-in. casing sizes. The standard material grade is L-80 grade steel. Other grades and premium threads can be provided at the customer’s request.
Halliburton Type-H External Sleeve (ES) Cementer
Stage Tool Plug Sets Plug sets for operating both Type-P and Type-H cementers must be ordered separately from the cementer. The individual components of each plug set depend on the type of tool to be operated. A standard plug set for two-stage cementing consists of the following equipment: • a shutoff baffle installed on top of the float collar (for 8-rd and buttress) • a shutoff plug (for both Type-P and Type-H cementers) • a free-fall opening plug (required for the Type-P cementer; optional for the Type-H cementer) • a closing plug (for both Type-P and Type-H cementers) • a baffle adapter installed one or more joints above the float collar (for the Type-H cementer) Use of a baffle adapter is necessary when using a Type-H cementer with a first-stage bottom plug.
Halliburton Stage Tool Free-Fall Plug Set with Insert Baffle
Halliburton Stage Tool Free-Fall Plug Set with Baffle Adapter
Wells can also be cemented in three stages with two cementers and a three-stage plug set. A three-stage plug set must be ordered separately from the cementers. 11
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Full-Opening (FO) Multiple-Stage Cementer The full-opening (FO) multiple-stage cementer is used to place an indefinite number of cement stages or other fluids at selected points along the outside of a casing string. An indefinite number of FO cementers can be run in the casing string. The standard material grade is L-80. Other grades can be supplied at the customer’s request. When one or more FO cementers are run in the casing string, the first stage of cement can be pumped in the conventional manner. All subsequent cementing stages are pumped through a workstring run inside the casing. Shifting tools run 8 to 10 ft apart on the workstring are used to open or close the FO cementer.
Halliburton Full-Opening (FO) Multiple-Stage Cementer
Unlike plug-operated or hydraulically opened stage cementers, FO cementers provide the following benefits: • They do not require operating plugs, eliminating the need for drilling out after cementing. • FO cementers can be used to test, treat, and evaluate a zone in the well before it is closed. • Multiple FO cementers can be run in the same casing string. • Operators can open and close these tools as many times as necessary. A packoff between the workstring and casing is required to direct fluid out the open ports of the FO cementer. FO cementers are available by special order for any casing grade or premium thread. For pricing information, customers must provide information about casing OD, thread type, weight, grade, and minimum hole size.
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External Sleeve Inflatable Packer Collar (ESIPC) The external sleeve inflatable packer collar (ESIPC) is a combination of the ES (Type P or Type H) cementer and a casing inflation packer. This tool provides controlled packer element inflation through the stage-tool opening seat, eliminating hydraulic valving bodies normally used with inflatable packer elements. The rubber inflatable packer element is constructed with reinforcing metal slats to reduce packer element damage during inflation. This inflatable packer element allows packer differential pressures up to 4,000 psi. The ESIPC is commonly used in horizontal well applications for cementing casing in the bend radius or vertical portion of the wellbore above an openhole completion or a slotted liner. The packer element is inflated to prevent cement from flowing downhole when it is pumped into the annulus above the tool. The ESIPC is available by special order for any casing grade or premium thread. For pricing information, customers must provide information about casing OD, thread type, weight, grade, and minimum hole size. ESIPC’s are operated with standard stage tool plug sets.
Halliburton External Sleeve Inflatable Packer Collar (ESIPC)—Type H
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Type-H Selective-Release (SR) Plug Set The Type-H selective-release (SR) plug set is used during two-stage cementing of a liner that contains a Type-H ES cementer. The plug set consists of an SR first-stage shutoff and closing plug that is normally installed on the bottom of the stinger of a liner-setting tool, which is attached to the top joint of the liner. However, if the liner-setting tool must be disconnected from the liner before cementing, the SR plug set must be installed on a launching collar located on the top joint of the liner. If a hydraulically set liner hanger requiring a ball-setting sub will be used, the ball-setting sub must be placed in the casing string above the float collar and below the baffle adapter. The ball-setting sub must retain the ball when used with Super Seal IITM floating equipment.
Closing Plug Releasing Dart
Shut-Off Plug Releasing Dart
Halliburton Selective-Release (SR) Plug Set
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After the liner hanger is set, the first-stage cement is pumped through the drillpipe, followed by a drillpipe/releasing dart that latches into and releases the lower SR shutoff plug. The SR shutoff plug is pumped through the ID of the liner to land and shut off on the baffle adapter. Drillpipe pressure applied to the shutoff plug hydraulically opens the Type-H cementer. The second-stage cement is mixed and pumped down the drillpipe, followed by a second drillpipe dart. The drillpipe/releasing dart latches into and releases the SR closing plug. The SR closing plug is pumped through the liner ID and lands in the Type-H cementer. Casing pressure is applied to close the cementer. After cementing operations are complete, the drillpipe is retrieved to the surface, and all SR plugs are drilled out.
