Cementing

CementingIntroduction

History and Overview

The basic principle of oil well cementing involves displacing cement slurry down the casing to a predetermined point in the well. The slurry is formed by mixing water with Portland cement, or with cement blended with additives. This procedure controls gas/oil and water/oil ratios, and is used in various types of liner jobs and remedial work. The casing must be cemented to exclude water and other unwanted fluids. Cement slurry is forced into the annular space between the casing and the wall of the hole, where the cement can set and form a permanent barrier against water and other fluids.

Protection and Prevention

Protection of the well and prevention of possible value loss are two vital considerations in cementing.

Protection Against Pressure, Corrosion, and Shock Loading; Maintenance of Casing Support

Cement that is pumped down the casing and into the annulus between the casing and wellbore is used as a sealant to help protect:

casing and wellbore from external pressure that could collapse the pipe or cause a blowout

oil- and gas-producing strata from extraneous fluids casing from possible corrosion and electrolysis caused by formation waters and physical

contact with various strata drillstring against loss in a key-seat or sticky hole downhole production and drilling equipment pipe from the stresses of formation movement

Cement also bonds the pipe to the formation for support and minimizes the danger of blowouts from high-pressure zones.

Prevention of Fluid Migration, Lost Circulation, Pollution, and Blowouts

Lost-circulation cement, placed at critical points behind the casing and in open hole, is also used to help prevent:

unwanted migration of fluids from one formation to another pollution of valuable oil or gas zones lost circulation, by sealing off lost-circulating zones and other potentially troublesome

formations as a prelude to deeper drilling contamination of freshwater zones that may be used for domestic supply; protect other

formation strata such as coal, potash, etc. blowouts from high-pressure gas zones behind the casing cave-in of the hole during drilling unscrewing of the bottom joints in surface and intermediate strings

Manufacture & Classification of Oilwell CementsCement Manufacture and Chemistry

Cement is manufactured with materials and methods that have changed little over the last 160 years. Joseph Aspdin, a builder from Leeds, UK, was granted a patent in 1924 for "a cement of superior quality resembling Portland stone." Asp-din's cement was prepared by sintering fixed proportions of calcareous materials (limestone, chalk, seashells, etc.) with aluminosilicates (clays) in a kiln at temperatures of 1425 to 15350 C. The resulting material, which is called clinker, is then cooled and ground with gypsum to form Portland cement. Gypsum is added to prevent flash set. In addition to the basic raw materials cited above, other materials such as sand, bauxite, iron oxide, etc., may be used in the kiln feed to adjust the elemental ratios in the resulting clinker.

Portland Cement Components

The principal components of common Portland cement are

50% tricalcium silicate/C3S* (3CaO · SiO2)

25% dicalcium silicate/C2S* (2CaO · SiO2)

10% tricalcium aluminate/C3A* (3CaO · Al2O3)

10% tetracalcium aluminoferrite/C4AF* (4CaO · Al2O3 · Fe2O3) 5% other oxides

* C3S, C2S, C3A, and C4AF are commonly used abbreviated notations for the cement components.

The relative amounts of the above compounds may be varied depending on the intended application of the cement. The component having the greatest effect on the overall strength of Portland cement is C3S; it is also responsible for the early strength (1 to 28 days) of the set mass. C3S is the slow-reacting component that accounts for the gradual gain in strength of the cement which occurs over an extended period of time. Of the above components, C3A shows the fastest rate of hydration. The initial set and thickening time of cement, as well as the sensitivity of the set cement to sulfate-containing waters, are influenced by the concentration of this component. C4AF is the low heat of hydration compound in cement; the addition of Fe2O3 to the kiln feet favors the production of C4AF at the expense of C3A in the clinker. This procedure is commonly followed in the production of medium sulfate resistant (MSR — 3 to 8% C3A) and high sulfate resistant (HSR — up to 3% C3A) cements. A description of the manufacture and composition of cement may be found on pages 3 to 5 of the Halliburton Cementing Tables.

Hydration of Cement

Cement is composed principally of a blend of anhydrous metallic oxides. The addition of water to this material converts these compounds to their hydrated form. After a period of time, the hydrates form an interlocking crystalline structure which is responsible for the set cement's strength and impermeability. The formation of this structure, as the cement hydrates, is shown schematically and actually (by scanning

electron micrograph) in Figure 1 (The setting of portland cement ).

Figure 1

Water in excess of that required for cement to set is necessary for formation of slurry (a suspension of solids in a continuous liquid medium) and gives the slurry its required mobility. Removal of the excess water by filtration results in loss of slurry mobility and in deposition of the wetted cement solids as filter cake.

The amount of water required for a given slurry depends on the type of cement and the amount and type of additives used. For example, the water requirements for API class "G" cement slurry, containing varying amounts of bentonite are as follows:  

% bentonite water requirement in U.S. gals/94 lb. Sack

0 5.0

2 6.3

4 7.6

If the amount of water is correct for a given system, the slurry will have acceptable fluidity and will not show excessive solids-settling or free-water breakout. Water requirements for cement and most of the commonly used additives can be found in service company publications (e.g. Halliburton cementing tables (1981)).

Temperature Effects

As is true of most chemical reactions, the hydration of cement is accelerated by increased temperature. Figure 2 (The effect of temperature and pressure on Portland

cement thickening time ( after Bearden, 1959)) shows the effect of temperature on the thickening time of various cement slurries. The reaction of cement with water begins when they are first mixed.

