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Floating equipment, cementing plugs, stage tools, centralizers, and scratchers are mechanical devices commonly used in running pipe and in placing cement around casing.
Floating equipment is commonly used on the lower section of the well casing to:
- Reduce the strain on the derrick during placement of the casing in the wellbore
- Help guide the casing past ledges and sidewall cavings, as the casing passes through deviated sections of the hole
- Provide a backpressure valve to prevent re-entry of cement into the casing inside diameter (ID) after it is pumped into the casing/wellbore annulus
- Provide a landing point for cementing plugs pumped in front of and behind the cement slurry
Types of floating and guiding equipment
Some basic types of floating and guiding equipment are:
- The guide shoe, with or without a hole through the guide nose
- The float shoe, containing a float valve and a guide nose
- The float shoe and float collar, containing an automatic fill-up valve
The simplest guide shoe is an open-end collar, with or without a molded nose. It is run on the first joint of casing and simply guides the casing past irregularities in the hole. Circulation is established down the casing and out the open end of the guide shoe or through side ports designed to create more agitation as the cement slurry is circulated up the annulus. If the casing rests on bottom or is plugged with cuttings, circulation can be achieved through the side ports.
Modified or float shoe
A modified guide or float shoe with side ports may aid in running the casing into a hole where obstructions are anticipated. This tool has side ports above, and a smaller opening through, the rounded nose. The smaller opening ensures that approximately 60% of the fluid is pumped through the existing side ports. These ports help wash away obstructions that may be encountered and also aid in getting the casing to bottom, if some of the cuttings have settled in the bottom of the hole.
The jetting action of the side-port tool types aids in removing the cuttings and helps provide a cleaner wellbore with increased turbulence during circulation and cementing. It also aids in the uniform distribution of the slurry around the shoe.
The combination guide or float shoe usually incorporates a ball or spring-loaded backpressure valve. The outside body is made of steel of the same strength as that of the casing. The backpressure valve is enclosed in plastic and high-strength concrete. The valve, which is closed by a spring or by hydrostatic pressure from the fluid column in the well, prevents fluids from entering the casing while pipe is lowered into the hole. After the casing has been run to the desired depth, circulation is established through the casing and float valve and up through the annulus. When the cement job is completed, the backpressure valve prevents cement from flowing back into the casing.
Float collars are usually placed one to three joints above the float or guide shoe in the casing string, and serve the same basic functions as the float shoe (Fig. 1). They contain a backpressure valve similar to the one in the float shoe and provide a smooth surface or latching device for the cementing plugs. Float collars are also available with nonrotating (NR) inserts. When cementing plugs with matching inserts are used during cementing operations, the plugs are locked to the float collar, preventing spinning of the plugs during drillout. This equipment may reduce drillout time of the “shoe track” by 80%. The space between the float collar and the guide shoe traps contaminated cement or mud that may accumulate from the wiping action of the top cementing plug. The contaminated cement is, thus, kept away from the shoe, where the best bond is required.
When the cement plug sits at the float collar (Fig. 2), it shuts off fluid flow and prevents overpumping of the cement. A pressure buildup at the surface indicates that cement placement is complete. For larger casing, float collars or shoes may be obtained with a special stab-in device that allows the cement to be pumped through tubing or drillpipe. (This method of placement is often called inner-string cementing.) Such a device eliminates the need for large cementing plugs and oversize plug containers.
Insert flapper valve
For reasons of economy, a simple insert flapper valve and seat may be installed in the casing string one or two joints above the guide shoe. This insert valve is designed for use in shallow wells for pressures less than the collapse pressure of J-55 casing in the particular weight range being used. Insert flapper-valve-equipment may be run with an orifice tube holding the flapper valve in the open position to allow the casing to automatically fill as it is being run in the wellbore. The opening through the fill tube may be varied to allow heavy concentrations of lost-circulation material to pass through the tube. After the casing has been landed at the desired depth, a weighted plastic ball is dropped in the casing to shear out the orifice tube and allow the flapper valve to close. The insert flapper valve, like the float collar, provides a space for isolating contaminated cement. It also provides a surface for landing the cement plug.
