PEH:Cementing

Publication Information

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume II - Drilling Engineering

Robert F. Mitchell, Editor

Chapter 9 - Cementing

By Ron Crook, Halliburton

Pgs. 369-431

ISBN 978-1-55563-114-7
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Cementing operations can be divided into two broad categories: primary cementing and remedial cementing. The objective of primary cementing is to provide zonal isolation. Cementing is the process of mixing a slurry of cement and water and pumping it down through casing to critical points in the annulus around the casing or in the open hole below the casing string. The two principal functions of the cementing process are to restrict fluid movement between the formations and to bond and support the casing.

If this is achieved effectively, the economic, liability, safety, government regulations, and other requirements imposed during the life of the well will be met. Zonal isolation is not directly related to production; however, this necessary task must be performed effectively to allow production or stimulation operations to be conducted. Thus, the success of a well depends on this primary operation. In addition to isolating oil-, gas-, and water-producing zones, cement also aids in (1) protecting the casing from corrosion, (2) preventing blowouts by quickly forming a seal, (3) protecting the casing from shock loads in deeper drilling, and (4) sealing off zones of lost circulation or thief zones.

Remedial cementing is usually done to correct problems associated with the primary cement job. The most successful and economical approach to remedial cementing is to avoid it by thoroughly planning, designing, and executing all drilling, primary cementing, and completion operations. The need for remedial cementing to restore a well ’ s operation indicates that primary operational planning and execution were ineffective, resulting in costly repair operations. Remedial cementing operations consist of two broad categories: squeeze cementing and plug cementing.

In general, there are five steps required to obtain successful cement placement and meet the objectives previously outlined.

Analyze the well parameters; define the needs of the well, and then design placement techniques and fluids to meet the needs for the life of the well. Fluid properties, fluid mechanics, and chemistry influence the design used for a well.
Calculate fluid (slurry) composition and perform laboratory tests on the fluids designed in Step 1 to see that they meet the needs.
Use necessary hardware to implement the design in Step 1; calculate volume of fluids (slurry) to be pumped; and blend, mix, and pump fluids into the annulus.
Monitor the treatment in real time; compare with Step 1, and make changes as necessary.
Evaluate the results; compare with the design in Step 1, and make changes as necessary for future jobs.

Well Parameters

Along with supporting the casing in the wellbore, the cement is designed to isolate zones, meaning that it keeps each of the penetrated zones and their fluids from communicating with other zones. To keep the zones isolated, it is critical to consider the wellbore and its properties when designing a cement job.

Depth

The depth of the well influences the amount of wellbore fluids involved, the volume of wellbore fluids, the friction pressures, the hydrostatic pressures, the temperature, and, thus, the cement slurry design. Wellbore depth also controls hole size and casing size. Extremely deep wells have their own distinct design challenges because of high temperatures, high pressures, and corrosive fluids.

Wellbore Geometry

The geometry of the wellbore is important in determining the amount of cement required for the cementing operation. Hole dimensions can be measured using a variety of methods, including acoustic calipers, electric-log calipers, and fluid calipers. Openhole geometry can indicate adverse (undesirable) conditions such as washouts. Wellbore geometry and casing dimensions determine the annular volume and the amount of fluid necessary.

The hole shape also determines the clearance between the casing and the wellbore. This annular space influences the effectiveness of drilling-fluid displacement. A minimum annular space of 0.75 to 1.5 in. (hole diameter 2 to 3 in. greater than casing diameter) is recommended. Annular clearances that are smaller restrict the flow characteristics and generally make it more difficult to displace fluids.

Another aspect of hole geometry is the deviation angle. The deviation angle influences the true vertical depth and temperatures. Highly deviated wellbores can be challenging because the casing is not as likely to be centered in the wellbore, and fluid displacement becomes difficult.

Problems created by geometry variations can be overcome by adding centralizers to the casing. Centralizers help to center the casing within the hole, leaving equal annular space around the casing.

Temperature

The temperatures of the wellbore are critical in the design of a cement job. There are basically three different temperatures to consider: the bottomhole circulating temperature (BHCT), the bottomhole static temperature (BHST), and the temperature differential (temperature difference between the top and bottom of cement placement). The BHCT is the temperature to which the cement will be exposed as it circulates past the bottom of the casing. The BHCT controls the time that it takes for the cement to setup (thickening time). BHCT can be measured using temperature probes that are circulated with the drilling fluid. If actual wellbore temperature cannot be determined, the BHCT can be estimated using the temperature schedules of American Petroleum Inst. (API) RP10B.^[1] The BHST considers a motionless condition where no fluids are circulating and cooling the wellbore. BHST plays a vital role in the strength development of the cured cement.

The temperature differential becomes a significant factor when the cement is placed over a large interval and there are significant temperature differences between the top and bottom cement locations. Because of the different temperatures, commonly, two different cement slurries may be designed to better accommodate the difference in temperatures.

The bottomhole circulating temperature affects slurry thickening time, rheology, fluid loss, stability (settling), and set time. BHST affects compressive-strength development and cement integrity for the life of the well. Knowing the actual temperature that the cement will encounter during placement allows operators to optimize the slurry design. The tendency to overestimate the amount of materials required to keep the cement in a fluid state for pumping and the amount of pumping time required for a job often results in unnecessary cost and well-control problems. Most cement jobs are completed in less than 90 minutes.

To optimize cost and displacement efficiency, the guidelines discussed next are recommended. Design the job on the basis of actual wellbore circulating temperatures. A downhole temperature subrecorder can be used to measure the circulating temperature of the well. A subrecorder is a memory-recorder device that can either be lowered by wireline or dropped into the drillpipe and measures the temperature downhole during the circulating operation before cementing. The memory recorder is then retrieved from the drillpipe and the BHCT is measured. This allows for accurate determination of the downhole temperature.

If determining the actual wellbore circulating temperature is not possible, use API RP10B to estimate the BHCT.^[2]
Do not "pad" the actual downhole temperatures measured, and do not exceed the amount of dispersants, retarders, etc. recommended for the temperature of the wellbore. When determining the amount of retarder required for a specific application, consider the rate at which the slurry will be heated.

Formation Pressures

When a well is drilled, the natural state of the formations is disrupted. The wellbore creates a disturbance where only the formations and their natural forces existed before. During the planning stages of a cement job, information about the formations ’ pore pressure, fracture pressure, and rock characteristics must be known. Generally, these factors will be determined during drilling. The density of the drilling fluids in a properly balanced drilling operation can be a good indication of the limitations of the wellbore.

To maintain the integrity of the wellbore, the hydrostatic pressure exerted by the cement, drilling fluid, etc. must not exceed the fracture pressure of the weakest formation. The fracture pressure is the upper safe pressure limitation of the formation before the formation breaks down (the pressure necessary to extend the formation’ s fractures). The hydrostatic pressures of the fluids in the wellbore, along with the friction pressures created by the fluids’ movement, cannot exceed the fracture pressure, or the formation will break down. If the formation does break down, the formation is no longer controlled, and lost circulation results. Lost circulation, or fluid loss, must be controlled for successful primary cementing. Pressures experienced in the wellbore also affect the strength development of the cement.

Formation Characteristics

The composition of formations can present compatibility problems. Shale formations are sensitive to fresh water and can slough off if special precautions, such as increasing the salinity of the water, are not taken. Other formation and chemistry considerations, such as swelling clays and high-pH fluids, should be taken into consideration. Some formations may also contain flowing fluids, high-pressure fluids, corrosive gases, or other complex features that require special attention.

Cement-Placement Design

Primary Cementing

Most primary cement jobs are performed by pumping the slurry down the casing and up the annulus; however, modified techniques can be used for special situations. These techniques are cementing through pipe and casing (normal displacement technique), stage cementing (for wells with critical fracture gradients), inner-string cementing through tubing (for large-diameter pipe), outside or annulus cementing through tubing (for surface pipe or large casing), reverse-circulation cementing (for critical formations), delayed-set cementing (for critical formations and to improve placement), and multiple-string cementing (for small-diameter tubing).

Cementing through Pipe and Casing

Conductor, surface, protection, and production strings are usually cemented by the single-stage method, which is performed by pumping cement slurry through the casing shoe and using top and bottom plugs. There are various types of heads for continuous cementing, as well as special adaptors for rotating or reciprocating casing.

Stage Cementing

Stage cementing is used to ensure annular fill and seal across selected intervals whenever a continuous single-stage, lead and tail, or lightweight (foamed, ceramic spheres, etc.) cementing application cannot be performed. Stage-cementing tools, or differential valve (DV) tools, are used to cement multiple sections behind the same casing string, or to cement a critical long section in multistages. Stage cementing may reduce mud contamination and lessens the possibility of high filtrate loss or formation breakdown caused by high hydrostatic pressures, which is often a cause for lost circulation.

Stage tools are installed at a specific point in the casing string as casing is being run into the hole. The first (or bottom) cement stage is pumped through the tool to the end of the casing and up the annulus to the calculated-fill volume (height). When this stage is completed, a shutoff or bypass plug can be dropped or pumped in the casing to seal the stage tool. A free-falling plug or pumpdown dart is then used to hydraulically set the stage tool and open the side ports, allowing the second cement stage (top stage) to be displaced above the tool. A closing plug is used to close the sliding sleeve over the side ports at the end of the second stage and serves as a check valve to keep the cement from U-tubing above and back through the tool.

The displacement stage-cementing method 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 (mud, spacer, cement) must be accurately calculated and prepared on locations and densities closely measured to prevent over- or underdisplacement of the first stage. Overdisplacement can result in improper opening of the tool to apply the second (upper) stage, resulting in excess pressures or job failure. Underdisplacement creates a gap (void) in the cement column at the stage tool, which results in poor zonal isolation. 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 methods, except that there is an additional stage. Obviously, the more stages used in the application, the more complicated the job will become. Although stage cementing was very popular many years ago, new foamed-cement and nonfoamed-ultralightweight-cement technologies have successfully reduced the need for multistage cementing in many operations.

Inner-String Cementing

When large-diameter pipe is cemented, tubing or drillpipe is commonly used as an inner string to place the cement. This procedure reduces the cementing time and the volume of cement required to bump the plug. The technique uses modified float shoes, guide shoes, or baffle equipment, with sealing adaptors attached to small-diameter pipe. Cementing through the inner string permits the use of small-diameter cementing plugs. If the casing is equipped with a backpressure valve or latchdown baffle, the inner string can be disengaged and withdrawn from the casing as soon as the plug is seated, while preparations are made to drill deeper.

Outside or Annulus Cementing

A method commonly used on conductor or surface casing to bring the top of the cement to the surface consists of pumping cement through tubing or small-diameter pipe run between casings or between the casing and the hole. This method is sometimes used for remedial work. Casing can suffer damage when gas sands become charged with high pressure from surrounding wells. In such instances, cementing the annulus between strings through a casinghead connection can repair the casing.

Reverse-Circulation Cementing

The reverse-circulation cementing technique involves pumping the slurry down the annulus and displacing the drilling fluid back up through the casing. The float equipment, differential fill-up equipment, and wellhead assembly must be modified. This method is used when the cement slurry cannot be pumped in turbulent flow without breaking down the weak zones above the casing shoe. Reverse circulation allows for a wider range in slurry compositions, so heavier or more-retarded cement can be placed at the lower portion of casing, and lighter or accelerated cement can be placed at the top of the annulus. Caliper surveys should be made before the casing is run, to determine the necessary volume of cement and minimize overplacement.

Delayed-Set Cementing

Delayed-set cementing involves placing a retarded cement slurry containing a filtration-control additive in a wellbore before running the casing. This method can help to obtain a more uniform sheath of cement around the casing than may be possible with conventional methods. The cement is placed by pumping it down the drillpipe and up the annulus. The drillpipe is then removed from the well, and casing or liner is sealed at the bottom and lowered into the unset cement slurry. After the cement slurry is set, the well can be completed with conventional methods.

This technique has been used in tubingless-completion wells by placing the slurry down one string and lowering multiple tubing strings into the unset cement. When the casing is run into the cement slurry, drilling fluid left in the annulus mixes with the cement slurry. Although not ideal, this development is preferred to leaving the drilling fluid in the annulus as a channel or pocket. The delayed-set cement slurry allows protracted reciprocation of the casing string, which is more likely to ensure a uniform cement sheath.

A disadvantage to delayed-set cementing is the increased water/oil-contact (WOC) time, which could be expensive if a drilling rig is kept on location while the cement sets and gains strength. If the drilling rig can be moved off location and a workover rig can complete the well, the cost can be reduced.

Multiple-String Cementing

Multiple-casing completions are used when single or conventional completions are not economically attractive. When multiple strings are placed in a well, each string is usually run independently, and the longest string is landed first. The first string is set in the hanger and is circulated before the second string is run. After the second string is landed in the hanger, it is circulated while the third string is run. In areas where lost circulation is a known problem, cement can be placed through the longest casing string. Once the cement fill-up has been established, the remainder of the hole is filled with cement slurry through a shorter string.

Centralizers are frequently used, one per joint from 100 ft above to 100 ft below productive zones. Other casing equipment in these small-diameter holes includes landing collars for cement wiper plugs, full-opening guide shoes, and limited-rotating scratchers for single completions. All float equipment, centralizers, and scratchers should be able to pass the hanger assembly in the casinghead.

Other factors considered in the design of cement slurry are similar to those considered in the design of slurry for a single string of pipe. The cement is usually pumped down the longest strings simultaneously, although this is not mandatory. The idle strings may be pressured to 1,000 to 2,000 psi during cementing to safeguard against leakage, thermal buckling, or collapse.

Cementing of High-Pressure/High-Temperature Wells

Recent technological advances have allowed the production of reservoirs that were once considered too expensive and risky to be commercially viable. Designs for these wells must withstand high temperatures and pressures, as well as frequently encountered corrosive gases such as H₂S and CO₂ . Completions performed in high-pressure/high-temperature (HP/HT) reservoirs are some of the most expensive in the industry. High completion costs make it a necessity to successfully cement the well casing on the primary cementing job and eliminate the need for remedial cementing. HP/HT reservoirs are characterized by reservoir depths greater than 15,000 ft, reservoir pressure greater than 15,000 psi, and reservoir-fluid temperatures from 300 to 500°F.