Figure 2

As the reaction proceeds, but before the system achieves sufficient set to have measurable strength, the slurry shows an increase in viscosity. When the slurry reaches a viscosity equivalent to 100 poise, it is said to be no longer pumpable. The length of time required to achieve this viscosity under a given set of conditions is referred to as the thickening time.

API Cement Types

Service company literature, such as Halliburton Cementing Tables , describes the various API cement types. Section 2 of API Spec 10 describes not only the various API cement types but the chemical ( API Table 2 .1) and physical requirements ( API Table 2 .2) for each. Note that not all countries use the API classification system. RHC (Rapid Hardening Portland Cement) and HSC (High Strength Portland Cement), for example, ar two non-U.S. cement classifications that correspond roughly to API class C cement.

The API classifications and their general applications are summarized as follows: for operations outside the United States, the predominant API Classes are A and G (Smith, 1987).

API Class A cement — also referred to in the United States as "construction cement" or "common cement" — may normally be used, mixed neat, from surface to a depth of 6000 ft (1830 m) if no special properties are required. This cement is widely available and its performance can be modified by the use of additives (see the Halliburton Cementing Tables, Section 230, Blue Subsection II). Additive response and product uniformity of Class A cement are generally inferior to those of

API Class G cement.

API class B cement is intended for use from surface to 6,000 ft depth, where conditions require moderate to high sulfate resistance, while API class C is used this same depth range where early high strength is needed.

API Class D cement is intended for use from 10,000 to 14, 000 ft. depth, under conditions for moderate to high pressure and temperature. It is available in both moderately and highly sulfate - resistant types.

API Class E is intended for use from 10,000 to 14,000 ft. depth, for conditions of high temperature and pressure, and is available in both moderately and highly sulfate resistant types.

API Class F is for use in the 10,000 to 16,000 ft. depth range, under conditions of extremely high temperatures and pressures, and is available in both moderately and highly sulfate -resistant types.

API Class G is intended for use in neat slurries from the surface to a depth of 8000 ft (2438 m). This cement is available in both moderately sulfate-resistant and highly sulfate-resistant forms and may be modified by additives for use in a wide range of well depths pressures and temperatures. Specific formulations and resulting properties of Class G slurries are found in section 230 of the Halliburton Cementing Tables, (Subsection IV ).

API Class H cement is similar in form and application to class G, but is usually more coarsely ground.

Most oil well-cementing operations worldwide use slurries based on API Classes A, G, H, and C (high-early-strength cement). API Classes D, E, and F are intended for high-temperature applications, and each contains an organic set retarder added by the manufacturer. Classes D, E, and F are not widely distributed, and in some instances the set retarder is not compatible with materials added on-site.

API Class J cement is specifically intended for high-temperature applications; it does not set at BHSTs less than 230° F (110° C), and does not require the addition of silica to protect the set mass from high-temperature degradation. Class J is not widely available.

Specialty Cements

These include such materials as these cements: pozzolan , resin or plastic , gypsum , diesel oil, expanding, calcium aluminate, latex, and permafrost. Although they do not comprise the bulk of cements used in the petroleum industry, they have certain properties that are useful in various applications. These are summarized as follows:  

Specialty Cement Type Application

Pozzolan High temp.; low weight requirements

Resin or Plastic Selective plugging/squeezing operations

Gypsum Temporary remedial work requiring rapid setting, high strength

Diesel Oil Control of water zones, lost circulation

Expanding Special downhole conditions

Calcium Aluminate Extreme high temperature (i.e., in-situ combination wells)

Latex Improved bonding/filtration control requirements

Permafrost Frozen environments

Formation of Cement Slurries

Cement slurries are usually prepared in the field with a jet mixer. The components and operation of this continuous-mixing system are shown in Figure 1 (Jet mixing of oilwell cement slurries ) Jet mixers are simple, dependable, and are not volume-limited.

Figure 1

Their principal disadvantage is an inability to closely control slurry density. Various types of batch mixers utilizing either mechanical agitation or circulation are available for mixing up to 100 bbl (16 m3) of cement slurry. This type of mixer can control density within a range of 0.2 lb/gal. For some operations it is useful to prepare the slurry with a jet mixer that discharges into a batch mixer, where final density adjustments may be made before the slurry is pumped into the well. Recirculating-type jet mixers can also prepare slurries with a more uniform density.

Neat Slurries

A suspension of cement in water, containing no other components, is called a neat cement slurry. From the standpoints of ease of mixing and of economy, it would be desirable to use such slurries extensively in oil well cementing. This is usually not possible, however, since control of the properties of a neat slurry can be achieved only by slight changes in liquid/solids ratio and by choice of API cement type. Table 1 , below, gives the preferred water/cement ratio for the various API cement types, as well as the resulting slurry densities.  