Differential-fill-up and automatic-fill-up float collars and float shoes
Differential-fill-up and automatic-fill-up float collars and float shoes permit a controlled amount of fluid to enter the bottom of the casing while the casing is being run in the hole (Fig. 3). They operate on the principle that hydrostatic pressure in the annulus will tend to balance the hydrostatic pressure proportionally inside the casing. A restricted area allows a controlled amount of fluid to enter the casing through the bottom of the float shoe while the casing is being run, thereby shortening running time and reducing pressure surges against the formation. The backpressure valve in automatic-fill-up equipment is held out of service until it is released by a predetermined flow rate applied from the surface through the float equipment. The rate of flow into the casing is usually low enough to hold the fluid level within 10 to 300 ft of the surface. When purchasing floating equipment, it is important to specify the outside diameter (OD), the threading, the material grade, and the pipe weight.
Plug containers hold the top and bottom cementing plugs, and come in two different versions: continuous cementing head and quick-change container. A cementing head is designed to attach to the top joint of well casing during cementing operations. The head allows cementing plugs to be released ahead of and behind the cement slurry to isolate the cement slurry from wellbore fluids ahead of the cement and displacing fluids pumped behind the slurry. Cementing heads may house one, two, or more cementing plugs. A single cementing head is used when it is not necessary to have continuous pumping of the cementing slurry. When a single cementing head is used, the bottom plug may be loaded in the head and pumped in the casing with a small volume of fluid or inserted by hand into the top of the casing and then the head installed to the top casing joint. The top plug is loaded in the cementing head for release after the cement slurry is mixed.
A double cementing head (two plugs) or multiple cementing head (three or more) allows the cementing plugs to be loaded before the cement slurry is mixed. During cementing operations, plugs can be released from the head without interrupting the pumping.
Plug containers are equipped with valves and connections for attaching cementing lines for circulation and displacement. The cement usually falls down the casing on a vacuum before the plug is released; therefore, displacing fluid can be siphoned into the casing below the top plug if the valve to the supply source is not kept closed. Because the fluid can be siphoned through the cementing pump, the valve should not be opened until the top plug has been released. Cementing heads, with an internal swivel or a swivel between the top casing collar and the cementing head, make it possible to rotate the casing during cementing operations. Quick-connect couplings on the cementing heads allow fast connection of the cementing head to the casing when the last joint is landed so that circulation can be started immediately.
For ease of operation, the cementing head should be as near the level of the rig floor as possible. A typical plug container (Fig. 4) allows a bottom plug to be inserted through the container into the casing ahead of the cement slurry. The top plug is loaded into the plug container, where it rests on a support bar. It is released by retracting the support bar after the cement is mixed. A lever on some types of plug containers indicates the passage of the plug as it leaves the container.
Cementing plugs are highly recommended to separate drilling fluid, cement, and displacing fluid. Unless a well is drilled with air or gas, the casing and hole are usually filled with drilling fluid before cementing. To minimize contamination of the interface between the mud and the cement in the casing, a bottom plug is pumped ahead of the cement slurry. This plug wipes the mud from the casing inner diameter (ID) as it moves down the pipe. When it reaches the float collar, differential pressure ruptures a diaphragm on top of the plug, allowing the cement slurry to flow through the plug and the floating equipment and up the annular space between the pipe and the hole (Fig. 5). The top cementing plug, pumped behind the cement slurry, is pumped to a shutoff on the float collar, causing a pressure increase at the surface. This is a signal that the cement has been displaced. Top and bottom plugs are similar in outward appearance, but are always different colors. The top plug (black) has a solid insert with rubber wipers molded to the insert. The bottom plug (red, orange, and yellow) has a cylinder-type insert with molded wipers and a plastic or molded rubber diaphragm designed to rupture at 200 to 400 psi. Inserts are manufactured of plastic or aluminum. Aluminum inserts increase the strength and temperature ratings of the cementing plug, and should be used when the Bottom Hole Circulating Temperature (BHCT) exceeds 300°F, and should be drilled out with conventional tricone rock bits. The recommended landing pressures for aluminum-insert plugs vary, depending on casing size, but are normally higher than the recommended landing pressures for wiper plugs with plastic inserts. Plastic-insert plugs can be used in wells with a BHCT below 300°F and can be drilled out with tri-cone rock or polycrystalline-diamond compact (PDC) bits.