To provide optimum zonal isolation, one should consider not only the primary cementing job, but also the long-term, post-placement effects of various operations that can place stress on the set cement. In the initial cementing, the job should be designed to displace the drilling fluid completely and to prevent gas migration and fluid loss. Once the initial cement job is completed, the effects of stress throughout the well ’ s life will determine the cement sheath’ s future viability.

In most wells, the liner or production string is the most important component. In HP/HT wells, the conductor string can be placed under greater loading and all sections of the well can be exposed to formation, temperature, and pressure changes that are greater than normal; therefore, the well should be examined from the whole-well perspective.

A well’ s characteristics determine the cement-slurry properties and performance. A careful and thorough review of these characteristics is essential for designing an effective cement slurry and ensuring correct placement. Engineers should combine individual variables to develop a total-cement-job design.

Guidelines for improving cementing results are:

Condition the drilling fluid to break its gel structure, thereby reducing its viscosity and improving its mobility.
Use pipe movement to dislodge pockets of gelled, immobile drilling fluid.
Use mechanical scratchers and wall cleaners to maximize pipe-movement effectiveness, which can erode excess drilling fluid.
Centralize pipe in and near "critical" zones. A minimum of 70% casing standoff is recommended. Good pipe standoff helps increase drilling-fluid removal, thereby equalizing forces exerted by cement flowing up the annulus.
Use the highest possible pump rates to get the greatest displacement efficiency.
Use spacers and/or flushes to isolate dissimilar fluids and prevent potential contamination problems.
Use a drilling fluid with a rheology that allows efficient drilling-fluid removal without raising the equivalent circulating density (ECD) to an unacceptable level.
Use enough spacer and/or flush to allow adequate contact time (7 to 10 minutes contact and 500 to 1,000 ft of annulus).

Remedial Cementing

Squeeze Cementing

Introduction. Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs force poor decisions and high risk. Squeeze cementing is a "correction" process that is usually only necessary to correct a problem in the wellbore. Before using a squeeze application, a series of decisions must be made to determine (1) if a problem exists, (2) the magnitude of the problem, (3) if squeeze cementing will correct it, (4) the risk factors present, and (5) if economics will support it. Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics.

Squeeze cementing is a dehydration process. A cement slurry is prepared and pumped down a wellbore to the problem area or squeeze target. The area is isolated, and pressure is applied from the surface to effectively force the slurry into all voids. The slurry is designed specifically to fill the type of void in the wellbore, whether it is a small crack or micro-annuli, casing split or large vug, formation rock or another kind of cavity. Thus, the slurry design and rate of dehydration or fluid loss designed into the slurry is critical, and a poor design may not provide a complete fill and seal of the voids.

Techniques

The following techniques are the six commonly recognized squeeze applications.

Running Squeeze. A running squeeze is any squeeze operation in which continuous pumping is used to force the cement into the squeeze interval. This technique is sometimes referred to as a "walking squeeze" when low pump rates and minimal graduating pressure is used. Although the running squeeze is easier to design and apply, it is probably the most difficult to control because the rate of pressure increase and final squeeze pressure are difficult to determine. As running-squeeze pressure builds, the pump rate should be reduced, creating a walking squeeze. Running squeezes may be applied whenever the wellbore can be circulated at a reasonable pump rate (approximately 2 bbl/min). When applied correctly, most running squeezes are low-pressure applications; however, they often turn into high-pressure applications because of unknown formation characteristics, the quality of slurry used, or lack of job control.

Hesitation Squeeze. This technique is often used when a squeeze pressure cannot be obtained using a running technique because of the size of the void, lack of filtrate control, or when the squeeze must be performed below a critical wellbore pressure. During a hesitation squeeze, the pumping sequence is started and stopped repeatedly, while the pressure is closely monitored on the surface. Cement is deposited in waves into the squeeze interval, and the slurry is designed to increase resistance (gel-strength development and fluid-leakoff rate) until the final squeeze pressure is reached. Operators must thoroughly design and test the cement slurry to understand how its properties will change with frequent shutdowns and to safely approximate the shutdown period between pumping cycles. The slurry volume should be clear of all downhole tools before the hesitation cycles begin. For many otherwise large and expensive conventional squeeze applications, a hesitation squeeze can be a safer, less expensive, and effective technique.

High-Pressure Squeeze. A high-pressure squeeze is an application performed above formation fracturing pressures when fracturing is necessary to displace the cement and seal off formations or establish injection points between channels and perforations. Slurry volumes and leakoff vary with the size of the interval. "Block" squeezing is the process of squeezing off permeable sections above and below a production zone, which requires isolation of the zone with a packer and retainer, using high pressure to force cement slurry (fracture) into the zone. Cement slurry will not invade a formation unless it is fractured away, creating a large crack to accommodate the entire slurry. Otherwise, dehydration occurs and only the filtrate enters the zone. High pressure is usually required to force all wellbore fluids into the formations ahead of the cement slurry. This technique is often referred to as "bullheading."

Low-Pressure Squeeze. A low-pressure squeeze, the most common technique, is any squeeze application conducted below the fracturing pressure. This method can be applied whenever clean wellbore fluids can be injected into a formation, such as permeable sand, lost-circulation interval, fractured limestone, vugs, or voids. Filtrate from the cement slurry is easily displaced at low pressures, and the dehydrated cement is deposited in the void. Whole cement slurries will not invade most formations unless a fracture is readily open or is created during the squeeze process.

Packer/Retainer Squeeze. Squeeze tools are often used to isolate the squeeze interval and place the cement as close to the squeeze target as possible before applying pressure. Retainers or bridge plugs are used to create a false bottom and are set just below the squeeze target inside the casing or tubing. This procedure seals off the open wellbore below the target (which may be several thousands of feet) and reduces the volume of cement needed for the squeeze. A packer can be run into the wellbore and set above the squeeze interval, between two intervals, or below an interval. Packers allow circulation of the wellbore until the cement slurry is pumped; then the packer is set, which seals off the annulus so the cement can be squeezed through tubing below the packer or down the backside between the tubing/casing annulus above the packer. Cement volumes, squeeze pressures, and squeeze targets can be more accurately determined and controlled using squeeze tools.

Bradenhead Squeeze. This technique is often applied when the problem occurs during drilling (lost circulation) or soon after a primary cement job (weak casing shoe). A Bradenhead squeeze is performed when squeeze tools are unavailable or cannot be run in the hole, or when the operator feels he can successfully control the problem without pulling the drillstring, tubulars, etc. out of the wellbore. Whether during drilling or completion, a Bradenhead is performed by circulating cement slurry down to the squeeze interval, then pulling the workstring above the top of the cement column. The backside of the wellbore is closed in, and pressure is applied through the workstring to force cement into the squeeze interval. A hesitation squeeze is sometimes used to more effectively pack off the cement into all voids. Most coiled-tubing (CT) squeeze applications are performed using this technique.

Plug Cementing

In oil-gas-well construction, a plug must prevent fluid flow in a wellbore, either between formations or between a formation and the surface. As such, a competent plug must provide a hydraulic and mechanical seal. Each plugging operation presents a common problem in that a relatively small volume of plugging material, usually a cement slurry, is placed in a large volume of wellbore fluid. Wellbore fluids can contaminate the cement, and even after a reasonable WOC time, the result is a weak, diluted, nonuniform or unset plug. In addition, plugging situations frequently present unique issues that require sound engineering design and judgment. For these reasons, both mechanical and chemical technologies are necessary for successful plugging.

Displacement efficiency, slurry stability, fluid compatibilities, and all the issues that are normally considered for a primary cement job must be carefully considered for a plug job. Plugging operations are difficult because the work string from a heavier balanced cement plug must be removed from its position above a lighter wellbore fluid. Some of the varied reasons for performing plugging operations are discussed next.

Abandonment. To seal off selected intervals of a dry hole or a depleted well, operators can place a cement plug at the required depth to help prevent zonal communication and migration of any fluids that might infiltrate underground freshwater sources.

Directional Drilling/Sidetracking. When sidetracking a hole around a non-retrievable fish, such as a stuck bottomhole assembly (BHA) or changing the direction of drilling for geological reasons, it is often necessary to place a cement plug at the required depth to change the wellbore direction or to help support a mechanical whipstock, so the bit can be guided in the desired direction.

Lost-Circulation Control. When mud circulation is lost during drilling, lost returns can sometimes be restored by spotting a cement plug across the thief (lost-circulation) zone and then drilling back through the plug. Efforts should be made to identify the source and reason for lost returns when planning a plugging job. Drilling-induced fractures, chemically induced formation instability, natural fractures, vugs, and high permeability can contribute to lost circulation.

Well Control. Plugs, typically made of cement, are sometimes placed in a wellbore when the well has reached a critical state in which no margins remain between pore and frac pressures and no other options exist. In fact, the drillstring is sometimes intentionally cemented in place because it cannot be pulled without risk of inducing an uncontrolled flow to the surface or a crossflow from a high-pressured zone into a weak or low-pressured zone.

Zonal Isolation/Conformance. One of the more common reasons for plugging is to isolate a specific zone. The purpose may be to shut off water, to recomplete a zone at a shallower depth, or to protect a low-pressure zone in an openhole before squeezing. In a well with two or more producing intervals, abandoning a depleted or unprofitable producing zone may be beneficial. A permanent cement plug is used to isolate the zone, helping to prevent possible production losses into another interval or fluid migration from another interval. The integrity of such plugs is frequently enhanced mechanically by placing them above bridge plugs or through and above squeeze retainers. Other methods involve combining the spotting of plugging fluids with the remedial squeeze process of injecting a polymer plugging material into the formation matrix, followed by a small volume of cement slurry to shut off perforations.

Formation Testing. Plugs are occasionally placed in the open hole below a zone to be tested that is a considerable distance off-bottom, where other means of isolating the interval are not possible or practical. Although cement is the most commonly used plug material, barite, sand, and polymers may also serve as plugging agents.

Wellbore Stability. At times during drilling, placing a plugging material across an unstable formation can be beneficial. Polymer, resins, cements, or combinations of these materials can be used to consolidate formations and alter the near-wellbore stresses and formation integrity. A balanced cement plug is sometimes placed to simply "backfill" a severely washed out or elliptical hole section. In such cases, the plug is subsequently drilled out, leaving a cement sheath in place to reduce or prevent further wellbore enlargement and to help return the wellbore to its original diameter and circular shape for improved annular velocities.

Placement Techniques

This section describes some common placement techniques in basic terms, but these techniques can be custom-designed for specific situations.

Dump Bailer. Dump bailers are used for placing very small volumes of plugging material precisely and economically. Different types of dump bailers, including gravity and positive-displacement bailers, are shown in Fig. 9.1. These are generic dump bailers and are indications of various types. Generally, any company in the business or setting wireline plugs (both slickline and e-line) will have some type of dump-bailer service.

Fig. 9.1—Various types of dump bailers.

These tools can be run on wireline, slickline, or sandline, depending on the tool. Both through-tubing and through-casing sizes are also available. Sand, barite, polymers, thermal-set resins, plastics, and cement slurries are all placed with this technique. The use of dump bailers for spotting materials that thermally depend on set times (such as polymers, resins, and cement slurries) has historically been limited to shallow depths because of temperature concerns; but modern polymer and retarder technology allows for broader use.

A limit plug, cement basket, permanent bridge plug, or sand pill is often placed below the desired plugging location to provide a solid bottom in the wellbore. The dump bailer, containing a measured quantity of plugging material, is lowered to the desired depth. The bailer is opened either electronically by the wireline operator or mechanically by tagging the bridge plug and then raised to release the plugging material at this location. At times, the job is performed either with a lubricator on the wellhead or under overbalanced conditions so that the plugging fluid may achieve limited forced entry through gravel packs, perforations, and other passages into formation matrix.

Coiled Tubing. Probably the most technically efficient way to spot fluid in a wellbore is to lay it in with CT; but it is not always the most economical or logistically efficient way. The process consists of placing the end of the CT at the bottom of the planned plug depth, and while the cement or other plugging slurry exits, the nozzle at the end of the coil slowly extracts the coil so that the pull-out rate matches the fluid-pump rate and keeps the end of the coil just below the top of the slurry. This placement method results in a volume of plugging fluid with little or no contamination in the wellbore. After placement, the operator may wash out the wellbore above the plug to establish a very accurate top of cement, or apply squeeze pressure in some prescribed manner.

Bullheading or Bradenhead Placement. The bullheading or Bradenhead placement method consists of injecting a plugging slurry into a formation with the intent to leave some portion of the plugging material in the wellbore. Typically applied in cases of well control, lost circulation, or abandonment, this method is probably one of the less accurate placement methods because of the uncertainty of the fluid path. The general assumption is that the fluids will follow the path of least resistance, but that is not always reliable. Consequently, when a slurry goes into the annulus rather than down into a lower portion of the wellbore, work strings are sometimes unintentionally cemented in the wellbore. Despite the uncertainty involved, this plugging method has been used successfully when it is executed with caution.

Balanced Plugs. Probably the most common technique in both drilling and abandonment operations, the balanced-plug method involves pumping the slurry through drillpipe or tubing until the level outside is equal to that inside the string. The volume and hydrostatics of wellbore fluids, preflushes, spacers, and plugging fluids must be carefully calculated to ensure that the system is being correctly balanced in the hole. The pipe or tubing is then pulled slowly from the plugging material before it sets, leaving the plug in place. The method is simple in theory, but depending on wellbore conditions, the fluid mechanics can be extremely complex. Wellbore, fluid, and hardware constraints must all be considered during the design and execution of the job.

Preparing a drilling fluid for cementing can be difficult before a primary cementing operation; it can be next to impossible when preparing to spot a balanced cement plug because of time, economic, and technical constraints. When these conditions exist, a simple way to ensure maximum mud removal is to wash across the interval where the plug will be placed, typically with a diverter tool (such as a drillpipe, CT, or a specialized tailpipe assembly) on the end of the work string. This approach ensures that the wellbore fluids are as close as possible to being 100% mobilized across this critical interval.

In cases where well control is a concern, such as placement of thixotropic slurries, short slurry-thickening time, or other instances with a high risk of compromising plug stability/integrity when the work string is removed, the operator should consider running a sacrificial tailpipe. This tailpipe can be released by either shearing it off at the end of the job or leaving the work string in place until the plugging material has set and cutting or backing off the pipe at the first free connection. In extreme situations, a sacrificial string may include the bottomhole drilling assembly, but if the pipe can be tripped, releasable tailpipe assemblies can be quickly fabricated out of locally available tubing and hardware. If necessary, such assemblies can be constructed out of any drillable material, such as aluminum.