API Cement Type

Recommended Water/Cement Ratio (gal/sack)

Slurry Density (lb/gal)

A & B 5.2 15.6

C 6.3 14.8

D&F 4.3 16.4

G 5.0 15.8

H 4.3 16.4

J 4.9 15.4

Table 1. Neat cement slurries

The range of densities of these slurries results from the different degrees of fineness of the various types of API cement, which affect water requirement. Of the commonly used API types, Class C is the most finely ground, Classes A and G are intermediate, and Class H is the most coarsely ground. Slurries prepared with the finer grinds tend to show slightly lower cement-slurry-filtration rates. The thickening time of neat cement slurries may be estimated from the thickening-time requirements for the various API cement classes given in Section 8, Table 8 .3, Schedules 1, 4, 5, 6, 8, and 9 of API Spec 10. API Classes A and C require a minimum thickening time of 90 minutes when tested according to Schedule 1 (final temperature 80° F [27° C]) and Schedule 4 (final temperature 113° F [45° C]). API Classes G and H must indicate a thickening time between 90 and 120 minutes when tested according to Schedule 5 (final temperature 125° F [52° C]). This information is useful for comparing the relative reactivity of the various API classes; however, a thickening-time test under simulated well conditions is an important part of most cementing jobs.

For most applications, sufficient control over slurry density, filtration rate, and thickening time cannot be obtained simply by choosing the appropriate API cement class; additives must be used to achieve slurry-property modification. Choice of the proper API cement type (when a choice is possible) can make modification by the use of additives easier.

Additive-Containing Slurries

Additives are necessary for the use of most oil well cements. This is not surprising If one considers that Portland-type cements are designed primarily for construction applications at surface conditions of temperature and pressure. For simplicity and economy, it is good practice to minimize the number of additives, thereby facilitating mixing and reducing the chances of undesirable interactions. Also, it is important to utilize optimum concentrations of additives for each situation; for this reason, slurry should be tested using on-site components and realistic procedures. The effects of a variety of additives on the properties of oil well cement, according to Dwight K. Smith, are given in Table 2 (Effects of additives on cement properties )

Table 2

Alteration of Rate of Set

Additives are used extensively to alter the rate of reaction between cement and mix water. Acceleration of the reaction rate decreases the thickening time of the slurry and thus the WOC time (time required for the cement to attain a compressive strength of 500 psi [3450 kPa]). Retardation of the rate increases both thickening time and WOC time. At shallow well depths temperatures are relatively low, pumping times are short, and it is often necessary to accelerate the set of the cement to reduce WOC time. This must be done within the constraint of retaining adequate thickening times. For deep, hot wells slurries are usually retarded to attain sufficient thickening time (plus a safety factor), but over-retardation must be avoided or WOC time will be unduly prolonged.

Cement Testing Procedures

Cement-Testing Procedures

API Spec 10 covers in detail the laboratory methods used to perform API cement tests. Properties that are covered under the API test procedures include soundness

and fineness, free water content (i.e., filtration rate), compressive strength and thickening time. Tests for these physical properties involve both chemical and physical analysis.

Some general observations about cement-slurry testing are worthy of mention here:

Testing serves both as a tool for pre-job quality control and as a means of post-job evaluation and/or troubleshooting, as well as future job planning.

API specifications do not cover all the properties of cements over the wide range of conditions experienced in the field.

The do, however, list properties for various classes of cements that will fit most well conditions (Smith,1987).

Cement characteristics vary from one manufacturer to another, and can vary over time from the same manufacturer. Also, mix-water chemistry can have a significant influence on cement properties. The information in service company tables or API bulletins is helpful in a general way, but most jobs require testing samples of on-site components.

If cement-slurry components are sent to a service company laboratory for testing, the quantity and quality of the samples should be adequate. At least 5 kg of dry cement is needed to perform the usual set of tests. The cement should be placed in a clean, dry, airtight metal or plastic container. If a mix-water sample is sent, at least 4 liters should be placed in a plastic or glass container; glass should be carefully packed to prevent breakage. Metal is not used because of the reaction between the water and the container.

Fluid-Loss Test

The rate at which a cement slurry loses the water required for its fluidity through a permeable barrier is called filtration rate or fluid-loss rate. Appendix F of API Spec 10 describes procedures for performing both the low-pressure (100 psi [689 kPa]/room temperature) and the well-simulation (1000 psi [6890 kPa]/simulated BHST) fluid-loss tests. The API high-pressure test (performed according to Paragraph F.2 of API Spec 10) has been found to produce more useful information than the API low-pressure/room-temperature test. Data from the low-pressure/room-temperature test should be used with caution. The only advantage of the low-pressure/ room-temperature test is that it can be performed in the field; because the high-pressure test requires a consistometer, it must be done in a cement laboratory.

Operating Compressive-Strength Tests

Cement-strength data, described in Appendix D of API Spec 10, is useful for establishing WOC time and monitoring the stability of the set material. Several authors have addressed the question of what degree of cement strength is required to allow the safe resumption of operations. Although certain general guidelines have been established with repsct to cement compressive strength, it is best to refer to specific government regulations, as they may vary among different locations.

The final curing temperatures found in Table D.1 of API Spec 10 ("Well-Simulation Test Schedules for Curing Strength Specimens") are intended to simulate BHSTs, whereas comparable temperatures for thickening-time tests (Section 8 and Appendix E of API Spec 10) simulate bottomhole circulation temperatures (BHCT).

Operating Thickening-Time Tests

The thickening time of a slurry when tested according to simulated well conditions is one of the more important properties of an oil well cementing slurry. Insufficient thickening time can result in cement deposits in the casing, tubing, or drillpipe, and has economically disastrous consequences. Excessively long thickening time necessitates unduly long waiting on cement (WOC) time, and in extreme cases of over-retardation can result in cement that never sets. By accepted practice, cement-slurry thickening time (when tested realistically) is the estimated job time plus a safety factor — usually one hour. Estimated job times may vary considerably, however, and one hour may not necessarily be a good safety-factor general guideline.  