Nonrotating cement plugs
Nonrotating five-wiper cementing plugs (Fig. 5) are manufactured with locking teeth on both the top and bottom plug to land on an NR float collar with similar locking teeth. These locking teeth lock the plug to the float collar, preventing spinning during drillout, which reduces drillout times and associated rig costs. NR plugs use plastic inserts that allow easy drillout with either PDC bits or tricone rock bits. High-strength NR plugs and float collars can be used to pressure-test casing immediately after cementing operations are completed.
There are times, however, when a bottom plug should not be used; for example, when the cement contains large amounts of lost-circulation material, or when the casing being used is badly rusted or scaled. Under such conditions, a bottom plug could cause bridging and plugging of the casing. In some cases, water or a chemical flush should precede the cement slurry to clean the casing of the mud solids. This is not as effective as the mechanical wiping action of the bottom plug, but it will reduce the amount of contaminated slurry. The top plug follows the cement slurry, wiping it from the casing wall.
Although the conventional wiper plugs are the most widely used, there are other designs available for primary cementing (Fig. 6):
- Wooden plugs
- Subsea plugs
- Teardrop or latch-down devices
The latch-down casing plug and baffle may be used with most conventional floating equipment, but they are most commonly used in small-diameter tubing for inner-string cementing. This type of plug system, supplementing the float valve, prevents fluid from re-entering the casing string. When all the cement has been pumped, the latch-down plug allows surface pressure to be released immediately and also prevents the cement and plug from being backed up into the casing by air compressed below the plug. If completions are made fairly close to the float collar, the latch-down plug system eliminates the need to drill out the cement.
Subsea completions and conventional liner jobs can be cemented with the standard two-plug cementing techniques. They require the cement slurry to be pumped through a string of drillpipe that is smaller than the casing string being cemented. The downhole release system can wipe both the drillpipe and the casing, and can separate the cement slurry and displacing fluid.
The downhole release plugs are attached to an installation tool in the top of the casing to be cemented. The bottom plug is fastened to the top plug, which, in turn, is fastened to the installation tool. These tools use a ball or a releasing plug to release the bottom plug from the top plug by pressuring to a predetermined amount and shearing some pins. This allows the bottom plug to be pumped ahead of the cement slurry while wiping mud solids off the casing and separating the cement slurry from the wellbore fluid. A top-plug-releasing dart is pumped behind the cement slurry to separate the cement and displace fluid in the drillpipe. The top-plug-releasing dart will latch into the top wiper plug in the casing. A predetermined amount of pressure releases the top wiper plug, which is then pumped down as a solid plug through the casing behind the cement slurry.
When the top plug is to be displaced by drilling fluid or water, the volume of the displacing fluid should be measured as the cement pumps and compared with the volume measured in the water or mud tanks. Where there is a flowmeter, it can be used to crosscheck. When the top plug lands on the bottom plug, a pressure increase is indicated at the surface because no fluid can be pumped through the floating equipment. If the top plug does not “bump” (i.e., seat at the float collar) causing a pressure increase at the calculated displacement volume, the pumping should be stopped so that cement slurry will not be displaced out of the casing.
A cementing manifold is commonly used with a discharge line to the pit for flushing the cement truck. It is assembled to permit pumping the plug out of the cementing head with the displacement fluid.