Hole Preparation

The predominant cause of cementing failure appears to be channels of gelled drilling fluid remaining in the annulus after the cement is in place. If drilling-fluid channels are eliminated, any number of cementing compositions will provide an effective seal.

In evaluating factors that affect the displacement of drilling fluid, it is necessary to consider the flow pattern in an eccentric annulus (i.e., where the pipe is closer to one side of the hole than the other). Flow velocity in an eccentric annulus is not uniform, and the highest velocity occurs in the side of the hole with the largest clearance.

If the casing is close to the wall of the hole, it may not be possible to pump the cement at a rate high enough to develop uniform flow throughout the entire annulus (Fig. 9.2). To reduce the chances for eccentricity, centralizers should be used to maintain the pipe in the center of the annulus.

Fig. 9.2—Effect of eccentricity on cement flow in the annulus.

Standoff

100% Standoff. This shows a hole with casing that is exactly centralized in the hole. The shaded areas are the cement and it shows the cement level is the same on both sides of the casing.

75% Standoff. This shows a hole with the casing decentralized to a 75% standoff, and it shows that as you decentralize the casing the flow is higher up the wide side of the hole compared to the narrow side.

50% Standoff. Same as the 75% standoff only more pronounced with the cement height.

Circulability Treatment

The condition of the drilling fluid is the most important variable in achieving good displacement during cementing. Regaining and maintaining good fluid mobility is the key. An easily displaced drilling fluid will have low gel strengths and low fluid loss. Pockets of gelled fluid, which commonly exist following drilling, make displacement difficult and should be broken up. Circulating or conditioning the drilling mud for at least two hole volumes, prior to cementing, is preferred. Varying pump rates during the conditioning process enhances hole cleaning. Pipe movement (reciprocation or rotation) helps to break up mud gels for greater displacement efficiency. Performing the steps discussed next conditions the drilling fluid for a cement job.

Determine the volume of the circulatable hole, and evaluate the percentage of the hole that is being circulated. Good fluid returns do not reliably indicate the mobility of fluid in the annular space.
When the casing is on bottom and before displacement begins, circulate the drilling fluid to help break the gel structure of the fluid, decreasing its viscosity and increasing its mobility. Condition the drilling fluid until equilibrium is achieved.
Never allow the drilling fluid to remain static for extended periods, especially at elevated temperatures. When the drilling fluid is well conditioned (the drilling-fluid properties going in equal the drilling-fluid properties at the outlet), continue circulating it until the displacement program begins.
Modify the flow properties of the drilling fluid to optimize its mobility and drill-cuttings removal.
Measure gel strengths at 10 seconds, 10 minutes, 30 minutes, and 4 hours to examine the gel-strength profile of the drilling fluid. This testing would typically be performed during the job-planning stage. During conditioning just before the job, readings taken at 10 seconds, 10 minutes, and 30 minutes are typically sufficient. An optimum drilling fluid has flat, nonprogressive gel strengths (e.g., gel-strength values of 1, 3, and 7). Note: Gel strength is measured using a rotational viscometer. The unit of measure is lbf/100 ft². The test procedure is outlined in API RP13B-1, Recommended Practice Standard Procedure for Field Testing Water-based Drilling Fluids.^[2]
Measure gel-strength development of drilling fluid to be left in the well at downhole conditions of temperature and pressure. At elevated temperatures and pressure, some drilling fluids gel to a consistency that prohibits removal. These increased gel strengths are not detectable at surface conditions. This testing should take place during the planning stages.

In deviated wellbores, a drilling fluid that has a higher viscosity at low shear rates may be required to help prevent drilling-fluid or wellbore solids from settling on the low side of the wellbore. The presence of large drill cuttings may also necessitate higher-viscosity fluids. This testing should take place during the planning stages.

Spacers and Flushes

Spacers and flushes are effective displacement aids because they separate incompatible fluids such as cement and drilling fluid. A spacer is a fluid used to separate drilling fluids and cementing slurries. A spacer can be designed for use with either water-based or oil-based drilling fluids and prepares both pipe and formation for the cementing operation. Spacers are typically densified with insoluble-solid weighting agents.

For example, a spacer is a volume of fluid injected ahead of the cement but behind the drilling fluid. It can also enhance the removal of gelled drilling fluid, allowing a better cement bond. Spacers can be designed to serve various needs. For example, weighted spacers can help with well control, and reactive spacers can provide increased benefits for removing drilling fluids. The drilling-fluid/spacer interface and the spacer/cement-slurry interface must be compatible. The use of the compatibility procedures outlined in API RP10B^[1] is highly recommended. Parameters governing the effectiveness of a spacer include flow rate, contact time, and fluid properties. To achieve maximum drilling-fluid displacement, consider these guidelines: pump the spacer fluid at an optimized rate; provide a contact time (10-minute minimum) and volume of spacer that will remove the greatest possible amount of drilling fluid; make sure that the viscosity, yield point, and density of the spacer and the cement slurry are at least the same as the drilling fluid; and when an oil-based or synthetic-based drilling fluid is used, the spacer package should be formulated to thoroughly water-wet the surface of the pipe and the formation. To achieve a high level of water-wettability, test the spacer system using a newly developed API apparent-wettability testing technique. This technique is highly recommended for customizing the spacer/surfactant package to help ensure water-wetting.

Flushes are used to thin and disperse drilling-fluid particles and are used to separate drilling fluids and cementing slurries. They can be designed for use with either water-based or oil-based drilling fluids. Flushes prepare both the pipe and formation for the cementing operation and are not typically densified with insoluble-solid weighting agents. They go into turbulent flow at low rates. Flushes are also referred to as washes and preflushes.^[1]

Contact Time

Contact time is the period of time that a fluid flows past a particular point in the annular space during displacement. Studies indicate that a contact time of 10 minutes or longer provides excellent removal of most drilling fluids. The volume of fluid needed to provide a specific contact time is

....................(9.1)

where

V_t = volume of fluid (turbulent flow), ft³ ;

t_c = contact time, min;

q_d = displacement rate, bbl/min;

and

5.615 = conversion between ft³ and bbl.

The calculation is simple because only two readily available factors are required, and the calculation is independent of casing and hole size. The equation holds as long as all of the fluid passes the point of interest.^[3]

Sweeping Pill Design and Analysis

The most important factor in a sweep program is to carry it out in a proactive manner. It is much easier to keep the hole clean than it is to try to clean it up after solids buildup has occurred. Hole cleaning depends on fluid type. When wells are drilled with invert oil emulsion systems, cuttings tend to be harder, more competent, and better defined than in water-based mud (WBM). This method allows the cuttings to be removed from the wellbore more readily. Even highly inhibitive, high-performance WBM systems do not generate cuttings of the same high level of integrity as inverts. Hole cleaning may also be compromised by the effect of WBM fluids on the nature of the borehole, which will often exhibit rugosity or out-of-gauge hole, thereby reducing annular flow velocities. Large washouts tend to require more frequent hole-conditioning trips. Silicate, CaCl₂ , and some cationic polymer WBM systems produce near-gauge holes in formations of moderate or low chemical reactivity, but in the Gulf of Mexico (GOM), even these WBM types can fall short, and poor hole cleaning and packing off are very real risks. This problem is also manifested at the shakers, which usually require extra attention to keep the screens clean and handle the larger dilution volumes needed to maintain WBM properly.

Cuttings transport in deviated wellbores is more challenging than in vertical wells. Correct well planning, drilling practices, and sweep procedures can have a positive influence on "on-bottom" drilling times. Primary factors contributing to hole-cleaning challenges include drillpipe eccentricity, the need for sliding while maintaining hole direction, and the resultant flow-path changes in the annulus. A factor that compounds the situation is that cuttings settle toward the low side of the deviated hole. This situation, shown in Fig. 9.3,^[4] is known as the Boycott Effect.

Fig. 9.3—Boycott effect: the tendency for cuttings to settle along the low side of a deviated well.⁴

Regardless of drilling-fluid rheology, it is almost impossible to clean a highly deviated wellbore without drillpipe rotation. Drillpipe rotation agitates the settled cuttings back into the flow stream, so they can be transported to the surface.

Cement Composition

Manufacture of Cement

Almost all drilling cements are made of Portland cement, a calcined (burned) blend of limestone and clay. A slurry of Portland cement in water is used in wells because it can be pumped easily and hardens readily, even under water. It is called Portland cement because its inventor, Joseph Aspdin, thought the solidified cement resembled stone quarried on the Isle of Portland off the coast of England. Portland cements can be modified easily, depending on the raw materials used and the process used to combine them.

Proportioning of the raw materials is based on a series of simultaneous calculations that take into consideration the chemical composition of the raw materials and the type of cement to be produced: American Soc. for Testing and Materials (ASTM) Type I, II, III, or V white cement, or API Class A, C, G, or H.^[5],^[6]

Classification of Cement

The basic raw materials used to manufacture Portland cements are limestone (calcium carbonate) and clay or shale. Iron and alumina are frequently added if they are not already present in sufficient quantity in the clay or shale. These materials are blended together, either wet or dry, and fed into a rotary kiln, which fuses the limestone slurry at temperatures ranging from 2,600 to 3,000°F into a material called cement clinker. After it cools, the clinker is pulverized and blended with a small amount of gypsum to control the setting time of the finished cement.

When these clinkers hydrate with water in the setting process, they form four major crystalline phases, as shown in Tables 9.1 and 9.2.^[7] The chemical formulas and standard designations of these phases are discussed later in this chapter.

Table 9.1
Table 9.2

Portland cements are usually manufactured to meet certain chemical and physical standards that depend upon their application. In some cases, additional or corrective components must be added to produce the optimum compositions. Examples of such additives are sand, siliceous loams, pozzolans, diatomaceous earth (DE), iron pyrites, and alumina. Calculations also take into account argillaceous or siliceous materials that may be present in high proportions in some limestones, as well as from the ash produced when coal is used to fire the kiln. Minor impurities in the raw material also must be taken into account, as they can have a significant effect on cement performance. In the U.S., there are several agencies that study and write specifications for the manufacture of Portland cement. Of these groups, the best known to the oil industry are ASTM, which deals with cements for construction and building use, and API, which writes specifications for cements used only in wells.

The ASTM Spec. C150^[5] provides for eight types of Portland cement: Types I, IA, II, IIA, III, IIIA, IV, and V, where the "A" denotes an air-entraining cement. These cements are designed to meet the varying needs of the construction industry. Cements used in wells are subjected to conditions not encountered in construction, such as wide ranges in temperature and pressure. For these reasons, different specifications were designed and are covered by API specifications. API currently provides specifications covering eight classes of oilwell cements, designated Classes A through H. API Classes G and H are the most widely used.

Oilwell cements are also available in either moderate sulfate-resistant (MSR) or high sulfate-resistant (HSR) grades. Sulfate-resistant grades are used to prevent deterioration of set cement downhole caused by sulfate attack by formation waters.

API Classifications

The oil industry purchases cements manufactured predominantly in accordance with API classifications as published in API Spec. 10A.^[8] The different classes of API cements for use at downhole temperatures and pressures are defined next.

Class A. This product is intended for use when special properties are not required. [ Available only in ordinary, O , grade (similar to ASTM Spec. C150, Type I)] .^[5]

Class B. This product is intended for use when conditions require moderate or high sulfate resistance. Available in both MSR and HSR grades (similar to ASTM Spec. C150, Type II).^[5]

Class C. This product is intended for use when conditions require high early strength. Available in ordinary, O , MSR, and HSR grades (similar to ASTM Spec. C150, Type III).^[5]

Class G. No additions other than calcium sulfate or water, or both, shall be interground or blended with the clinker during manufacture of Class G well cement. This product is intended for use as a basic well cement. Available in MSR and HSR grades.

Class H. No additions other than calcium sulfate or water, or both, shall be interground or blended with the clinker during manufacture of Class H well cement. This product is intended for use as a basic well cement. Available in MSR and HSR grades.

Properties of Cement Covered by API Specifications

Chemical properties and physical requirements are summarized in Tables 9.3 and 9.4, respectively.^[7] Typical physical requirements of the various API classes of cement are shown in Table 9.5.^[7]

Table 9.3
Table 9.4
Table 9.5

Although these properties describe cements for specification purposes, oilwell cements should have other properties and characteristics to provide for their necessary functions downhole. API RP10B provides standards for testing procedures and special apparatus used for testing oilwell cements and includes slurry preparation, slurry density, compressive-strength tests and nondestructive sonic testing, thickening-time tests, static fluid-loss tests, operating free fluid tests, permeability tests, rheological properties and gel strength, pressure-drop and flow-regime calculations for slurries in pipes and annuli, arctic (permafrost) testing procedures, slurry-stability test, and compatibility of wellbore fluids.^[1]

Specialty Cements

A number of cementitious materials, used very effectively for cementing wells, do not fall into any specific API or ASTM classification. These materials include pozzolanic Portland cements, pozzolan/lime cements, resin or plastic cements, gypsum cements, microfine cements, expanding cements, refractory cements, latex cements, cements for permafrost environments, Sorel cements, and cements for carbon dioxide (CO₂) resistance.

Pozzolanic Cements

Pozzolanic materials include any natural or industrial siliceous or silico-aluminous material, which will combine with lime in the presence of water at ordinary temperatures to produce strength-developing insoluble compounds similar to those formed from hydration of Portland cement. Typically, pozzolanic material is categorized as natural or artificial, and can be either processed or unprocessed. The most common sources of natural pozzolanic materials are volcanic materials and DE. Artificial pozzolanic materials are produced by partially calcining natural materials such as clays, shales, and certain siliceous rocks, or are more usually obtained as an industrial byproduct. Artificial pozzolanic materials include metakaolin, fly ash, microsilica (silica fume), and ground granulated blast-furnace slag.

Pozzolanic oilwell cements are typically used to produce lightweight slurries. Because the specific gravity of the pozzolanic material is lower than that of the cement, a pozzolan slurry has a lighter weight than a corresponding Portland cement slurry of similar consistency. The lighter weight keeps the formation from breaking down. It is important not to exceed the fracture pressure of the formation while cementing.