Application Schedule Numbers

Pages in API Spec 10

Specification testing 1-9 29-31

Casing cementing 1g-11g 52-57

Liner cementing 22-32 58-61

Squeeze cementing and plug setting

12.21 62-70

Table 1: API Thickening-time schedules.  

Depth - Ft Factor Depth - Ft Factor

1,000 1.020 11,000 1.160

2,000 1.035 12,000 1.165

3,000 1.050 13,000 1.160

4,000 1.070 14,000 1.150

5,000 1.085 15,000 1.140

6,000 1.100 16,000 1.125

7,000 1.115 17,000 1.105

8,000 1.130 18,000 1.1085

9,000 1.140 19,000 1.060

10,000 1.155 20,000 1.030

Table 2: Factors for converting log temperature to bottomhole static temperature. (From Halliburton).

Section 8 and Appendix E of API Spec 10 describe accepted equipment and laboratory procedures used for oil well cement-thickening-time testing, including

several categories of time/ pressure/temperature schedules. Section 8 describes specification tests, and Appendix E lists various operating thickening-time tests. The proper application of these testing schedules is summarized in Table 1.

Selection of an appropriate liner cementing (No. 22-32) or casing cementing (No. 1g-11g) thickening-time schedule depends on a knowledge of bottomhole static temperature (BHST), so the temperature gradient in °F/100 ft of vertical depth should be calculated. If the BHST is unknown, it may be estimated by use of the empirical relationship between logging and static temperatures in Table 2. The correct application of the API squeeze, liner, or casing thickening-time schedules (or interpolations thereof) produces reliable data for establishing retarder requirements. In some cases, where unusual geothermal gradients are encountered (outside the 0.9 to 1.9 °F/100 ft range) or for cementing through a long riser in very deep water (>1000 ft or 305 m), the use of a special time/pressure/temperature schedule may be required.

Determination of Slurry Density

Cement-slurry density measurements can and should be used in the field to monitor cement slurry-quality. Appendix C of API Spec 10 describes (with reference to API RP 13B) the accepted procedure for making this measurement. The pressurized-fluid density balance described in Paragraph C.5 of API Spec 10 should be employed during density measurement of a slurry containing entrapped air (e.g., a salt-containing slurry).

Cement Additives

Cement Additives

Almost all cement used in oil and gas wells is Portland cement. However, neat cement is seldom used throughout a job since various additives are usually necessary to modify the properties of either slurry or set cement. With basic cements (API Class G or H) and the use of additives, cement slurries can be tailored for any specific requirement.

Most additives in current use are free-flowing powders that are dry-blended with the cement prior to its transportation to the well. When necessary, some powdered additives can be dispersed in mixing water at the site. Liquid additives are more commonly used offshore and in remote land locations where dry cement blending and storage are a problem.

Properties that are modified by additives are shown below:

For the slurry:

thickening time (acceleration, retardation) density (extenders, weight increase/reduction) friction during pumping fluid loss (by filtrate) lost-circulation resistance (whole slurry loss)

For set cement:

compressive strength strength retrogression (loss with time) expansion/contraction

Accelerators

Cement-setting time is accelerated to reduce WOC time and to increase early strength. This is desirable for surface pipe, in shallow (cooler) wells, and for setting plugs.

General pressure recommendations are as follows:

pipe support and zonal isolation — 100 psi (690 kPa)

drilling out — 500 psi (3450 kPa)

perforating  

—bullets — 500 psi (3450 kPa)

—hollow carrier or expendable jets — 2000 psi (13,800 kPa)

whipstock plug — 2500 psi (17,200 kPa) or greater (or harder than formation)The most common accelerators are calcium chloride, sodium silicate, sodium chloride (low concentrations), seawater, hemihydrate forms of gypsum, and ammonium chloride. Table 1 shows typical amounts used per sack.  

Type Amount used per sack (% by weight)

Accelerators  

Calcium Chloride (CaCl2) (flake, powder, an hydrous) 2 - 4

Sodium Chloride (NaCl)  3 - 10 (water)

  1.5 - 5 (cement)

Hemihydrate forms of 20 - 100

Gypsum (plaster of Paris)  

Sodium Silicate (Na2SiO3)w 1 - 7.5

Cements with dispersants and reduced water 0.5 - 1.0

Sea Water  

Retarders  

Calcium-Sodium Lignosulfonate 0.1 - 1.0

Calcium Lignosulfonate 0.1 to 1.0

Calcium Lignosulfonate 0.1 to 2.5

plus organic acid  

CMHEC 0.1 to 1.5

Saturated Salt 15 to 17 lb/sk

Table 1. Commonly used accelerators and retarders. (Source: Halliburton Services).