If casing movement is employed, it should be continued throughout the mixing cycle. Frequently, movement is continued while plugs are released and until the top plug bumps, although it is not uncommon to stop while either or both plugs are being inserted.
Multiple-stage cementing tools
Stage cementing usually reduces mud contamination and lessens the possibility of formation breakdown, which is often a cause of lost circulation. Stage tools are installed at a specific point in the casing string as casing is being run into the hole. When it is desirable to cement two or three separate sections behind the same casing string or to cement a long section in two or three stages, multiple-stage cementing tools are used. During multiple-stage cementing, cement slurry is placed at predetermined points around the casing string in several cementing stages. Multiple-stage cementing tools can be used for these 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
Types of multiple-stage cementing tools
Two types of multiple-stage cementing tools are available:
- Hydraulically opened
The type selected depends on well conditions. After cement has been placed around the bottom of the well casing, in the conventional manner, the multiple-stage tool may be opened, either hydraulically, by applying casing pressure (hydraulically opened tool), or with a free-fall opening plug dropped down the casing ID (plug-operated). When the tool is opened, fluid, such as cement, can be circulated through its outside ports. When all the cement slurry has been placed, a closing plug pumped down the casing behind the cement closes a sleeve over the side port.
Because the multiple-stage cementing tool contains sliding internal or external sleeves, certain precautions must be taken when it is installed into the casing string. The casing tongs should be placed only on the upper and lower 6 in. of the tool. The tongs should never be placed on the midsection of the casing. This could deform the casing, causing the tool to be inoperative.
Bending forces, resulting from hole deviation or casing deflection, will not damage the tool unless the yield strength of the casing itself is exceeded. Because the OD of the tool is larger than the casing OD, doglegs and key seats, encountered when going into the hole, may cause the tool to stick. Casing centralizers should be installed on the casing as close as possible to each end of the tool to guide it and to provide clearance with the sides of the hole.
Plug-operated stage cementing
The plug-operated free-fall stage-cementing method is used when the first-stage cement is not required to fill the annulus from the bottom of the casing all the way to the stage tool, or when the distance between the tool and the casing shoe is fairly long. The primary advantage of this method is that the shutoff plug used in the first stage prevents overdisplacement of the first-stage cement.
The time for the free-falling plug to reach the tool must be estimated because there will be no surface indication when it lands. Many factors, including the viscosity and density of the fluid in the casing and large deviations of the hole from vertical, affect the plug’s falling rate and must be considered when waiting time is estimated. A good rule of thumb is to allow 1 minute for each 200 to 400 ft of depth. The maximum deviation that the plug can reasonably be expected to fall is 30°. A deviation greater than 30° will probably cause the plug to hang up at a collar, requiring the plug to be pushed to the tool by a wireline sinker bar or work string (Fig. 7).
Hydraulically open stage cementing tool
The hydraulically opened or displacement stage-cementing tool is used when the cement is to be placed in the entire annulus from the bottom of the casing up to or above the stage tool. The displacement method is often used in deep or deviated holes in which too much time is needed for a free-falling plug to reach the tool. Fluid volumes must be calculated accurately and measured carefully to prevent overdisplacement or underdisplacement of the first stage.
Two-stage cementing is the most widely used multiple-stage cementing technique. However, when a cement slurry must be distributed over a long column and hole conditions will not allow circulation in one or two stages, a three-stage method can be used. The same steps are involved as in the two-stage method, except there is an additional stage. Most multiple-stage cementing tools are designed with drillable seats that must be drilled out after cementing operations are completed. These drillable seats allow drillout with either standard tri-cone rock bits or PDC bits.
The uniformity of the cement sheath around the pipe determines, to a great extent, the effectiveness of the seal between the wellbore and the casing. Because holes are rarely straight, the pipe is generally in contact with the wall of the hole at several places. Hole deviation may vary from zero to, in offshore directional holes, as much as 70 to 90°. Such severe deviation greatly influences the number and spacing of centralizers (Fig. 8).