Some pozzolanic materials also have a high water demand that effectively gives a higher yield and lighter slurry. They also tend to improve compressive strength over time. The additional binding material also reduces permeability and minimizes attack from formation waters. In most cases, pozzolanic materials can also reduce the effect of sulfate attack, though this is to a certain degree dependent on the slurry design.

Commercial cements such as TXI Lightweight™ for use in oil wells are a special formulation composed of Portland-cement clinker interground with lightweight siliceous aggregate to produce, in effect, a pozzolanic cement.

Pozzolan/Lime Cements

Pozzolan/lime or silica/lime cements are usually blends of fly ash (silica), hydrated lime, and small quantities of calcium chloride. At low temperatures, the initial reactions of these cements are slower than similar reactions in Portland cements, and therefore, they are generally recommended for primary cementing at temperatures greater than 284°C (140°F). The merits of this type of cement are ease of retardation, light weight, economy, and strength stability at high temperatures.

Gypsum Cements

Gypsum cement is a blend of API Class A, C, G, or H cement and a hemihydrate form of gypsum (CaSO₄ •½H₂O). Gypsum cements are commonly used in low-temperature applications for primary cementing or remedial cementing work. This combination is particularly useful in shallow wells to minimize fallback after placement. A high-gypsum-content cement has increased ductility, thixotropy, and acid solubility. It is usually used in situations of high lateral stress or in temporary plugging applications. A 50:50 gypsum cement is frequently used in fighting lost circulation, to form a permanent insoluble plugging material. These blends should be used cautiously because they have very rapid setting properties and could set prematurely during placement. A limitation of gypsum cements is that they are slowly soluble, and they are not stable in contact with external sources of water. This would be a fatal error for an oilfield cement.

Microfine Cements

Microfine cements are composed of very finely ground sulfate-resisting Portland cements, Portland cement blends with ground granulated blast-furnace slag, and alkali-activated ground granulated blast-furnace slag. Such cements have a high penetrability and are ultrarapid-hardening. Applications for such cements are in consolidation of unsound formations and in repairing casing leaks in squeeze operations, particularly "tight" leaks that are inaccessible to conventional cement slurries because of their penetrability. Ultrafine alkali-activated ground blast-furnace slag is the product used in the mud-to-cement technology, in which water-based drilling mud is converted to cement.

Expanding Cements

Expansive cements are available for the primary purpose of improving the bond of cement to pipe and formation. If expansion is properly restrained, its magnitude will be reduced and a prestress will develop. Expansion can also be used to compensate for the effects of shrinkage in normal Portland cement.

At this time, there is no test procedure or specifications in the API standards for measuring the expansion forces in cement. Most laboratories use the expansive bar test, employing a molded 1 × 1 × 10-in. cement specimen. Ring molds are also available, though they are not as commonly used. The expansive force is measured soon after the cement sets for a base reference and then at various time intervals until the maximum expansion is reached. Hydraulic bonding tests have also been used to evaluate the growth of expanding cements.

Calcium Aluminate Cements

High-alumina cement (HAC) is used in well-cementing operations at both temperature extremes in permafrost zones with temperatures at 32°F or below; in-situ combustion well ’ s (fireflood) where temperatures may range from 750 to 2,000°F, and thermal-recovery wells where temperatures can exceed 1,300°F and temperature fluctuations can be high.

A number of HACs have been developed with alumina contents between 35 and 90%, and there is a move to term these collectively as calcium aluminate cements (CACs) because the reactive phase in all cases is calcium aluminate.

It is the standard type (e.g., Ciment Fondu) that is mostly used in well cementing. These cements can be accelerated or retarded to fit individual-well conditions, but the retardation characteristics will differ from those of Portland cements. The addition of Portland cement to refractory cement causes a flash set; therefore, when both are handled in the field, they should be stored separately.

Latex Cement

Latex cement, although sometimes identified as a special cement, is actually a blend of API Class A, G, or H with latex. In general, a latex emulsion contains only 50% latex by weight of solids and is usually stabilized by an emulsifying surface-active agent. Latexes impart elasticity to the set cement and improve the bonding strength and filtration control of the cement slurry. Latex in powdered form can be dry-blended with the cement before it is transported to the wellsite and is not susceptible to freezing.

Permafrost Cement

It is normally desirable to use a quick-setting, low-heat-of-hydration cement that will not melt the permafrost. API RP10B, Sec. 14,^[1] gives special cementing procedures for simulating arctic conditions and cementing in such environments.

Two cement systems that have been used successfully are calcium aluminate cement blends and gypsum cement blends. Fly ash or natural pozzolan is normally blended (at about 50% by weight) with calcium aluminate cements to lower the heat of hydration, thus preventing permafrost damage. Gypsum-cement blends can be accelerated or retarded and will set at 15°F below freezing. For surface pipe, these slurries are normally designed for 2 to 4 hours of pumpability, yet their strength development is quite rapid and varies little at temperatures between 20 and 80°F.

Resin or Plastic Cements

Resin and plastic cements are specialty materials used for selectively plugging open holes, squeezing perforations, and cementing waste disposal wells, especially in highly aggressive, acidic environments. They are usually mixtures of water, liquid resins, and a catalyst blended with an API Class A, B, G, or H cement.

When pressure is applied to the slurry, the resin phase may be squeezed into a permeable zone to form a seal within the formation. These specialty cements are used in wells in relatively small volumes. They are effective at temperatures from 140 to 392°C (60 to 200°F).

Cements for CO₂Resistance

The hydration products of Portland cement are susceptible to carbonation in the presence of moisture. Carbonation is the attack resulting from dissolved CO₂ in formation waters or as a result of CO₂ -injection processes. The CO₂ dissolves in the aqueous pore solution of the hydrated cement, ultimately producing calcium carbonate (CaCO₃).

Carbonation can be minimized by the use of a specially formulated calcium phosphate cement, ThermaLock™, that is resistant to both CO₂ and acid. This cement can be used at temperatures typically ranging from 140°F (60°C) to 700°F (371°C). ThermaLock™ is an ideal cement for environments in which high concentrations of CO₂ are anticipated. The one disadvantage is that it is more expensive than Portland cement; however, it greatly reduces concerns on the long-term affects of CO₂; saves on remedial operations, abandonments, and redrilling or recompletion; and it does not require special cementing equipment or techniques.

Cement Hydration

The reactions involved when cement is mixed with water are complex. Each phase hydrates by a different reaction mechanism and at different rates (Fig. 9.4).

Fig. 9.4—Schematic of cement-hydration reactions (courtesy of Halliburton).

The reactions, however, are not independent of each other because of the composite nature of the cement particle and proximity of the phases. In all, five distinct stages have been identified: (1) pre-induction, (2) "dormant" (induction) period, (3) acceleration, (4) deceleration, and (5) steady state. In cementing operations, the most important of these are Stages 1 through 3. Stage 1 dictates the initial mixability of the cement and is attributed primarily to the aluminate and ferrite phase reactions. Stage 2 relates to the pumpability time, while Stage 3 gives an indication on setting properties and gel-strength development.

Hydration of Pure Mineral Phases

During hydration, the cement forms four major crystalline phases.

Tricalcium Silicate (3CaO•SiO₂= C₃S). C₃S on reaction with water produces C-S-H and calcium hydroxide, CH, (also known as Portlandite). The hyphens used in the C-S-H formula are to depict its variable composition: CSH would imply a fixed composition of CaO.SiO₂.H₂O. C/S ratios in C-S-H vary from 1.2 to 2.0, and H/S ratios vary between 1.3 and 2.1.

Dicalcium Silicate (2CaO•SiO₂= C₂S). The kinetics and hydration mechanism for C₂S are similar to those of C₃S except that the rate of reaction is much slower. The hydration products are the same except that the proportion of CH produced is about one-third of that obtained on hydration of C₃S.

Tricalcium Aluminate (3CaO•Al₂O₃= C₃A). The initial reaction of C₃A with water in the absence of gypsum is vigorous and can lead to "flash set" caused by the rapid production of the hexagonal crystal phases, C₂AH₈ (H = H₂O) and C₄AH₁₉. Sufficient strength is developed to prevent continued mixing. The C₂AH₈ and C₄AH₁₉ subsequently convert to cubic C₃AH₆ (hydrogarnet), which is the thermodynamically stable phase at ambient temperature. Typically, gypsum is added to retard this reaction, though other chemical additives can be used.

The reaction products formed on reaction of C₃A in the presence of gypsum depend primarily on the supply of sulfate ions available from the dissolution of gypsum. The primary phase formed is ettringite . Ettringite is the stable phase only as long as there is an adequate supply of soluble sulfate. A second reaction takes place if all of the soluble sulfate is consumed before the C₃A has completely reacted. In this reaction, the ettringite formed initially reacts with the remaining C₃A to form a tetracalcium aluminate monosulfate-12- hydrate known as monosulfate or monosulfoaluminate .

TetraCalcium Aluminoferrite (4CaO•Al₂O₃•Fe₂O₃= C₄AF). Hydration of C₄AF gives hydration products that are similar in many respects to those formed from C₃A under comparable conditions, though typically they contain Fe³ + as well as Al³+ . An iron (III) hydroxide gel and calcium ferrite gel are also possible products of C₄AF hydration. The reactivity of the pure C₄AF is, in general, much slower than that of the C₃A.

Hydration of Cement Phases

Although the basic reaction mechanisms and theories on the hydration of the pure phases pertain to the phases in cement, there are some significant differences. A schematic of the initial hydration reactions up to the time of set is illustrated in Fig. 9.5.

Fig. 9.5—Cement hydration from mixing to setting (courtesy of Halliburton).

Alkalis. The alkalis, primarily sodium and potassium, are impurities that arise from shales, clays, or the fuel used in the manufacture of the cement. Although present in small amounts,

< 1%, they have a significant effect on the hydration. Typically, they are present as sulfates, in the form of K₂SO₄ , Na₂SO₄, Na₂SO₄•3K₂O (aphthitalite), and/or 2CaSO₄•K₂SO₄ (calcium langbeinite), and they are usually deposited on the surface of the cement particles. The alkali sulfates dissolve almost immediately on contact with water, and alkalis can also be present as impurities in the cement phases, with sodium preferentially in the aluminate (C₃A) phase and potassium more widely distributed in both calcium and aluminate phases. API Spec. 10A for Class G and H cements limits the alkali to 0.75% as Na₂O₄ to allow adequate thickening times to be achieved downhole.^[8]

In cements high in K₂SO₄, reaction between K₂SO₄ and gypsum in the presence of water can produce syngenite, . This can cause lumpiness on storage of the dry cement powder under high-humidity conditions (> 90% relative humidity) because the acts as an effective binder to the dry cement particles. Precipitation of during cement hydration can cause false or even flash setting.

Calcium Sulfates. Gypsum is added to the cement primarily to retard the hydration of the aluminate and ferrite phases. The effectiveness of the gypsum depends on the rate at which the relevant ionic species dissolve and come in contact with each other. Thus, interground gypsum is far more effective than interblending the same proportion because intergrinding brings the gypsum particles into closer contact with the cement particles and produces a shorter diffusion distance between the two. Temperature and humidity in the grinding mill can cause the gypsum to dehydrate, resulting in the formation of hemihydrate and/or soluble anhydrite . Hemihydrate or soluble anhydrite can rehydrate to give "secondary" gypsum, causing a rapid set, known as "false set." Pumpability can be regained on further mixing or addition of water, assuming the quantity of secondary gypsum is not too great.

The reactivity and performance of cement is a culmination of the effect of the different impurities on the number of defects and morphology of the crystal structure of the different phases. This is why cement can vary not only from one source to another but also between batches from the same source.

Effects of Temperature on Hydration

The rate of hydration of the cement phases, however, will increase with increasing temperature, and the resulting thickening and setting times will, consequently, decrease. Above 230°F (110°C), the hydration products formed differ considerably from those obtained at lower temperatures. Alite and belite phases hydrate to give crystalline α-C₂SH rather than amorphous C-S-H. α-C₂SH is a relatively dense crystalline material that is porous and weak and is deleterious in that it provides high permeability and low compressive strength. Formation of α-C₂SH can be prevented, or at least minimized, by the addition of finely ground silica, such as silica flour, to the cement.

Normally, in oilwell cementing, ~ 35% silica in the form of silica flour is used to prevent strength retrogression that can occur at temperatures above~ 248°F (120°C). This percentage of added silica gives an effective C/S ratio in the cement blend of approximately 1.0. Generally, over time, the permeability increases slightly, and the compressive strength decreases as the phases increase in crystallinity.

Fly ash has often been considered as a potential source of silica for hydrothermal systems. There is considerable variability in the alumina/silica ratio of fly ashes from different sources, as well as in the reactivity of the aluminosilicate glass, and this clearly has an impact on the phases formed and their stability fields. The influence of this variability in composition and reactivity is that the fly ash, if used as a source of silica, can give properties that range from good to deleterious.

Sulfate Attack

Sulfate attack is normally a problem only where BHSTs are below approximately 60°C (140°F), where ettringite is present. Some formation waters contain high concentrations of sulfate. These sulfates attack the cement, and, as a result, the cement will crumble with time.

Resistance to sulfate attack is increased on modifying the cement powder by replacing the aluminate with ferrite, which reduces the amount of ettringite formed on hydration, and also by lowering the amount of free lime. Addition of pozzolanic materials, such as fly ash, also reduce sulfate attack because they react with the CH in cement and render it unavailable for reaction.

Slurry Design

The properties of Portland cements must often be modified to meet the demands of a particular well application. These modifications are accomplished by the admixing of chemical compounds commonly referred to as additives that effectively alter the hydration chemistry. An overview of the most common cementing additives is given in Table 9.6.^[7]

Table 9.6-Summary Of Oilwell Cementing Additives
Table 9.6 Continued

The table also includes an indication of the primary uses and benefits, along with the cements that they can be used with. The primary effects of the cement admixtures on the physical properties of the cement, either as a slurry or set, are presented in Table 9.7.^[7] This is a quick reference, and individual additives in a given category may not agree in total with the effects as given. It is also typically defined for individual additives, the properties and effects of which can be modified when additive combinations are used.