Retarders

Cement-thickening time is slowed primarily to allow the slurry to be pumped and displaced into position before setting. Retarder additives include calcium lignosulfonate, organic blends, carboxymethylhydroxyethyl cellulose (CMHEC), borax, sodium chloride (in high concentrations), and most fluid-loss agents (see Table 1).Thickening time is a function of both temperature and pressure, and these effects must be predicted before additives are selected  

Type Amount used per sack (% by weight)

Accelerators  

Calcium Chloride (CaCl2) (flake, powder, an hydrous)

2 - 4

Sodium Chloride (NaCl)  3 - 10 (water)

  1.5 - 5 (cement)

Hemihydrate forms of Gypsum (plaster of Paris)

20 - 100

Sodium Silicate (Na2SiO3) 1 - 7.5

Cements with dispersants and reduced water

0.5 - 1.0

Sea Water —

Retarders  

Calcium-Sodium Lignosulfonate 0.1 - 1.0

Calcium Lignosulfonate 0.1 to 1.0

Calcium Lignosulfonate plus organic acid 0.1 to 2.5

CMHEC 0.1 to 1.5

Saturated Salt 15 to 17 lb/sk

Table 1: Commonly used accelerators and retarders. (Source: Halliburton Services).

Thickening time can also be shortened by interruption of pumping (loss of agitation). API tests may be done in this manner to simulate actual interruptions during squeezing.

An increase in water volume increases the thickening time of unretarded cement (Classes A, C, G, and H). With retarded cements (Classes D, E, and F), however, increased water or solids may decrease thickening time by reducing the concentration of retarder.

The thickening time of a slurry under realistic conditions must be established to ensure adequate pumping time for slurry placement.

Excessive thickening time must be avoided to prevent:

delays in resuming drilling operations settling and separation of slurry components formation of free-water pockets loss of hydrostatic head and gas cutting

Density-Reducing Additives

Slurry density may be reduced with extenders such as bentonite, pozzolan, diatomaceous earth, and anhydrous sodium metasilicate. Table 1 shows typical additive concentrations.

Low-density slurry is frequently preferred, to decrease the likelihood of breaking down the formation and causing lost circulation. In addition, low-density slurries cost less per cubic foot because yield per sack is increased.

Density decrease results in large part from increased water content. Extenders, with their high surface area to "tie up" water, permit water addition without separation. Cement strength is reduced approximately in proportion to water-content increase. However, we shall see later that high strength is not always required.  

Type Amount used per sack(% by weight)

Density reducers/extenders  

Bentonite 2 to 16

Attapulgite 1/2 to 4

Diatomaceous Earth (Diacel D) 10, 20, 30 or 40

Pozzolan, Artificial (fly ash) 74 lb/sk

Natural hydrocarbons:  

Gilsonite 1 to 50 lb/sk

Coal 5 to 50 lb/sk

Pozzolan-Bentonite Cement Variable

Sodium Silicate 1 to 7.5 lb/sk

Expanded Perlite 5 to 20 lb/sk

Hollow Spheres Variable

Density increasers  

Sand 5 to 25

Barites 10 to 108

Ilmenite (iron-titanium oxide) 5 to 100

Hematite 4 to 104

Salt 5 to 16

Friction Reducers 0.05 to 1.75

Table 1: Materials used to vary slurry density.( Source: Halliburton Services).

For years, bentonite has been the most commonly used additive for filler-type cement. In addition to its effect on density, yield, and cost, bentonite increases viscosity and gel strength, which reduces settling of high-density particles (e.g., weight material, cement), or floating of low-density particles (e.g., perlites, pozzolan, gilsonite, crushed coal, hollow spheres). Bentonite also reduces API fluid loss. However, cements containing bentonite are more permeable and have lowered sulfite resistance.

Pozzolans increase slurry viscosity and provide low permeability. Sodium meta-silicate provides a very low density slurry with early compressive strength; this material and calcined shale-cement (a special cement, not an extender) are becoming popular, particularly in offshore applications.

Very light slurries (less than 8 lb./gal.) have been made using hollow spheres. These new cements are useful in underpressured, hot geothermal wells and other special applications.

Density-Increasing Additives

High density cement sluries are often necessary to offset the high pressures that are frequietly encontered in deep or abnormally pressured fromations. Density may be increased with weight material such as sand, barite, hematite or ilmenite, and/or salt dissolved in the mix water, as shown in Table 1.  

Type Amount used per sack (% by weight)

Density reducers/extenders  

Bentonite 2 to 16

Attapulgite 1/2 to 4

Diatomaceous Earth (Diacel D) 10, 20, 30 or 40

Pozzolan, Artificial (fly ash) 74 lb/sk

Natural hydrocarbons:  

Gilsonite 1 to 50 lb/sk

Coal 5 to 50 lb/sk

Pozzolan-Bentonite Cement Variable

Sodium Silicate 1 to 7.5 lb/sk

Expanded Perlite 5 to 20 lb/sk

Hollow Spheres Variable

Density increasers  

Sand 5 to 25

Barites 10 to 108

Ilmenite (iron-titanium oxide) 5 to 100

Hematite 4 to 104

Salt 5 to 16

Friction Reducers 0.05 to 1.75

Table 1: Materials used to vary slurry density.( Source: Halliburton Services).

Available densities and effects on compressive strength are shown in Table 2.  

Material Spec. Gravity (lb./gal)

Max. Density

Effect on compressive strength

Ottawa Sand 2.63 18 None

Barite 4.25 19 Reduce

Coarse Barite 4.00 20 None

Hematite 5.02 20 None

Ilmenite 4.45 20 None

Dispersant 17.5 Increase  

Salt 18 Reduce  

Table 2: Densities of weight materials and their effect on compressive strength.

A density of 22 lb/gal can be obtained with hematite or ilmenite plus friction-reducing additives. Fine barite requires a large amount of water, which reduces compressive strength and retards thickening time.