A great deal of effort has been expended to determine the relative success of running casing strings with and without centralizers. Although experts differ on the proper approach to an ideal cement job, they generally agree that success hinges on the proper centralization of casing. Centralizers are among the few mechanical aids covered by API specifications.
Centralizing the casing with mechanical centralizers across the intervals to be isolated helps optimize drilling-fluid displacement. In poorly centralized casing, cement will bypass the drilling fluid by following the path of least resistance. The cement travels down the wide side of the annulus, leaving drilling fluid in the narrow side. When properly installed in gauge sections of a hole, centralizers:
- Prevent drag while pipe is run into the hole
- Center the casing in the wellbore
- Minimize differential sticking, thus, helping to equalize hydrostatic pressure in the annulus
- Reduce channeling and aid in mud removal.
Types of centralizers
Two general types of centralizers are:
The spring-bow type has a greater ability to provide a standoff where the borehole is enlarged.
The rigid type provides a more positive standoff where the borehole is close to gauge.
Positive-type centralizers are ¼ to ½ in. smaller in diameter than the hole size where they are to be run and, therefore, have no drag forces with the wellbore.
Rigid-type centralizers are commonly run in horizontal wellbores, because of their positive standoff. Both spring-bow and rigid centralizers are available in almost any casing/hole size. The important design considerations are positioning, method of installation, and spacing. Centralizers should be positioned on the casing through intervals requiring effective cementing, on the casing adjacent to (and sometimes passing through) the intervals where differential-sticking is a hazard, and, occasionally, on the casing passing through doglegs where key seats may exist.
Good pipe standoff helps ensure a uniform flow pattern around the casing, and helps equalize the force that the flowing cement exerts around the casing, increasing drilling-fluid removal. In a deviated wellbore, standoff is even more critical to help prevent a solids bed from accumulating on the low side of the annulus. The preferred standoff should be developed from computer modeling, and will vary with well conditions. Under optimum rates, the best drilling-fluid displacement is achieved when annular tolerances are approximately 1 to 1.5 in. Effective cementing is important through the production intervals and around the lower joints of the surface and intermediate casing strings to minimize the likelihood of joint loss.
Restraining devices (collar or stop collars)
Centralizers are held in their relative position on the casing either by casing collars or mechanical stop collars. The restraining device (collar or stop collar) should always be located within the bow-spring-type centralizer, so the centralizer will be pulled, not pushed, into the hole. The bow-spring-type centralizer should not be allowed to ride free on a casing joint.
Fastening devices for casing attachments
All casing attachments should be installed or fastened to the casing by some method, depending on the type (i.e., solid body, split body, or hinged). If they are not installed over a casing collar, a clamp must be used to secure or limit the travel of the various casing attachments.
There are a number of different types of clamps. One type is simply a friction clamp that uses a setscrew to keep the clamp from sliding. Another type uses spiral pins driven between the clamp and the casing to supply the holding force (Fig. 9). Others have dogs (or teeth) on the inside that actually bite into the casing. Any clamp that might scar the surface of the casing should not be used where corrosion problems exist.
Placement of centralizers
Most service companies offer computer programs on the proper placement of centralizers, based on casing load, hole size, casing size, and hole deviation. All computer spacing programs are based on a standoff of 66% used in API Spec. 10D. The computer programs determine placement of the centralizers on the casing string, depending on the well data entered into the program. The programs are based on the equations published in API Spec. 10D.
Design of centralizers
The design of centralizers varies considerably, depending on the purpose and the vendor. For this reason, the API specifications cover minimum performance requirements for standard and close-tolerance spring-bow casing centralizers.
Definitions in API Spec. 10D cover:
- Starting force
- Running force
- Restoring force
The starting force is the maximum force required to start a centralizer into the previously run casing. The maximum starting force for any centralizer should be less than the weight of 40 ft of medium-weight casing. The maximum starting force should be determined for a centralizer in its new, fully assembled condition as delivered to the end user.