Table 9.7-Effects of Cement Admixtures On The Physical Properties Of Cement

Many chemical compounds have proved to be effective in modifying the properties of Portland-cement slurries. These compounds, when used alone, will have a primary effect upon the cement slurry that is considered to be beneficial. They will also exhibit at least one secondary characteristic that may be either beneficial or detrimental to the cement-slurry performance properties. The effects of the additives are reduced or enhanced by modifying the additive or by using additional additives. For most downhole requirements, more than one additive is needed. This give-and-take relationship between additives is the basis of cement-slurry design.

The reaction of these additives with the cement and the interaction between them is not well defined chemically. What is actually known are the physical effects of these additives on the slurry performance properties. The slurry performance properties that are measured include: thickening time, compressive strength, rheology, fluid loss, free fluid, and slurry stability.

Cement manufactured to API depth and temperature requirements can be purchased in most oil-producing areas of the world. Any properly made Portland cement (consistent from batch to batch) can be used at temperatures up to 570°F. For example, Class H cement with the proper additives has routinely been used at depths up to 20,000 ft.

In addition to the cement, other factors, such as the correct BHCT, should be considered when designing a cement slurry to meet well requirements. In formulating a cement slurry, the designer must consider not only the temperature but also the other downhole conditions, such as permeability and water-sensitive formations.

A slurry should be designed for its specific application, with good properties to allow placement in a normal period. The ideal cement slurry should have no measurable free water, provide adequate fluid-loss control, contain adequate retarder to help ensure proper placement, and maintain a stable density to ensure hydrostatic control. Do not add dispersants or retarders in excess of the amounts indicated by wellbore conditions, and provide just enough fluid-loss control to place the cement before it gels.

Slurry design is affected by the following criteria: well depth, quality of mix water, BHCT, fluid-loss control, BHST, flow regime, drilling fluid

’

s hydrostatic pressure, settling and free water, type of drilling fluid, quality of cement, slurry density, dry or liquid additives, lost circulation, strength development, gas-migration potential, quality of the cement testing, pumping time, and laboratory and equipment.

When estimating job time, include the mixing time on the surface, especially if the job is going to be batch-mixed. Calculate the actual job time, using the slurry volume and average displacement rate; then, limit the amount of trouble time to 1 to 1.5 hours. To calculate the approximate thickening time for slurry design, add 1 to 1.5 hours to the job time.

Additives

The additives used to modify the properties of cement slurries for use in oilfield well-cementing applications fall into the following broad categories: accelerators, retarders, extenders, weighting agents, dispersants, fluid-loss control agents, lost-circulation agents, strength-retrogression prevention agents, free-water/free-fluid control, expansion agents, and special additives.

The demand for new additives with special properties and tuned performance continues to increase. These demands include such factors as density range of application, temperature stability, economics, viscosity range, singular function, multifunction, rate of solubility, synergism with co-additives, and resistance to cement variability.

Accelerators

Accelerators speed up or shorten the reaction time required for a cement slurry to become a hardened mass. In the case of oilfield cement slurries, this indicates a reduction in thickening time and/or an increase in the rate of compressive-strength development of the slurry. Acceleration is particularly beneficial in cases where a low-density (e.g., high-water-content) cement slurry is required or where low-temperature formations are encountered.

Calcium Chloride (CaCl₂). Of the chloride salts, CaCl₂ is the most widely used, and in most applications, it is also the most economical. The exception is when water-soluble polymers such as fluid-loss-control agents are used. The major benefits of the use of CaCl₂ are the significant reduction in thickening time achieved and that, regardless of concentration, it always acts as an accelerator. The normal concentration range of use for CaCl₂ is 1 to 4% by weight of cement (BWOC). Above a concentration of 6% BWOC, the results will become unpredictable and gelation can occur.

Sodium Chloride (NaCl). NaCl is the second most widely used of the chloride salts. NaCl, common table salt, is the most versatile of the chloride salts. Depending on the concentration of use, NaCl can act as an accelerator or a retarder, and it acts a mild dispersant at all concentrations. Some additional uses for NaCl are to improve bonding to pipe, stabilize reactive formations (e.g., shale and gumbo), enhance bonding to salt formations, reduce the permeability of set cement, improve the durability of set cement in contact with saltwater-containing formations, and increase slurry density without the use of dispersants or a reduction in water content. In general, NaCl acts as an accelerator at concentrations from 1 to 10% by weight of water (BWOW), although the most commonly used concentration of NaCl as an accelerator is 3% BWOW.

Potassium Chloride (KCl).The acceleration performance of KCl is similar to that of NaCl. KCl has two advantages over other accelerators: its stabilizing effect on shale or active clay-containing formations and its minimal effect on the performance of fluid-loss additives. As an accelerator, KCl may be used at concentrations up to 5% BWOW; for formation stabilization, concentrations of 3% BWOW are effective.

Sodium Silicate (Na₂SiO₃). Sodium silicate is normally considered to be a chemical extender, although it is also functional as an accelerator. The effectiveness depends on the concentration and molecular weight. The low-molecular-weight form may be used at concentrations of 1% BWOC or less to accelerate normal-density slurries. The high-molecular-weight form is an effective accelerator at concentrations up to 4% BWOC. Sodium-meta-silicate also provides excellent lost-circulation control when used with cement or CaCl₂ brines.

Seawater. Seawater is a naturally occurring mixture of alkali chloride salts, including magnesium chloride. The composition of seawater varies widely around the world. For example, the equivalent chloride salt content can vary from 2.7 to 3.8% BWOW.

Alkali Hydroxides [ Ca(OH)₂, NaOH] . Alkali hydroxides are commonly used in pozzolan-extended cements. They accelerate both the pozzolanic and the cement component by altering the aqueous chemistry.

Mono-Calcium Aluminate (CaO•Al₂O₃= CA). Calcium aluminate is used as an accelerator in pozzolan- and gypsum-extended cements.

Retarders

The commonly used cements in well applications are API Class A, C, G, and H. These cements, as produced in accordance with API Spec. 10A^[8] do not have a sufficiently long fluid life (thickening time) for well applications above 38°C (100°F) BHCT. To extend the thickening time beyond that obtained with a neat (cement and water without additives or minerals) API-class cement slurry, additives known as retarders are required.

Lignosulfonates. Of the chemical compounds that have been identified as retarders, lignosulfonates are the most widely used. A lignosulfonate is a metallic sulfonate salt derived from the lignin recovered from processing wood waste. The common lignosulfonates are calcium and sodium lignosulfonate.

Three grades of lignosulfonate are available for the retardation of cement slurries. Each grade is available as calcium/sodium or sodium salts. The three grades are filtered, purified, and modified.

The filtered grade calcium or sodium salt is typically used at a temperature of 200°F BHCT or less at a concentration of 0.6% BWOC or less. It may be used at higher temperatures but will normally be limited by economic considerations. The purified grade represents a class of lignosulfonates in which the sugar content has been reduced. The calcium/sodium salt is typically used at a BHCT of 200°F or lower and at a concentration of 0.5% BWOC or less.

The modified grade represents lignosulfonates that have been blended or reacted with a second component. The compounds most commonly used as blend components are boric acid and the hydroxycarboxylic acids, or their salts. Blended materials are available as calcium or sodium salts. The modified lignosulfonates are typically used at a BHCT of 200°F or above. They are more effective than the purified grade at temperatures greater than 250°F. The advantages, whether a blend or reacted product, are their improved high-temperature stability above 300°F BHCT, increased dispersing activity, and synergism with fluid-loss additives.

Cellulose Derivatives. Two cellulose polymers are used in well-cementing applications. They are hydroxyethyl cellulose (HEC) and carboxymethyl hydroxyethyl cellulose (CMHEC). HEC is commonly considered as a fluid-loss additive. Although as a possible option, it is worth noting that at BHCT of 125°F or less, the thickening time can be extended by approximately two hours in a freshwater slurry. Traditionally, the only cellulose that is considered as a retarder is CMHEC. This is largely because it is functional as a retarder up to approximately 230°F BHCT at the same concentrations as calcium lignosulfonate, but it also provides good fluid-loss control.

Hydroxycarboxylic Acids. The hydroxycarboxylic acids are well known for their antioxidant and sequestering properties that benefit cement-slurry performance. The antioxidant property improves the temperature stability of soluble compounds such as fluid-loss additives. Commonly used hydroxycarboxylic acids and their derivatives are citric acid, tartaric acid, gluconic acid, glucoheptonate, and glucono-delta-lactone. The commonly used hydroxycarboxylic acids are generally derived from naturally occurring sugars.

Organophosphates. Organophosphonates, with a few exceptions, are the most powerful retarders used in cement. These materials are not widely used in well-cementing applications because of the low concentration required, difficulty of accurate measurement, and sensitivity to concentration. The advantage of organophosphate retarders is their effectiveness in ultrahigh-temperature wells ( > 450°F) or in applications where extended thickening times of 24 hours or greater are desired.

Synthetic Retarders. The term synthetic retarder is a misnomer in that the previously mentioned retarding compounds are all, in effect, man-made. However, the term synthetic retarder has been applied to a family of low-molecular-weight copolymers. These retarders are based on the same function groups as those of conventional retarders (e.g., sulfonate, carboxylic acid, or an aromatic compound). Two common synthetic retarders are maleic anhydride and 2-Acrylamido-2-methylpropanesulfonic acid (AMPS) copolymers.

Inorganic Compounds. The retardation mechanism of inorganic compounds on cement hydration is different from that for the previously discussed retarders. Inorganic compounds, commonly used as cement retarders, are borax (Na₂B₄O₇•10H₂) and other borates such as boric acid (H₃BO₃) and its sodium salt and zinc oxide (ZnO).

Borates are commonly used as a retarder aid for high-temperature retarders at BHCT of 300°F (149°C) and greater. At higher temperatures, the borate is a less-powerful retarder than at lower temperatures; however, it exerts a synergistic effect with other retarders such as lignosulfonates, whereby the combination provides better retardation than either retarder alone. ZnO is a strong retarder when used alone. It is normally used for the retardation of chemically extended cements.

Salt as a Retarder. Water containing salt concentrations of greater than 20% BWOW has a retarding effect on cement. The gelation is evident in the thickening-time viscosity profile of saturated salt slurries by a sudden increase in Bearden units of consistency that then levels off before set. Saturated salt slurries are useful for cementing through salt domes. They also help protect shale sections from sloughing and heaving during cementing and aid in preventing annular bridging and the lost circulation that could result. Saturated salt cements are also dispersed, and salt reduces the effectiveness of fluid-loss additives.

Lightweight Additives/Extenders

Neat cement slurries, when prepared from API Class A, C, G, or H cements using the amount of water recommended in API Spec. 10A^[8] will have slurry weights in excess of 15 lbm/gal. In many parts of the world, severe lost circulation and weak formations with low fracture gradients are common. These situations require the use of low-density cement systems that reduce the hydrostatic pressure of the fluid column during cement placement. Consequently, lightweight additives (also known as extenders) are used to reduce the weight of the slurry. There are several different types of materials that can be used. These include physical extenders (clays and organics), pozzolanic extenders, chemical extenders, and gases.

Any material with a specific gravity lower than that of the cement will act as an extender. These materials, in general, decrease the density of cement slurries by one of three means. The pozzolanic and inert organic materials have a lower density than cement and can be used to partially replace cement, therefore lowering the density of the solid material in the slurry. In the case of the physical and chemical extenders, they not only have a lower density but also absorb water, thus allowing more water to be added to the slurry without producing free fluid or particle segregation. The gases behave differently in that they are used to produce foamed cements that have exceptionally low density with acceptable compressive strengths.

In many lightweight slurries, it is common to use a combination of the different types of material. For example, pozzolanic and chemical extenders are, or can be, used with physical extenders and/or gases. Pozzolan slurry designs almost always incorporate bentonite, and gases generally have a chemical extender to stabilize the foam. Lightweight additives also increase the slurry yield and can result in an economical slurry.

Physical Extenders. These are particulate materials that function as cement extenders by increasing the water requirements or by reducing the average specific gravity of the dry mix. There are two general classes of materials that fall into this category: clays and inert organic materials. The most commonly used clay material is bentonite, although attapulgite is also used. The commonly used inert organic materials are perlite, gilsonite, ground coal, and ground rubber.

Bentonite (Gel). This extender is a colloidal clay mineral composed predominately of sodium montmorillonite [ NaAl₂(AlSi₃O₁₀ )•2OH] . The montmorillonite content of bentonite is the controlling factor in its effectiveness as an extender; hence, it is one of two extenders that are covered by an API specification. Bentonite can be added to any API class of cement and is commonly used in conjunction with other extenders. Bentonite is used to prevent solids separation, reduce free water, reduce fluid loss, and increase slurry yield.

Bentonite is typically used at concentrations of 1 to 16% BWOC. It may be dry-blended with the cement or prehydrated in the mixing water. In prehydrating, the effect of 1% BWOC prehydrated is approximately equal to 3.5% BWOC dry-blended, but the yield point is much higher. For best results, the prehydrated bentonite/water mixture should be used for mixing the cement slurry shortly after prehydration has been completed. Laboratory testing is advised to determine the proper gel concentration and mixing procedure for prehydrated bentonite. Tech grade or "mud gel" should not be substituted for cement-grade bentonite. Lignosulfonate is commonly used as a dispersant and retarder in high-gel cements to reduce the slurry viscosity.

Attapulgite (Salt Gel). This is a more effective extender than bentonite in seawater or high-salt slurries, but it is not regulated or does not have a specification. Attapulgite, (Mg,Al)₂ (OH/Si₄O₁₀)•12H₂O, is composed of clusters of fibrous needles that require high shear to be dispersed in water. It produces many of the same effects as bentonite, except that it does not reduce fluid loss. A disadvantage of attapulgite is that because of the similarity of the fibers to those of asbestos, its use has been prohibited in some countries. Granular forms are available that may be permitted as a replacement.

Expanded Perlite. Expanded Perlite is a siliceous volcanic glass that is heat-processed to form a porous particle that contains entrained air. It is a highly buoyant product that requires the addition of 2 to 6% BWOC bentonite to prevent separation from the slurry. Because of its low crush strength, the water requirement for perlite-containing slurries must be increased to allow for slurry compressibility under downhole conditions. Volume loss must also be taken into effect in fill-volume calculation.