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Formation Packer Shoes/Collars A formation packer shoe or collar, which is installed on the casing string, is used when casing will be set in a vertical hole on top of a predrilled low-pressure formation. A mechanical packer element seals the annulus between the casing and the wellbore, allowing cement to be pumped into the annulus above the packer element. Formation packer shoes/collars are available in two types: 852 series (poppet valve) and 855 series (flapper valve). The 855 series is supplied as a float shoe and can be converted to a collar when the float-shoe nose is removed.
852-Series Formation Packer Shoe/Collar The 852-series formation packer shoe/collar has a double-poppet float valve that allows the casing to be floated in the hole. However, this tool does not allow automatic casing fill while casing is run in the hole. The inverted check valve at the bottom of the tool allows well fluids to be circulated at any time before the packer is set. When the tool’s packer element is ready to be set, a weighted plastic ball (2-in. OD for a 4 1/2- to 5-in. tool, 2 3/8-in. OD for a 5 1/2-in. or larger tool) is dropped in the casing ID, falling by its own weight to a seat in the tool. Pressure is applied to the casing, shifting the tool’s valve mechanism downward, closing the bottom circulating port and expanding the packer element to seal against the wellbore. After a pressure of 1,000 psi is applied to the casing, the setting ball extrudes through the ball seat, allowing fluid to be pumped into the casing/wellbore annulus above the set packer element. The maximum recommended differential pressure across the packer element is 1,000 psi at temperatures below 200°F. Cement is mixed and pumped into the annulus, followed by a top cementing plug. The top cementing plug is pumped to a pressure shutoff on top of the tool. After cementing operations, the top cementing plug and the tool’s internal components can be drilled out. The 852-series formation packer shoe/collar should not be run above a gas zone.
Halliburton 852-Series Formation Packer Shoe
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855-Series Formation Packer Shoe/Collar The 855-series formation packer shoe/collar includes a flappertype float valve that allows the casing to be floated in the hole. If desired, an orifice tube fill-up unit can be installed in the tool, allowing casing to be filled while it is run in the hole. A setting ball (which is used to set the tool’s packer element) and a latchdown plug and baffle are packaged with each tool assembly. The latchdown plug and baffle must be installed in the casing above the formation packer shoe/collar because the tool does not contain a backpressure valve to keep cement in place in the annulus after cementing operations. After the casing has been run to the desired depth, a weighted plastic ball (2 1/4-in. OD for a 4 1/2-in. tool and 2 3/8-in. OD for a 5 1/2- or 7-in. tool) is dropped in the casing ID where it lands on a seat in the tool. Pressure applied to the casing shifts the inner sleeve of the tool downward, expanding the packer element so that it seals against the wellbore. After 1,200 psi of pressure is applied to the casing, cementing ports above the packer element are exposed, allowing fluid to be pumped into the casing/ wellbore annulus above the set packer element. Cement is then pumped into the annulus, followed by the top cementing latchdown plug. The latchdown plug seats and seals in the casing baffle, preventing cement from re-entering the casing ID. After cementing operations, the latchdown plug, baffle, and internal components of the formation packer shoe/collar can be drilled out.
Halliburton 855-Series Formation Packer Shoe
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Super-Fill™ Equipment Super-Fill™ equipment provides a reliable way for wellbore fluid to enter the casing or liner ID while the casing is being run into the hole, thereby reducing the effective wellbore surge pressure and reducing the volume of fluid lost to the formation. Super-Fill™ equipment can be used for the following applications: • on conventional full-bore casing • near the bottom of a tieback casing string (run above the tieback stinger) • on subsea completions • when a liner is run and cemented in the wellbore
Super-Fill™ Collar In a full-bore casing string, the Super-Fill™ collar is run in the open position directly above the float collar. When casing is run in the wellbore, fluid bypasses the float shoe and collar, automatically filling the casing with wellbore fluid. After the casing reaches the required setting depth, a standard five-wiper bottom cementing plug can be pumped down the casing to land on and close the Super-Fill™ collar ports. When these ports are closed, circulation fluid is diverted through the float collar and float shoe and into the casing/ wellbore annulus. Cementing operations can then be performed in the conventional manner with standard top and bottom cementing plugs. A Super-Fill™ Type TB collar can also be used when a production liner has been set in the wellbore and a tieback casing string will be installed back to the surface. During tieback applications, the Super-Fill™ Type TB collar is installed in the open position immediately above the polished bore receptacle (PBR) stinger. When the PBR stinger of the tieback string is stabbed into the PBR, operators can cement the tieback string without withdrawing the tieback from the PBR. The open ports of the Super-Fill™ collar (1) prevent a “hydraulic lock” from occurring between the PBR stinger and the PBR and (2) reduce the risk of damage to the stinger seals when the stinger is reinserted in the PBR. The SuperFill™ collar can also be used in tight annular clearances where tieback movement may be impossible after cement placement. During tieback cementing operations, the top cementing plug pumped behind the cement lands on the Super-Fill™ collar plug seat. Casing pressure applied to the top plug shears the pins in the tool, allowing the internal sleeve to shift down and permanently cover the Super-Fill™ ports. After cementing operations, the top plug and internal seats of the Super-Fill™ collar are drilled out with a PDC or roller-cone rock bit.