Slurry weighted with solids must have adequate viscosity and gel strength to carry and suspend high-specific-gravity solids. In addition, some additives (e.g., fluid-loss agents, retarders, water) tend to significantly thin or thicken a slurry.

High slurry densities (up to 17.5 lb/gal) may be obtained by (1) using heavy additives and/or (2) adding dispersants to achieve pumpability at lower-than-normal water/cement ratios. The latter is more expensive, but it yields the highest compressive strength.

Pretesting of such high-density slurries should include measurement of density, thickening time, compressive strength, settling, free water, and viscosity.

Filtration-Control Additives

Fluid loss, or the premature escape of mix water from the slurry before chemical reaction occurs, can cause many downhole problems, including

differential sticking of casing and decentralization

formation damage by filtrate (if not controlled by mud cake)

loss of pumpability

cement bridging above gas zones and gas cutting from hydrostatic pressure loss

improper or premature dehydration during squeezing

Filtration-control additives in present use and their recommended concentrations are listed in Table 1.  

Type Amount used per sack (% by weight)

Fluid-loss additives 0.5-1.5%

Organic polymers (cellulose), form micelles

Organic plymers (dispersants), size distribution and form micelles

0.5 - 1.25%

Carboxymethyl hydroxyethyl cellulose, from micelles

0.3 - 1.0%

Latex additives, form films 1.0 gal/sk

Bentonite cement with dispersant 12-16% gel

Table 1: Materials to reduce filtrate loss, friction.

These materials function by forming micelles or films, and/or by improving particle-size distribution, which holds liquids.

A neat Class G or H slurry has an API 30-minute filter loss of over 1000 ml. Figure 1 shows the effectiveness of high-molecular-weight synthetic polymer in reducing filter loss.

Figure 1

Friction Reducers

Friction reducers or dispersants are commonly used to lower viscosity, yield point and gel strength of the slurry to reduce friction in pipe, and thus allow turbulent flow to occur at reduced pump rates. For example, to achieve turbulent flow with 7 5/8 in. casing in a 8 5/8 in. hole requires a rate of over 600 gal/min. With 0.5, 0.75, and 1.0% friction reducing additives (FRA), the required rate is only 530, 300, and 210 gal/min, respectively. These additives also permit slurries to be mixed at lower water/cement ratios so that higher densities may be achieved.

Some common dispersants are alkylaryl sulfonate, polyphosphate, lignosulfonate, salt, and organic acid. Table 1 shows typical concentrations. Turbulent-flow additives tend to cause settling and excessive free water. These effects should be tested in the lab prior to field use.  

Type Amount used per sack (% by weight)

Friction reducers/ dispersants  

Polymer: blend 0.5 to 0.3 lb/sk

Polymer: long chain 0.5 to 1.5 lb/sk

Calcium lignosulfonate 0.5 to 1.5 lb/sk

(organic acid)  

Sodium Chloride 1 to 16 lb/sk

Organic acid 0.1 to 0.3 lb/sk

Table 1: Materials to reduce filtrate loss, friction.

Lost-Circulation Materials

"Lost circulation" or "lost returns" refers to the loss to formation voids of either whole drilling fluid or cement slurry used during the course of drilling or completing a well. It should not be confused with volume decrease caused by filtration.

Drilling fluids or slurries are usually lost to either natural or induced formation fractures. These fluids may also be lost through highly permeable formations — those starting at about 5 darcies for drilling fluid with a maximum particle size of 0.002 in. (300 mesh). Cement, with its larger particle size (neat cement has 2.6 to 18% particles larger than 200 mesh) is less susceptible to loss in permeable formations.

The best time to treat the formation to reduce such fracture or formation permeability is during drilling, when high concentrations of bridging materials and various types of plugs (pills) may be utilized.

During primary cementing, concentrations of such materials must be carefully controlled to avoid bridging the casing or liner-borehole annulus, or plugging downhole equipment such as bottom wiper plugs, small-diameter stage tools, and float equipment.

Types of lost-circulation additives available for cement are blocky-granular materials (walnut shells, gilsonite, crushed coal, perlite-expanded and perlite-semiexpanded) which form bridges, and laminated materials (cellophane flakes) which form flake-type mats. In laboratory studies, granular material was found to be best suited for bridging fractures ( Figure 1 ,

Figure 1

the performance of LCM materials in sealing simulated  

Type material

Generic name

Type particle

Volumes used, typical range

Granular Gilsonite Graded 5-50 lb/sk

  Perlite Expanded 1/2-1 cu ft/sk

  Walnut shells

Graded 1-5 lb/sk

  Coal Graded 1-10 lb/sk

Lamellated Cellophane Flakes 1/8-2 lb/sk

Fibrous Nylon Short fibers 1/8-1/4 lb/sk

Table 1: Ranges of lost-circulation material (LCM) volumes used per sack.

Fibrous materials (such as nylon fibers) are used in drilling fluid for sealing large openings but are not normally used in cement because they tend to plug surface and downhole cementing equipment. Also, most other fibrous materials contain organic chemicals that can seriously retard cement-thickening time.

Ranges of lost-circulation material (LCM) values used per sack are listed in Table 1.

Salt

Salt has many different properties. In addition to its uses as a dispersant and in slurry densification, it may be used as a cementing additive in the following ways:

• Bonding to Salt Formations Saturated-salt slurries are the best overall choice for cementing across salt zones because they do not dissolve the salt zone and thus give a better formation-to-cement bond.