Gilsonite. This is an asphaltic material, or solid hydrocarbon, found only in Utah and Colorado. It is one of the purest naturally occurring bitumens. Gilsonite can be used with slurry densities as low as 11 lbm/gal at a normal concentration of 5 to 25 lbm/sack (sk) of cement, and it will plug float equipment and bridge tight annuli. The low densities obtainable with gilsonite result from its low density (1.07 g/cm³). Because gilsonite is an organic material, it is highly buoyant and will float out of the slurry unless inhibited. Bentonite is commonly added at a concentration of 2 to 6% to prevent bridging in the wellbore.

Crushed Coal. Crushed coal is used for the same purposes as gilsonite (i.e., for light weight and lost-circulation control). It is commonly used at concentrations up to 50 lbm/sk of cement. Its density is slightly higher (1.3 g/cm³), requiring a slight increase in water content. The addition of bentonite to prevent separation is normally not required.

Ground Rubber. This is a low-cost alternative to gilsonite and may be used in similar applications. The density of ground rubber is slightly higher (1.14 g/cm³). The physical properties are more variable than gilsonite and are dependent upon material source. One major advantage of ground rubber is its low cost. At present, there are no environmental issues with ground rubber when utilized in a cement system.

Pozzolanic Extenders

A number of pozzolanic materials are available for use in producing lightweight cement slurries. These can be either natural or artificial and include fly ash, DE, microsilica, metakaolin, and granulated blast-furnace slag. In comparison with other additives, pozzolanic materials are usually added in large volumes. Fly ash, for example, can be mixed with cement in ratios of fly ash to cement that range from 20:80 to 80:20, based on an "equivalent sack" weight (that is, where a sack of fly ash has the same absolute volume as that of a sack of cement). Pozzolanic materials have a lower specific gravity than that of cement, and it is this lower specific gravity that gives a pozzolanic-Portland-cement slurry a lower density than a Portland-cement slurry of similar consistency. Depending on the density, pozzolanic cements also tend to give a set cement that is more resistant to attack by formation waters.

Fly Ash. Fly ash is by far the most widely used of the pozzolanic materials. According to ASTM Standard C618,^[9] there are two types of fly ash: Class F and Class C; Class N refers to natural pozzolanic materials. There is, however, a need for a third category, based on the performance of different fly ashes. ASTM Standard C618,^[9] classifies fly ashes on the basis of the combined percentages of SiO₂ + Al₂O₃+ Fe₂O₃ —Class F having a minimum of> 90% and Class C, 50%. In reality, there is a much greater relationship between CaO content and performance. The CaO content ranges from 2 or 3% to 30% by weight of the fly ash. The "true" Class F fly ash has a CaO content of less than 10%, whereas a "true" Class C has CaO greater than 20%. Fly ashes having CaO between 10 and 20% behave somewhat differently from either the true Class F or Class C. Fly ashes are generally composed of amorphous glassy particles that are spherical in shape.

The ASTM Class F fly ash is the most common used in oilwell cementing. It is this fly ash that is covered by the API specifications. The major advantages of the Class F fly ash are its low cost and abundance worldwide. The performance characteristics of a Class F fly ash vary little from batch-to-batch from a given source. However, the differences between sources can be considerable because the composition can vary from the true low CaO to 10 to 20% CaO. This produces significant variations in performance characteristics, and because of this, different sources of Class F fly ashes should be tested before use. Specific gravities also must be determined. Some power plants produce Class F fly ashes with a high-carbon content because of poor burning. These should be avoided for oilwell cementing because they can cause severe gelation problems. The use of Class C fly ash, as an extender for well cementing, is relatively limited. This is, in part, because of the limited availability of Class C fly ash and the considerable variability that exists not only between sources but also to a large extent between batches from a given source.

Microspheres. Microspheres are used when slurry densities from 8.5 to 11 lbm/gal are required. They are hollow spheres obtained as a byproduct from power generating plants or are specifically formulated. The byproduct microspheres are essentially hollow fly-ash glass spheres. They are present, typically, in Class F fly ashes, but usually in small amounts. However, they are obtained in substantial quantities when excess fly ash is disposed of in waste lagoons. The low-density hollow spheres float to the top and are separated by a flotation process. These hollow spheres are composed of silica-rich aluminosilicate glasses typical of fly ash and are generally filled with a mixture of combustion gases such as CO₂, NO_x, and SO_x. The synthetic hollow spheres are manufactured from a soda-lime borosilicate glass and are formulated to provide a high strength-to-weight ratio—they are typically filled with nitrogen. The synthesized microspheres provide a more consistent composition and exhibit better resistance to mechanical shear and hydraulic pressure. The primary disadvantage of most microspheres is their susceptibility to crushing during mixing and pumping and when exposed to hydrostatic pressures above the average crush strength. This can lead to increased slurry density, increased slurry viscosity, decreased slurry volume, and premature slurry dehydration.

However, crushing effects can be minimized by the suitable choice of microspheres. These effects can be predicted and can be taken into account in slurry design calculations to produce a slurry having the required characteristics for the well conditions. Lightweight systems incorporating microspheres can provide excellent strength development and can help control fluid loss, settling, and free water.

Microsilica. Microsilica, also known as silica fume, is a finely divided, high-surface-area silica that can be obtained as a liquid or powder. In the powder form, it can be either in its original state, densified, or pelletized. The bulk density of the densified microsilica is 400 to 500 kg/m³. Microsilica typically has a specific gravity of approximately 2.2.

Microsilica is composed primarily of vitreous silica and has a SiO₂ content of 85 to 95%, which makes it considerably purer than the other pozzolanic materials. Microsilica particles are also considered to impart beneficial physical properties to the slurry. Because of their fineness, they are believed to fill in the voids between the larger cement particles, resulting in a dense, solid matrix, even before any chemical reaction between the cement particles has occurred. Rheological properties tend to be improved with addition of microsilica because the tiny spheres can act as very small ball bearings and/or they displace some of the water present between the flocculated cement grain, thereby increasing the amount of available fluid. Concentrations of microsilica can range from 3 to 30% BWOC, depending on the slurry and properties required.

The physical and chemical properties of the microsilica make it very useful for a variety of applications other than as an extender. These include compressive-strength enhancement for low-temperature lightweight cement, thixotropic properties for squeeze cementing, lost-circulation, gas migration, and a degree of fluid-loss control.

The one disadvantage of microsilica is the cost. Originally considered to be a waste product, with its increased usage in the construction industry over the last decade, it has become more of a specialty chemical. Also, with fluctuations of supply and demand, there is a question of having a constant supply of a good source of the product.

Diatomaceous Earth. DE is a natural pozzolan composed of the skeletons of microorganisms (diatoms) that were deposited in either fresh water or seawater.

Chemical Extenders

Several materials are effective as chemical extenders. In general, any material that can predictably accelerate and increase the concentration of the initial hydration products is effective as a chemical extender.

Sodium Silicate. This is the most commonly used chemical extender for cement slurries. Sodium silicate is five to six times as effective as bentonite on an equivalent concentration basis. Unlike the physical or pozzolanic extenders, sodium silicate is highly reactive with the cement.

Sodium silicate is available in both dry and liquid forms, making it readily adaptable to onshore and offshore applications. The solid form is sodium metasilicate (Na₂SiO₃), and it is typically dry-blended with the cement at a concentration of 1 to 3.5% BWOC at densities of 14.2 to 11.5 lbm/gal. It is not as effective if dissolved directly in the mix water unless CaCl₂ is dissolved in the water first. If a liquid system is desired, it is better to use the liquid form. Liquid sodium silicate is normally used in seawater applications at a concentration of 0.1 to 0.8 gal/sk of cement at densities of 14.2 to 11.5 lbm/gal. The two main advantages of sodium silicates as extenders are their high yield and low concentration of use.

Gypsum. The hemihydrate form of calcium sulfate (CaSO₄•0.5H₂O) is typically used as an extender. It is normally used at concentrations of 15% BWOC or less for the preparation of thixotropic slurries for use in applications where there are severe lost-circulation problems or where expansion properties are desired to improve bonding. Typical slurry compositions for lost-circulation applications, BHCT ≤ 125°F (52°C), contain from 8 to 12% BWOC gypsum with good expansion properties (0.2 to 0.4%). For improved bonding applications, where increased expansion (0.4 to 1%) is desired, NaCl is used (≥ 10% BWOW).

Foamed Cement

It is possible to make slurries ranging in density from 4 to 18 lbm/gal using foamed cement. Foamed cement is a mixture of cement slurry, foaming agents, and a gas. Foamed cement is created when a gas, usually nitrogen, is injected at high pressure into a base slurry that incorporates a foaming agent and foam stabilizer. Nitrogen gas can be considered inert and does not react with or modify the cement-hydration-product formation. Under special circumstances, compressed air can be used instead of nitrogen to create foamed cement. In general, because of the pressures, rates, and gas volumes involved, nitrogen-pumping equipment provides a more reliable gas supply. The process forms an extremely stable, lightweight slurry that looks like gray shaving foam. When foamed slurries are properly mixed and sheared, they contain tiny, discrete bubbles that will not coalesce or migrate. Because the bubbles that form are not interconnected, they form a low-density cement matrix with low permeability and relatively high strength.

Virtually any oilwell-cementing job can be considered a candidate for foamed cementing, including primary and remedial cementing functions onshore and offshore, and in vertical or horizontal wells. Although its design and execution can be more complex than standard jobs, foamed cement has many advantages that can overcome these concerns. Foamed cement is lightweight, provides excellent strength-to-density ratio, is ductile, enhances mud removal, expands, helps prevent gas migration, improves zonal isolation, imparts fluid-loss control, is applicable for squeezing and plugging, insulates, stabilizes at high temperatures, is compatible with non-Portland cements, simplifies admix logistics, enhances volume, has low permeability, is stable to crossflows, and forms a synergistic effect with some additives, which enhances the property of the additive. The disadvantage of foamed cement is the need for specialized cementing equipment both for field application and for laboratory testing.

Weighting Agents

Weighting agents or heavyweight additives are used to increase slurry density for control of highly pressured wells. Weighting agents are normally required at densities greater than 17 lbm/gal where dispersants or silica is no longer effective. The main requirements for weighting agents are that the specific gravity is greater than the cement, the particle size distribution is consistent, they have a low water requirement, they are chemically inert in the cement slurry, and they do not interfere with logging tools.

Hematite (Fe₂O₃). This is the most commonly used weighting agent. Hematite is a brick-red, naturally occurring mineral with a dull metallic luster. It contains approximately 70% iron. The specific gravity of hematite ranges from 4.9 to 5.3, depending on purity, and it has a Mohs hardness of approximately 6.

Ilmenite (FeO TiO₂). This is not as commonly used as hematite, although it has some advantages over hematite. Ilmenite is a black to dark brownish-black, naturally occurring mineral with a submetallic luster that contains approximately 37% iron. It resembles magnetite in appearance but has only a slightly magnetic character. The specific gravity ranges from 4.5 to 5, depending on the purity, and it has a Mohs hardness of 5 to 6.

Hausmannite (Mn₃O₄). Hausmannite is being used increasingly because of its unique properties that address many of the disadvantages encountered with the other weighting agents. Hausmannite is a dark brownish-black material that is a byproduct mineral from the processing industry. The specific gravity range or Mohs hardness has not been well established. Because of its particle size and unique wetting characteristics, the material can suspended in the mix water at up to 40 wt% with a minimum of agitation, providing a liquid weighting agent. Because the average particle size of hausmannite is much smaller than that of cement, it allows the material to fit within the cement pore matrix, displacing entrained water, resulting in a lower viscosity and significantly more-stable slurry. The main disadvantage is that it is not readily available in all geographic regions, so the additional shipping cost can make it cost-prohibitive.

Barite (BaSO₄)Barite is not normally used in cementing as a weighting agent because of its high surface area and high water demand. It is a soft, light gray, naturally occurring nonmetallic material. The specific gravity ranges from approximately 4.0 to 4.5, depending on purity, and it has a Mohs hardness of 2.5 to 3.5.

Dispersants

Dispersants, also known as friction reducers, are used extensively in cement slurries to improve the rheological properties that relate to the flow behavior of the slurry. Dispersants are used primarily to lower the frictional pressures of cement slurries while they are being pumped into the well. Converting frictional pressure of a slurry, during pumping, reduces the pumping rate necessary to obtain turbulent flow for specific well conditions, reduces surface pumping pressures and horsepower required to pump the cement into the well, and reduces pressures exerted on weak formations, possibly preventing circulation losses.

Another advantage of dispersants is that they provide slurries with high solids-to-water ratios that have good rheological properties. This factor has been used in designing high-density slurries up to approximately 17 lbm/gal without the need for a weighting additive. The concept can also be used to design low-density slurries in which the high-solids contents include lightweight extenders.

Dispersants have been extensively studied. It is generally agreed that the dispersants minimize or prevent flocculation of cement particles because the dispersant adsorbs onto the hydration cement particle, causing the particle surfaces to be negatively charged and repel each other. Water that otherwise would have been entrained in the flocculated system also becomes available to further lubricate the slurry.

Polyunsulfonated Napthalene (PNS). This is the most common dispersant; it is available as a calcium and/or sodium salt and can be obtained in both solid and liquid form. The commercial liquid form typically has a solids content of approximately 40%. The benefit of using PNS is that improved rheological properties can be obtained, and slurries can be pumped with reduced frictional pressures. PNS can also allow higher solids-to-water ratio slurries to be designed with improved properties.

Hydroxycarboxylic Acids. These acids, such as citric acid, may be used as the primary dispersant in freshwater slurries at higher temperatures (BHCT ≥ 200°F). This is typically advantageous with cements that have a high free alkali ( > 0.75%) content to offset their retarding properties. Citric acid is also used as a dispersant in salt- and seawater cement slurries. The concentration of use is limited by the temperature and thickening time desired, although concentrations of 0.5 to 1.0% BWOC are usually sufficient.

Fluid-Loss-Control Additives (FLAs)

FLAs are used to maintain a consistent fluid volume within a cement slurry to ensure that the slurry performance properties remain within an acceptable range. The variability of each of these parameters is dependent upon the water content of the slurry. For example, if the water content is greater than intended, the following will normally occur: thickening time, fluid loss, free fluid, sedimentation, permeability, and porosity will be increased; and density, viscosity, and compressive strength will be decreased. If the water content is less than intended, the opposite will normally occur. The magnitude of change is directly related to the amount of fluid lost from the slurry. Because predictability of performance is typically the most important parameter in a cementing operation, considerable attention has been paid to mechanical control of slurry density during the mixing of the slurry to assure reproducibility. Of equivalent importance is the slurry density during displacement, which is directly related to fluid-loss control.