The running force is the maximum force required to move a centralizer through the previously run casing. The running force is proportional to and always equal to or less than the starting force. It is a practical value that gives the maximum “running drag” produced by a centralizer in the smallest specified hole size.
The restoring force is the force exerted by a centralizer against the casing to keep it away from the borehole wall. The restoring force required from a centralizer to maintain adequate standoff is small in a vertical hole but substantial for the same centralizer in a deviated hole. Centralizing smaller annuli is difficult, and pipe movement and displacement rates may be severely restricted. Larger annuli may require extreme displacement rates to generate enough flow energy to remove the drilling fluid and cuttings. Centralizers and other mechanical cementing aids that are commonly used in the industry may also serve as inline laminar-flow mixers, changing the flow pattern of the fluids, which can promote better drilling-fluid removal and greater displacement.
Scratchers, or wall cleaners, are devices that attach to the casing to remove loose filter cake from the wellbore. They are most effective when used while the cement is being pumped. Like centralizers, scratchers help to distribute the cement around the casing.
Types of scratchers
There are two general types of scratchers:
- Those that are used when the casing is rotated
- Those that are used when the casing is reciprocated
The rotating scratcher is either welded to the casing or attached with limit clamps. The scratcher claws are high-strength-steel wires with angled ends that cut and remove the mudcake during rotation. The claws may have a coil spring at the base to reduce breaking or bending when the casing is run into the hole. When the pipe must be set at a precise depth, rotating scratchers should be used, but there must be assurance that the pipe can be freely rotated. Because rotating scratchers are damaged by excessive torque on the casing, they are generally not used where the risk of excessive torque is high, such as in deep or deviated wells.
Reciprocating scratchers (Fig. 10), also constructed of steel wires or cables, are installed on the casing with either an integral or a separate clamping device. When the desired depth is reached, reciprocating the casing (working it up and down) cleans the wellbore on the upstroke by removing mud and filter cake. Reciprocating scratchers are more effective where there is no depth limitation in setting casing and where the pipe can be either rotated or reciprocated after it is landed.
Mud-diverter equipment is designed for use with a drillpipe when liners are being run or in subsea completions where the wellhead is located on the ocean floor. It allows a fluid flowpath from the drillpipe ID into the annulus above the liner. A drag-spring system on the outer case of the tool causes the drillpipe movement that opens and closes the mud-diverter-equipment ports.
This equipment is used for liner applications where small annular clearances prevent mudflow between the liner being run and the previous casing string. Such conditions cause high mud loss into formations in the openhole section of the wellbore. Reliable automatic-fill equipment, installed on the lower end of the liner, can allow the wellbore fluid to enter the liner freely, and the drillpipe diverter equipment can allow the fluid to exit the drillpipe immediately above the liner. This arrangement helps reduce the pressure drop and the surge pressure on the formation while the liner is being run, which helps reduce costly mud loss into the formation. A mud-saver system that includes the diverter can be used on a liner or subsea completion. The use of this diverter equipment can eliminate the need to take returns at the surface.
Bridge plugs are devices that are set in open hole or casing as temporary, retrievable plugs or permanent, drillable plugs. They cannot be pumped through, and are used to prevent fluid or gas from moving in the wellbore. Bridge plugs are also used to:
- Isolate a lower zone, while an upper section is being tested
- Establish a bridge above or below a perforated section that is to be squeezed, cemented, or fractured
- Provide a pressure seal for casing that is to be tested or for wells that are to be abandoned
- Seal off zones to be abandoned to allow the upper casing to be recovered
- Plug casing, while surface equipment is being repaired
Cement baskets and external packers
Cement baskets and external packers (Fig. 11) are used with casing or liner at points where porous or weak formations require help in supporting the cement column until it takes its initial set. Baskets may be installed by slipping them over the casing and using either the collars or limit clamps to hold them in place. External packers are placed in the casing string as it is run in the well. They are expanded before cementing begins.