• Protecting Clay and Shale Formations Small amounts of sodium chloride (NaCl) and potassium chloride (KCl) help protect clay and shale formations that are otherwise susceptible to crumbling and sloughing.

• Acceleration Use of salt may be used as an accelerator. KCl in small amounts also promotes early-strength development.

• Retardation Saturated salt is an effective retarder in circulating temperatures up to about 23° to 260° F (100 to 127° C)

• Expansion Salt can be used to cause linear expansion of cement to occur long after the cement has set. This effect is minor but beneficial in obtaining a better formation-to-cement bond.

Compressive-Strength Stabilizers

Four variables — composition, temperature, pressure, and time — affect compressive strength. However, at high temperatures, cement compositions may retrogress (lose strength) after reaching a high value and never attain the strength reached at lower curing temperatures ( The effect of curing: Figure 1 , pressure and Figure 2 , temperature on cement strength.

Figure 1

The high temperatures cause strength retrogression).

Figure 2

This strength retrogression is accompanied by increased cement permeability, e.g., a neat retarded cement with 0.02+ md permeability at 290° F (143° C) after three days may have 8+ md at 320° F (160° C) after seven days.

Retarded cement (used in high-temperature applications) and high-water-content cement seem particularly subject to strength retrogression. For cement types used in deep and/or hot wells, the phenomenon begins at around 260° F (127° C), and becomes severe at 290° F (143° C).

Silica flour in high percentages inhibits strength retrogression and produces compressive strength far in excess of that of neat cement. Silica flour also reduces permeability of set cement; for instance, its addition to cement cured at 350° F (177° C) reduces permeability to less than 0.001 md.

Usually 30 to 40% silica flour is used. Silica sand ground to 200 mesh reacts with cement in the same way as fine-ground 325-mesh silica flour. Sand is used when high density is desired, and flour when low density is adequate. The different densities are achieved because of the different water requirements of the sand and the flour. Compositions containing silica sand or flour can be retarded effectively for high-temperature wells.

Natural pozzolans and fly ash produce a strong material with silica-stabilized cements up to 450° F (232° C). At a temperature of 600° F (315° C), fly ash and, to a lesser degree, natural pozzolans can cause cement to weaken and become more permeable.

Other Additives

Other additives are materials that do not fit readily into classifications. They are usually compatible with classified additives, and include the following:

Radioactive tracers are added to serve as markers that can be detected by logging devices. Radioactive tracers include iodine 131 (8-day half-life), scandium 46 (85-day half-life), liquid iridium 192 (74-day half-life), and sand for squeeze work.

Anti foam agents are available in dry or liquid form to combat air entrainment. They are used routinely in many cements to facilitate mixing. Some additives can cause excessive air entrainment, making it difficult to achieve the desired slurry density without the addition of anti foam agents.

Dyes are occasionally employed as an aid to determine the effectiveness of mud displacement during cementing operations.

Mud decontaminants neutralize certain mud-treating chemicals that could have a detrimental effect on the cement. They are used primarily in openhole plug-back and liner jobs, squeeze jobs, and tail-in primary casing jobs.

Gypsum additives, which create thixotropic properties in cement slurry, help combat lost circulation through rapid gel-strength development. Viscosity increases and slurry gelling is induced when shear rate is reduced. Gypsum additives decrease cement mobility and thus its setting time. In addition, these additives have expansion properties to improve bonding in set cement.

Primary Cementing Equipment

Surface Mixing and Pumping Facilities

Major components of surface-cementing equipment are:

mixers or blenders

pumping/displacing unit

cementing or plug-release head

Mixing Equipment

Dry cement must be mixed with the proper amount of water to ensure that slurry and set-cement properties are as designed.

For most slurries, the jet mixer produces a uniform mixture. Special mixing equipment is sometimes required for high-density cement, high-viscosity cement, and jobs for which precise composition and blending of all additives is particularly critical (such as liner and squeeze-cementing operations).

The jet mixer induces a partial vacuum at the venturi throat, drawing in the dry cement. High stream turbulence then provides thorough mixing ( Figure 1 , Schematic of jet mixer and typical job-site setup). The jet mixer is simple, reliable, and rugged, and can handle 50 sacks of cement per minute.

Figure 1

Batch mixing and/or blending is achieved through use of propeller- or impeller-type mixers, paddle mixers, ribbon blenders, pneumatic mixing, and rotation of the cement tank (similar in appearance to those used in construction). Figure 2 (pneumatic blender ) and Figure 3 (ribbon blender ) illustrate pneumatic and ribbon types.

Figure 2

Figure 3

Only a limited amount of cement can be mixed in a batch unit. However, several units can be combined to provide continuous operation on large jobs. Batch mixers provide the most accurate and thorough mixing of all slurry components.

Density measurements are made to gauge consistency and control the mixing operation. Variations during a job can result from nonuniform blending of dry components, changes in water/cement ratio, or air entrainment in the sample.

Density is measured either on samples with balances (two types), or continuously with radioactive devices or a force-balanced U-tube.

Pump-Skid Truck

The typical slurry-pumping unit ( Figure 4 : Courtesy of Halliburton Energy Services) is truck-mounted, and contains diesel engines and displacement tanks that are accurately graduated so that water or mud volumes can be controlled to place the slurry downhole properly.