Cement slurries are colloidal suspensions consisting of distinct solid and liquid phases. During the cementing operation, there are several opportunities for the fluid phase to separate from the cement slurry. This can occur when the slurry is passing through small orifices or ports, and within the annulus. When the slurry is passing through orifices, the fluid phase can be accelerated, resulting in particle bridging. In a wellbore annulus, fluid can be displaced from the slurry while it is passing though constricted areas, or to the formation, resulting in an increase in the ECD, which can lead to formation fracture (lost circulation) or flash set (dehydration). After placement, the fluid phase will filter to permeable formations, resulting in a reduction in the slurry volume and effective hydrostatic pressure, creating the potential for the migration of formation fluid into and through the cement column. FLAs are, therefore, used to prevent solids segregation during placement and to control the rate of fluid leakoff in the static state.

Neat cement slurries normally exhibit an uncontrolled API fluid loss of at least 1,500 cm³ /30 min. This value is excessive for most cementing operations, where permeable formations are encountered or where long columns of cement will be used. The amount of fluid-loss control required for a particular operation varies widely and is largely dependent upon the slurry density, the water content, the formation properties, and annular clearance.

Several materials are effective as FLAs. The materials that are currently in use can be loosely categorized in two groups according to their solubility characteristics: water-insoluble and water-soluble. With the exception of bentonite, the water-insoluble materials are polymer resins. All of the water-insoluble materials function as permeability reducers. The water-soluble materials are modified natural polymers, cellulosics, and vinylinic-based polymers. The polymeric materials, whether water-insoluble or -soluble, are all synthetic (manmade) materials. The action of FLAs depends on their solubility. The water-insolubles function by reducing the permeability of the filter cake developed.

Water-Insoluble Materials

Bentonite

Bentonite is not typically used as the primary fluid-loss agent in normal-density slurries. In low-density slurries, where higher concentrations can be used, it may provide sufficient fluid-loss control (400 to 700 cm³/30 min) for safe placement in noncritical well applications. Fluid-loss control, obtained through the use of bentonite, is achieved by the reduction of filter-cake permeability by pore-throat bridging. Fluid-loss rates can be erratic because of the concentration of use at a given density, variations in platelet disassociation caused by shear, and stacking arrangement in the filter cake.

Microsilica. Microsilica imparts a degree of fluid-loss control to cement slurries because of its small particle size of less than 5 microns. The small particles reduce the pore-throat volume within the cement matrix through a tighter packing arrangement, resulting in a reduction of filter-cake permeability.

PolyVinyl Alcohol (PVA). PVA is a white to cream-colored powder with a density range of 1.27 to 1.31 g/cm³. It is a water-soluble polymer derived from polyvinyl acetate and is chemically reactive with acids and alkalis. It is not listed in the water-soluble polymers section because it loses solubility in alkaline environments such as the aqueous phase of a cement slurry. PVA also provides gas-migration control and enhances cement bonding and acid resistance.

Synthetic Latex. This is an oil-in-water emulsion system consisting of a dispersed phase of a water-insoluble elastomer, surfactants, and a water exterior phase. These emulsions are characterized by their milky-white appearance. Their density is typically approximately 1 g/cm³ . The most common emulsion used is styrene-butadiene rubber (SBR), which provides exceptionally low fluid-loss control, gas-migration control, and acid-solubility resistance.

The surfactant system plays a key role in the use of latex in well-cementing applications. In cement slurries, the emulsion system readily disperses and exhibits time-, shear-, and temperature-dependent stability. The emulsion stability can be improved by the addition of additional surfactant, and depending on the surfactant type and concentration, the emulsion stability may be controlled to above 300°F (149°C) BHCT. The surfactant system also acts as a dispersant in the cement slurry, resulting in low slurry viscosity. Control of emulsion stability is critical to slurry performance because the rate of inversion of the emulsion controls slurry viscosity and thickening time. Inversion of the emulsion system results in an almost instantaneous conversion to a rubberized mass (set) that is reported as the pumping time for the slurry.

Latex is typically used at a concentration of ≥ 0.8 gal/sk ( ~

3.5% BWOC dry-weight equivalent) to obtain a fluid loss of less than 100 cm³/30 min. Fluid-loss values of less than 20 cm³/30 min are possible at 1.5 gal/sk in nonsilica slurries and 2 to 3 gal/sk with 35% BWOC silica slurries. Fluid loss is controlled in the cement slurry by particle plugging.

Water-Soluble Materials

Derivatized Cellulose

Two forms of derivatized cellulose have been found useful in well-cementing applications. They are the single-derivatized HEC and twice-derivatized CMHEC. The usefulness of the two materials depends on their retardational character and thermal stability limits.

Hydroxyethyl Cellulose. This is commonly used at temperatures up to approximately 82°C (180°F) for fluid-loss control and may be used at temperatures up to approximately 110°C (230°F) BHCT, depending on the co-additives used and slurry viscosity limitations. Above 110°C (230°F), HEC is not thermally stable. HEC is typically used at a concentration of 0.4 to 3.0% BWOC, densities ranging from 16.0 to 11.0 lbm/gal, and temperatures ranging from 27 to 66°C (80 to 150°F) BHCT to achieve a fluid loss of less than 100 cm³/30 min.

Carboxymethyl Hydroxyethyl Cellulose. This is commonly used at temperatures up to 300°F for fluid-loss control and may be used at temperatures up to approximately 350°F, depending on degree of substitution, the co-additives used, and slurry viscosity limitations. CMHEC is more thermally stable than HEC and is not as susceptible to oxidative attack.

Synthetic Polymers

Since the 1970s, a significant amount of work has been performed concerning synthetic copolymers for use in cement slurries. Most of this work has centered on copolymers of acrylamide and/or acrylamide derivatives and their salts; however, several nonacrylamide-based monomers have also been reviewed.

Polyvinyl Pyrrolidone (PVP). This is a nonionic polymer that is typically used as a fluid-loss enhancer in conjunction with sodium naphthalene sulfonate condensed with formaldehyde (SNFC) to improve the performance of other polymers. When used alone, PVP is not very effective as an FLA. However, when PVP is used in conjunction with SNFC, the fluid loss is improved through improved particle orientation. PVP/SNFC is particularly advantageous when used in densified cements for both dispersion and fluid-loss control. The use of PVP/SNFC, in conjunction with HEC or CMHEC, results in significant improvement in fluid-loss control. Surfactants are surface-active agents that may be used to modify the interfacial tension between two liquids or between a liquid and a solid. Low-molecular-weight polymers such as SNFC and lignosulfonate are surfactants. The choice of the proper surfactant can have a significant effect on the FLA itself and its interaction with cement particles. Surfactants can be used to accelerate or retard the solubility or wettability of polymers.

Lost-Circulation Additives

Cement slurries can be lost to the formation and not circulated back to the surface during completion of a wellbore. This is defined as lost circulation. It should not be confused with the volume decrease resulting from fluid-loss filtration. Lost circulation tends to occur in three basic formation types:

Unconsolidated or highly permeable. It is considered that the particles of a cement slurry can enter an unconsolidated or highly-permeable formation only if the permeability is greater than 100 darcies.
Fractured, induced or natural. Induced fractures occur in highly incompetent zones (e.g., shale) that break down at relatively low hydrostatic pressures. Natural fractures can be encountered anywhere.
Cavernous or vuggy. These are usually formed by erosion of the formation caused by the action of subsurface waters and are discovered unexpectedly.

In many cases, lost circulation occurs during drilling with loss of drilling fluids, and actions can be taken at that time to combat the lost circulation. At other times, difficulties may be encountered during drilling, indicating potential lost-circulation problems, and measures can be taken to prevent their occurrence during cementing. Typically, there are two steps in combating lost circulation: reducing slurry density and adding a bridging or plugging material. Additives for prevention of lost circulation can be separated into three basic groups: bridging materials, rapid-setting or thixotropic cements, and lightweight cementing systems. Bridging materials physically bridge over and/or plug the lost-circulation zone and are typically available in fibrous, flake, or granular form. Most bridging materials are considered to be chemically inert with respect to cement hydration. Fibrous materials are, in general, used for controlling lost circulation in highly permeable formations where the fibers form a mat over the surface.

The most common flake material is cellophane. Cellophane flakes act by forming mats or bridges over very narrow fractures. Concentration range of cellophane is usually from 0.125 to 0.5 lbm/sk.

Granular materials are most frequently used and include gilsonite, perlite, and coal. These coarse particles are typically used for large fractures and cavernous or vuggy lost-circulation formations. As the cement slurry enters the formation, these large granular particles, in principle, become trapped and block off the opening. Concentrations vary according to the material used and are typically, 5 to 50 lbm/sk for gilsonite, 0.5 to 1.0 ft³/sk for perlite, and 1 to 10 lbm/sk for coal. Rapid-setting and thixotropic cements are the preferred means for lost-circulation control in large cavernous or vuggy formations where bridging materials are no longer effective. These cements are usually designed to set up in the lost-circulation zone, ultimately plugging it off.

Rapid-setting cements include both quick- and flash-setting formulations. These cements generally give thin slurries but have very rapid setting times. The quick-setting cements will set up while being displaced or shortly after entering the lost-circulation zone, whereas the flash-setting cements form semisolid materials when mixed with water or water-based drilling fluids.

Thixotropic cements have a low viscosity during mixing and placing, but when they enter the formation and are no longer subjected to shear, they gel and become self-supporting. There are a number of thixotropic formulations that include gypsum cement, gypsum Portland cement, aluminum sulfate/iron (II) sulfate, clay-based systems, and crosslinked polymer systems.

It is often more effective to solve lost circulation by combining the bridging materials with rapid-setting or lightweight systems. The choice of system and the bridging material depends on the type of formation, the size of the lost-circulation zone, the fracture pressure gradient, and the downhole temperatures and pressure, as well as economics.

Strength-Retrogression Inhibitors

Strength retrogression is a normal phenomenon that occurs with all Portland cements at temperatures approximately 230 to 248°F (110 to 120°C) and is usually accompanied by a loss in impermeability. The use of 35 to 40% SiO₂ (sand or flour) is used to combat strength retrogression.

Free-Water Control

In well-cementing applications, the maintenance of a consistent column of cement is critical to assure proper zonal isolation. Because of rheological demands and the need for silica or weighting agents in some applications, this is not always possible with conventional materials. It is necessary, therefore, that an additional additive be incorporated into the cement slurry to address the potential problem of particle sedimentation. This group of additives is known as free-water-control additives.

Sodium Silicate. Sodium silicate may be used to control free water in normal- and low-density cement slurries. Typically, approximately 0.15 to 0.5% BWOC is sufficient to provide free-fluid control.

Biopolymers. Biopolymers impart the unique characteristics of thinning at higher shear rates and viscosifying at lower shear rates. This yields slurries that will more readily go into turbulent or upper laminar flow yet have sufficient low shear to prevent sedimentation. Xanthan gum and Welan gum both provide these characteristics and are typically used at an active concentration of approximately 0.2% BWOC.

Synthetic Polymers. Synthetic polymers of high molecular weight, which are resistant to alkaline hydrolysis, have been found to be effective as free-fluid-control additives at temperatures where sodium silicate and biopolymers are not effective. They are typically used at an active concentration of approximately 0.1 to 0.2% BWOC.

Expansive Cements

Expansive cements are used primarily for obtaining effective zonal isolation by improving the bond between the cement and the pipe and the cement and the annulus. Good zonal isolation is essential to prevent loss of production, control gas migration, provide protection from corrosive formation waters, reduce water production, and improve confinement of stimulation treatments. Poor bonding of cement to pipe and/or annulus is most often a result of a combination of effects from a variety of factors. The root causes are usually associated with drilling-fluid properties and displacement mechanics, casing expansion and contraction caused by thermal stresses or internal pressures, fluid loss from the cement, and hydration volume reduction during setting of cement. The resultant effect of poor bonding is the formation of "microannuli" or small gaps at the cement/casing or cement/formation interface. Expansive cements expand slightly after the cement has set and fill in the void spaces. Because of the restraints imposed by the casing and formation, any additional expansion will occupy the space provided by the internal cement porosity, resulting in a reduction in porosity. The two principal types of expansive additive or cement are post-set crystalline growth (or chemical expansion) and in-situ gas generation.

Crystalline-Growth Additives. The expansion mechanism is the growth of the crystals within the solid cement matrix. These crystals have a greater bulk volume than the original solids from which they form and, as such, cause a wedging action because of the internal pressure of crystalline growth, forcing the solid matrix apart. Crystal-growth expansion is unilateral in that restraint in one direction does not increase expansion in other directions. The amount of expansion is dependent on a number of factors that include amount of additive, curing time and temperature, and, in some cases, cement-slurry composition.

Cement slurries containing high concentrations of salt (NaCl, KCl, or CaCl₂ ) have a long reputation for contributing to expansion. Expansion is caused by the crystal growth of calcium chloroaluminate hydrate (3CaO•Al₂O₃•CaCl₂•H₂O) from reaction of the chloride ions with the aluminate phase in cement. There are indications that the temperature limitation for calcium chloroaluminate hydrate is around 51°C (125°F), although salts are reported to be effective, expanding additives up to 204°C (400°F), depending on the system. Salt also contributes to bond improvement by preventing dissolution of the salt formation.

In-Situ Gas Generation. Expansion resulting from in-situ gas-generating additives occurs before set while the cement is still in the plastic state. The most common in-situ gas-generating additive is aluminum powder, although zinc, iron, and magnesium are possible alternatives. The expansion is caused by the reaction with alkali and water present in the cement aqueous phase to produce microsized bubbles of H₂ gas. Expansive forces that are a direct function of the gas generated compensate for any volume losses caused by hydration volume reduction or fluid loss and increase the pressure of the cement against the pipe and formation. In-situ gas-generating additives can be used at temperatures from 16 to 204°C (60 to 400°F). Because of the compressibility of the gas, the amount required is more dependent on the hydrostatic pressure of the slurry than on the downhole temperature. Concentrations generally range from 0.15 to 0.6%, although they can be higher.