Halliburton Super-Fill™ Collar with Super Seal™ II Valve
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Super-Fill™ Diverter Tool The Super-Fill™ diverter tool is used on subsea or liner completions in which cementing operations are performed through drillpipe. During these applications, the small annular clearance between the previously cemented casing string or hole diameter (liner application) prevents adequate mudflow between the liner or casing being run and the previous casing string. These small annular clearances cause high mud losses to formations in the openhole section of the wellbore. A SuperFill™ collar installed on the lower end of the liner or casing allows the wellbore fluid to enter the liner or casing freely, and the Super-Fill™ diverter tool installed in the drillpipe string allows the fluid to exit the drillpipe directly above the liner. This arrangement reduces the pressure drop and the surge pressure on the formation when the liner or casing is being run, reducing mud loss into the formation. The Super-Fill™ diverter tool consists of a ported inner mandrel and an outer free-floating sleeve with drag springs. The inner mandrel contains a J-slot mechanism that allows the tool to open or close when the drillstring moves vertically. Before cementing operations, the diverter tool can be permanently locked in the closed position by moving the drillpipe upward while applying right-hand torque to the drillpipe.
Halliburton Super-Fill™ Diverter Tool
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Bow-Spring Centralizers Bow-spring centralizers help center the casing in the wellbore during cementing operations, allowing the cement to be evenly distributed around the casing string. The degree to which the casing is centered (standoff) depends on the performance of the centralizer and the spacing between the centralizers installed on the casing OD. Bow-spring centralizers, both welded and nonwelded, provide the following advantages: • They help center the casing in the wellbore, allowing even distribution of cement around the casing. • They help reduce casing drag on the wellbore during casing running operations. • They help prevent differential sticking of the casing. • They increase fluid turbulence at the tool, helping remove filter cake from the wellbore. • They can be run through hole restrictions in the wellbore or through smaller casing strings that are cemented in the well, thereby centering the casing below the restriction.
Welded Bow-Spring Centralizer Welded bow-spring centralizers are available in two styles: slip-on and hinged. Slip-on centralizers are manufactured with solid end rings, requiring the centralizer to be slipped on the casing OD during installation. Hinged centralizers are manufactured in segments, allowing the centralizer to be installed easily around the casing OD. Hinge pins hold the segments together during installation. All welded bow-spring centralizers are manufactured to API Specification 10D. The dual-contact (double bow) welded centralizer is designed for small-clearance casing-to-hole size applications. The centralizer will perform as a standard bow centralizer in holes up to 1/2 in. smaller than the centralizer’s nominal OD. When run in holes less than 1/2 in. smaller than the OD, the center of the centralizer contacts the casing OD, performing as a rigid centralizer. Because of its high restoring force with very little spring deflection, the dual-contact centralizer is excellent for deviated and horizontal wellbores. The dualcontact centralizer should only be installed between a collar and stop ring—never over a casing collar.
Halliburton Welded Bow-Spring Centralizer
Halliburton Dual-Contact Centralizer
Halliburton Nonwelded Bow-Spring Centralizer
Halliburton Welded Centralizer with Turbofins
Nonwelded Bow-Spring Centralizer Nonwelded bow-spring centralizers are available in the hinged style only. The bow springs of this centralizer are attached to the end rings without welding. The centralizer bow end is connected to the end rings with a locking tab that bears the load force on the centralizer. The centralizers are supplied in hinged segments joined by hinge pins in each segment. All nonwelded centralizers meet or exceed the requirements of API Specification 10D, which dictates the minimum restoring and maximum starting forces for centralizers for various casing/hole size combinations. Centralizers with turbofins attached to each bow spring are designed to create localized turbulent fluid flow at the centralizer. The turbofins divert the fluid flow to more evenly distribute cement around the casing. All welded and nonwelded bowspring centralizers are available in most common hole/casing sizes.
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Halliburton Cementing Casing Equipment and Accessories
Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale.
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2001 Halliburton Energy Services
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