High-energy displacement rates are most effective in ensuring good displacement. Turbulent flow around the full circumference of the casing is most desirable, but it is not required. When turbulent flow is not a viable option for a formation or wellbore configuration, use the highest pump rate that is feasible for the wellbore conditions. The best results are obtained when the spacer and/or cement is pumped at maximum energy; the spacer or flush is appropriately designed to remove the drilling fluid; and a good, competent cement is used.
Implementation of the cement pumping unit
Cement pumping units may be mounted on a truck, trailer, skid, or waterborne vessel. They are usually powered by either internal-combustion engines or electric motors, and are operated intermittently at high pressures and at varying rates. Pumping units must be capable of providing a wide range of pressures and rates to facilitate the requirements of modern cementing practices, and have the lowest practical weight-to-horsepower ratio to facilitate transportation.
Cementing units are normally equipped with two positive-displacement pumps. On a high-pressure system, one pump mixes while the other displaces. On a low-pressure system, a centrifugal pump mixes, and two positive-displacement pumps are available for displacement. For recirculating mixing, one centrifugal pump supplies water to the mixing jet, and another centrifugal pump recirculates slurry back through the mixing jet. As with a low-pressure system, two positive-displacement pumps are available to pick up the slurry and pump it down the well.
Nearly all cementing pumps are positive-displacement, and are either duplex double-acting piston pumps or single-acting triplex plunger pumps. Either is satisfactory within its design limits. For heavy-duty pumping, triplex pumps discharge more smoothly, and can usually handle higher horsepower and greater pressure than duplex pumps. Most cementing work involves a maximum pressure of less than 5,000 psi, but pressures as high as 20,000 psi are not uncommon. Because of widely varying operating conditions, the cementing pump and its power train are designed for the maximum rather than the average expected pressures.
Estimating the required number of pumping units
For a given job, the number of trucks used to mix cement depends on the volume of cement, well depth, and expected pressures. For surface and conductor strings, one truck is usually adequate, whereas for intermediate or production casing, as many as three units may be required. On jobs requiring more than 1,000 sk, or where high pressures are expected, two or sometimes three mixing trucks are used. A separate mixing system is used for each truck, with each unit tied to a common pumping manifold. If the pipe is to be reciprocated, the mixing trucks are tied into a temporary standpipe, which supports a flexible line leading to the cementing head.
Field slurries are usually mixed and pumped into the casing at the highest feasible rate, which varies from 20 to 50 sk/min depending on the capacity of each mixing unit. As a result, the first sack of cement on a primary cement job reaches bottomhole conditions rather quickly.
The mixing system proportions and blends the dry cementing composition with the carrier fluid (water), supplying to the wellhead a cementing slurry with predictable properties.
The recirculating mixer, designed for mixing more-uniform homogeneous slurries, is a pressurized jet mixer with a large tub capacity (Fig. 12). It uses recirculated slurry and mixing water to partially mix and discharge the slurry into the tub. The recirculating pump provides additional shear, and agitation paddles or jets provide additional energy and improve mixing. The result is a uniform cement slurry, with a density as high as 22 lbm/gal, which can be pumped as slowly as 0.5 bbl/min.
Batch mixing is used to blend a cement slurry at the surface before it is pumped into the well. The batch mixer is not part of the cement pumping unit; it is a separate piece of equipment. The batch mixer is used when a specified volume of cement is required. The mixing tank in the batch mixer is filled with enough water for a specified amount of cement. The mixing turbine circulates the water, as dry cement is added until the desired slurry consistency and volume are obtained. A prehydrator is used to wet the dry cement to prevent dust problems. Primary disadvantages of a batch mixer are volume limitations and the need to use an additional piece of equipment. However, units with multiple mixing tanks may be used for continuous cementing to provide precise slurry consistency and volume. For mixing densified or heavyweight slurries to be pumped at rates of less than 5 bbl/min, a recirculating mixer produces a more uniform slurry.
- API Spec. 10D, Specification for Casing Centralizers, third edition. 1986. Dallas, Texas: API.