Miscellaneous Additives

Several additives are used that do not fit in any of the preceding categories. These additives can be used frequently (as in antifoam additives) or in more-specialized cases, such as mud decontaminants, radioactive tracers, dyes, fibers, and cement for CO₂ resistance.

Antifoam Additives

Antifoam additives are frequently used to decrease foaming and minimize air entrainment during mixing. Foaming is a secondary effect, often caused by a number of additives. Excessive foaming can result in an underestimation of the density downhole and cavitation in the mixing system.

Slurry density is usually measured with a densitometer during mixing to proportion the solids and water to obtain the desired density. When a slurry foams, the entrapped air is also included in the density measurement, and because air compresses under pressure, the actual density downhole becomes greater than that measured on the surface. Another effect of foaming is that if severe, it can cause cavitation of the pumps and ultimately lead to loss of hydrostatic pressure.

Antifoam additives, in general, modify the surface tension and/or dispersion of solids in the slurry so that foaming is prevented or the foam breaks up. The concentration of foaming additive required to be effective is very small, typically less than 0.1% BWOW. Antifoam additives consist primarily of polyglycol ethers or silicones or a mixture of both, and may also include additional surfactants.

Polypropylene glycol is the most common polyglycol ether used and is favored for its low cost. It is effective in most situations, although, typically, it has to be added before mixing. In some cases, it can interact with other additives and cause increased foaming. The silicone antifoam additives are a suspension of very fine particles of silica dispersed in a silicone base and can also exist as an oil-in-water emulsion. They can be used both before and during mixing and are highly effective as antifoam additives.

Mud-Decontaminant Additives

Paraformaldehyde or a blend of Paraformaldehyde and sodium chromate is sometimes used to minimize the cement retarding effects of various drilling-mud chemicals in the event a cement slurry becomes contaminated by intermixing with the drilling fluids. A mud decontaminant consisting of a 60:40 mixture of paraformaldehyde and sodium chromate neutralizes certain mud-treating chemicals. It is effective against tannins, lignins, starch, cellulose, lignosulfonate, ferrochrome lignosulfonate, chrome lignin, and chrome lignite. Mud decontaminants are used primarily in openhole plugback jobs and liner jobs and for squeeze cementing and tailing out on primary-casing jobs.

Radioactive Tracers

Radioactive tracers are added to cement slurries as markers that can be detected by logging devices. They were originally used to determine the location of fill-up or cement top and the location and disposition of squeeze cement, although, now, temperature surveys and cement-bond logs fulfill this function. Radioactive tracers are still occasionally used in remedial cementing to locate the slurry after placement, if required, and for tracing lost circulation. Radioisotopes are controlled and licensed by the U.S. Nuclear Regulatory Commission and various state agencies and cannot be used indiscriminately.

Dyes

Small amounts of indicator dye can be used to identify a cement of a specific API classification or an additive blended in a cementing composition. When the dyes are used downhole, however, dilution and mud contamination may dim and cloud the colors, rendering them ineffective. Naturally occurring mineral oxides and/or synthetically produced color pigments may be substituted for the dye indicator.

Fibers

Conventional Portland cement, mixed at normal density, has low ductility, making it somewhat brittle. This makes it susceptible to post-cementing stresses. Synthetic fibrous materials are frequently added to make the cement more ductile and to reduce the effects of shattering or partial destruction from perforation, drill-collar stress, or other downhole forces. Fibrous materials transmit localized stresses more evenly throughout the cement and, thus, improve the resistance to impact and shattering. Nylon, with fiber lengths varying up to 1 in., has commonly been used because it is resilient and imparts high shear, impact, and tensile strength. Particulated rubber also acts to improve the ductility of cement and improve on the flexural strength, and it is usually used in concentrations up to 5% BWOC. More recently, aluminum silicate and/or fibrous calcium silicates have been reported to enhance the compressive, flexural, and tensile strengths.

Slurry-Design Testing

Performance Testing

When determining a slurry ’ s characteristics and performance, these testing procedures are recommended:

Temperature. Test to the highest simulated BHCT with a variety of retarders, densities, and temperatures.

Pressure. Test to the actual bottomhole pressure (BHP) thickening time.[

Note: The slurry to be tested should include surface time required (if batch mixed) and calculated time to bottom. ]

Compressive Strength at the Following Top-of-liner (TOL). Ensure certain conditions are met: simulated temperature and pressure, lowest simulated BHCT used with longest thermal recovery, ultrasonic cement analyzers set for simulated temperature recovery and calculated pressure not API minimum (3,000 psi).

Mixing Effects. Investigate and standardize order of addition, time taken to add, holding of mix water, time to mix at surface, surface mixing temperature/shear effects, slurry stability, sedimentation test, and HP/HT rheology (where available).

The methods of testing cement for downhole application are based on performance testing. Testing methods are usually performed according to API specifications, though specifically designed and engineered equipment or tests are also used. The choice of additives and testing criteria is dictated primarily by the specific parameters of the well to be cemented. Performance testing has proved to be the most effective in establishing how a slurry will behave under specific well conditions. There is no direct means of predicting cement performance from the properties of cement, and no technique has yet been established, or is likely to be in the near future, that would correlate cement composition and cement/additive interaction with performance.

Diagnostic Testing

Performance testing is not adequate in troubleshooting downhole problems where the integrity of the cement blend is in question. There are diagnostic analyses that can be performed to evaluate the cement powder, but there are no definitive tests for chemically analyzing the composition of a cement once it has been mixed with additives, either as a dry blend, a slurry, or a set cement. The primary reason for this is the low concentration of additives used in the slurry or set cement. This concentration in set cement can be even lower than that of the original slurry if the additive is consumed and/or modified during the cement hydration reaction. The content of samples taken from downhole is often questionable in that it is not clear exactly where they were obtained or if they were contaminated with drilling fluid, formation waters, or during retrieval. Many of the techniques used for understanding the chemistry of cement are designed for laboratory-prepared specimens and applications and are not applicable to field samples. However, depending on the sample and the concentration of additives, some qualitative analysis can sometimes be achieved.

Analysis of dry-blended samples is somewhat different from that of the slurry or set cement. If sufficient quantity is available for performance testing, this would be the most appropriate to compare the actual blend with that designed. If this is not the case, then the blend would require dissolution in an extracting solvent. This usually includes water and, inevitably, cement hydration will occur, with some of the additive component being removed by the hydration products. As the contact time is less, more additive should be extracted and will more likely be detectable through one of the methods previously discussed. After cement and additives are blended, it is usually not possible to separate the additive from the dry sample unless it has a significantly greater particle size or heavier density than that of the cement.

Cementing Hardware

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

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 inner diameter (ID) after it is pumped into the casing/wellbore annulus; and provide a landing point for cementing plugs pumped in front of and behind the cement slurry. 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; and 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.

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. 9.6). 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.

Fig. 9.6—Typical primary-cementing equipment (courtesy of Halliburton).

When the cement plug sits at the float collar (Fig. 9.7), 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.

Fig. 9.7—Float collar (courtesy of Halliburton).

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 permit a controlled amount of fluid to enter the bottom of the casing while the casing is being run in the hole (Fig. 9.8). 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 outer diameter (OD), the threading, the material grade, and the pipe weight.

Fig. 9.8—Float collars with differential fill-up and automatic fill-up (courtesy of Halliburton).

Plug Containers

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. 9.9) 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.

Fig. 9.9—Plug container (courtesy of Halliburton).

Cementing Plugs

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 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. 9.10). 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, signaling 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. Aluminum-inserted plugs should be used when the 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.

Fig. 9.10—Five-wiper (left) and nonrotating (right) cementing plugs (courtesy of Halliburton).

Nonrotating five-wiper cementing plugs (Fig. 9.10) 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: balls, wooden plugs, subsea plugs, and teardrop or latch-down devices (Fig. 9.11). 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.

Fig. 9.11—Latch-down casing plug assembly (courtesy of Halliburton).

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; and cementing deep, hot holes where limited cement pump times restrict full-bore cementing of the casing string in a single stage.

Two types of multiple-stage cementing tools are available: hydraulically opened or plug-opened types. 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.

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, thus, requiring the plug to be pushed to the tool by a wireline sinker bar or work string (Fig. 9.12).

Fig. 9.12—Cement plugs (courtesy of Halliburton).

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 that 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.

Casing Centralizers

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. 9.13).

Fig. 9.13—Welded bow-spring centralizer (courtesy of Halliburton).

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; as a result, 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; and reduce channeling and aid in mud removal.

Two general types of centralizers are spring-bow and rigid. 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.

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.

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. 9.14). 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.

Fig. 9.14—Clamp (courtesy of Halliburton).

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.^[10] 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.^[10]

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^[10] cover starting force, running force, and 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

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. There are two general types of scratchers: those that are used when the casing is rotated and 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. 9.15), 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.

Fig. 9.15—Reciprocating scratchers (courtesy of Halliburton).

Special Equipment

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; and plug casing, while surface equipment is being repaired.

Cement baskets and external packers (Fig. 9.16) 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.

Fig. 9.16—Cement basket (courtesy of Halliburton).

Pumping Equipment

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.

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 yet, 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.

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.

Cement Mixing

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. 9.17). 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.

Fig. 9.17—Reciprocating mixer (courtesy of Halliburton).

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.

Nomenclature

B_c	=	Bearden units of consistency
O	=	ordinary
q_d	=	displacement rate, bbl/min
t_c	=	contact time, min
V_t	=	volume of fluid (turbulent flow), ft³

References

↑ ^1.0 ^1.1 ^1.2 ^1.3 ^1.4 API RP 10B, Recommended Practice for Testing Well Cements, 22nd edition. 1997. Washington, DC: API.
↑ ^2.0 ^2.1 API RP 13B, Recommended Practice Standard Procedure for Field Testing Water-based Drilling Fluids, second edition, 1997. Washington, DC: API.
↑ Brice JR., J.W. and Holmes, B.C. 1964. Engineered Casing Cementing Programs Using Turbulent Flow Techniques. J Pet Technol 16 (5): 503-508. SPE-742-PA. http://dx.doi.org/10.2118/742-PA.
↑ Calvert, D.G., Heathman, J.F., and Griffith, J.E. 1995. Plug Cementing: Horizontal to Vertical Conditions. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 22-25 October. SPE-30514-MS. http://dx.doi.org/10.2118/30514-MS.
↑ ^5.0 ^5.1 ^5.2 ^5.3 ^5.4 ASTM C150-97a, Standard Specification for Portland Cement. 2000. West Conshohocken, Pennsylvania: ASTM International. http://dx.doi.org/10.1520/C0150_C0150M-12
↑ ASTM C114-97a, Standard Methods for Chemical Analysis of Hydraulic Cement. 2000. West Conshohocken, Pennsylvania: ASTM International. http://dx.doi.org/10.1520/C0114-11B.
↑ ^7.0 ^7.1 ^7.2 ^7.3 ^7.4 Smith, D.K. 2003. Cementing. Monograph Series, SPE, Richardson, Texas 4, Chaps. 2 and 3.
↑ ^8.0 ^8.1 ^8.2 ^8.3 API Spec. 10A, Specification for Cements and Materials for Well Cementing, 23rd edition. 2002. Washington, DC: API.
↑ ^9.0 ^9.1 ASTM C618, Standard for Testing and Materials. 2000. West Conshohocken, Pennsylvania: ASTM International. http://dx.doi.org/10.1520/C0618-12.
↑ ^10.0 ^10.1 ^10.2 API Spec. 10D, Specification for Casing Centralizers, third edition. 1986. Dallas, Texas: API.

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SI Metric Conversion Factors

bbl	×	1.589 873	E – 01	= m³
ft	×	3.048*	E – 01	= m
ft²	×	9.290 304*	E – 02	= m²
ft³	×	2.831 685	E – 02	= m³
°F		(°F – 32)/1.8		= °C
gal	×	3.785 412	E – 03	= m³
in.	×	2.54*	E+ 00	= cm
lbf	×	4.448 222	E+ 00	= N
lbm	×	4.535 924	E – 01	= kg
psi	×	6.894 757	E+ 00	= kPa

*

Conversion factor is exact.

[r1-1] 1.0 ^1.1 ^1.2 ^1.3 ^1.4 API RP 10B, Recommended Practice for Testing Well Cements, 22nd edition. 1997. Washington, DC: API.

[r2-2] 2.0 ^2.1 API RP 13B, Recommended Practice Standard Procedure for Field Testing Water-based Drilling Fluids, second edition, 1997. Washington, DC: API.

[r3-3] Brice JR., J.W. and Holmes, B.C. 1964. Engineered Casing Cementing Programs Using Turbulent Flow Techniques. J Pet Technol 16 (5): 503-508. SPE-742-PA. http://dx.doi.org/10.2118/742-PA.

[r4-4] Calvert, D.G., Heathman, J.F., and Griffith, J.E. 1995. Plug Cementing: Horizontal to Vertical Conditions. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 22-25 October. SPE-30514-MS. http://dx.doi.org/10.2118/30514-MS.

[r5-5] 5.0 ^5.1 ^5.2 ^5.3 ^5.4 ASTM C150-97a, Standard Specification for Portland Cement. 2000. West Conshohocken, Pennsylvania: ASTM International. http://dx.doi.org/10.1520/C0150_C0150M-12

[r6-6] ASTM C114-97a, Standard Methods for Chemical Analysis of Hydraulic Cement. 2000. West Conshohocken, Pennsylvania: ASTM International. http://dx.doi.org/10.1520/C0114-11B.

[r7-7] 7.0 ^7.1 ^7.2 ^7.3 ^7.4 Smith, D.K. 2003. Cementing. Monograph Series, SPE, Richardson, Texas 4, Chaps. 2 and 3.

[r8-8] 8.0 ^8.1 ^8.2 ^8.3 API Spec. 10A, Specification for Cements and Materials for Well Cementing, 23rd edition. 2002. Washington, DC: API.

[r9-9] 9.0 ^9.1 ASTM C618, Standard for Testing and Materials. 2000. West Conshohocken, Pennsylvania: ASTM International. http://dx.doi.org/10.1520/C0618-12.

[r10-10] 10.0 ^10.1 ^10.2 API Spec. 10D, Specification for Casing Centralizers, third edition. 1986. Dallas, Texas: API.

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