Figure 4

In operation, the pumper draws slurry from the mixer in a predetermined volume calculated from sacks and yield. Meanwhile, displacing fluid is drawn from storage to two open tanks on the pumper. The slurry is followed immediately by the fluid, which is gauged by the alternate draining and filling of the two tanks.

Cementer or pump-skid styles vary greatly, from small portable units to large truck-mounted systems. Most work is done at less than 5000 psi, but pressures up to 20,000 psi (137,900 kPa) can be handled with proper equipment. Pumping rates are dependent on mixing capacity. High rates are 10 to 15 bpm. When nearing the end of displacement, slow rates are preferred, to decrease the possibility of plug or casing damage.

Cementing Heads

Cementing heads provide a connection for pump-truck and rig-pump lines into the casing, and a receptacle for the plugs. Modern heads provide a quick-change cap that can be removed to insert the cement plug ( Figure 1 , cement head with manual plug release).

Figure 1

Most cementing heads are designed to hold one or more plugs and are loaded before the actual cementing operation. Plugs are selectively released into the casing from the head. When casing rotation is desired, an adapter swivel is used between the topmost collar and the head, and the casing is suspended by the rotary table slips. The advantage of using a cementing head that provides space for two plugs is that it allows for continuous pumping; that is pumping of the cement can proceed while the top plug is being dropped.

Conventional Casing Jobs and Equipment Applications

The conventional two-plug casing job is illustrated in Figure   1 (Principal equipment used in typical two-plug primary cement job ).

Figure 1

A predetermined volume of slurry is pumped into the casing between two wiper plugs. The bottom plug ruptures when it seats; the top plug is solid. The top plug is displaced with mud or completion fluid. Flow stops and pressure builds when the top plug lands. Check valves in the float shoe to prevent backflow of the heavier column of slurry in the annulus.

Guide/Float Shoes and Collars

In most cases, except in certain shallow wells, a round-nosed shoe is run on the bottom joint to guide the casing past borehole irregularities encountered while the string is run. Three types of shoes are commonly used:

· guide shoes without valves of any kind

· float shoes with a check valve that prevents slurry backflow

· differential or automatic fill-up types

Collars have basically the same features as shoes Figure   2 (Regular type guide shoe )

Figure 2

Figure   3 (Down jet type guide shoe )

Figure 3

Figure   4 (Insert self fill-up float valve )

Figure 4

Figure   5 (Standard float collar )

Figure 5

Figure   6 (Standard float collar with double demale threads )

Figure 6

Figure   7 (Insert valve float shoe with self fill-up unit )

Figure 7

Figure   8 (Cement baffle collar with latchdown plug and sealing sleeve ).

Figure 8

They are commonly known as baffle collars (without valves), float collars, and differential or automatic fill-up collars. Located one or more joints above the shoe, the collar, in addition to float and fill-up functions, acts as a seat for pump-down wiper plugs.

Since cement immediately below the wiper plug may be contaminated, the collar should be positioned to minimize the amount of contaminated cement pumped out around the shoe.

When float equipment is used, it prevents fluid from backflowing up the casing as the casing is run in the hole. This causes the casing to 'float' downhole because it is partially empty and somewhat buoyant. To control buoyancy effects with fluid when using float shoes or float collars from a surface fill-up line.

Wiper Plugs and Displacement Concepts

Wiper plugs are used to separate cement from preceding or following fluids ( Figure   1 , top and bottom wiper plugs). The bottom plug also removes mud from the wall of the casing, and prevents this mud from accumulating beneath the top plug and being deposited around the lower casing joints.

Figure 1

When the two-plug system is used, the operator should verify that the bottom plug is, in fact, placed in the bottom position in the cementing head. A mechanical device should be used to give visual proof when the top plug leaves the head.

A bottom plug is not recommended with large amounts of lost-circulation material in the slurry or with badly rusted or scaled casing, since such material may collect on the ruptured diaphragm.

Displacement of the top plug should be carefully monitored. Fluid behind the plug should be determined from calibrations on cementing-unit tanks or by measuring out of a storage tank. Another method is to count pump strokes and convert to volume. If available, a flowmeter can be used to verify volumes pumped.

If the top plug does not bump at a calculated volume (allowing for displacement-fluid compressibility), displacement should be stopped. Troubleshooting the situation, as well as keeping track of the top plug, requires that we have accurate measurements of the volume of surface lines and equipment, the capacity of the casing, the depth to the top of the float collar, and the amount of fluid pumped. Surface equipment capacity should be estimated for individual locations ( although this capacity will be small compared to the hole volume), while the volume inside the casing is base on its lined capacity (i.e.ft. per linear ft.), which is available from service company tables or cementing handbooks.

Casing Centralizer Design/Selection Factors

Casing centralizers are used to

improve displacement efficiency

prevent differential pressure sticking

keep casing out of key seats

Two general types of centralizers are spring-bow and rigid. The spring-bow type has greater ability to provide standoff where the borehole is enlarged. The rigid type provides more positive standoff where the borehole is "to gauge." Special close-tolerance centralizers may be used on liners.

Important design considerations are positioning, method of installation, and spacing. Centralizers should be positioned on casing

through intervals requiring effective cementing

adjacent to (sometimes passing through) intervals subject to differential sticking and may be used on casing that passes through the doglegs, and is thereby subject to key-seat sticking.

Correct positioning requires a caliper log of the wellbore so that locations correspond with to-gauge sections of the borehole. Installation method depends on the type of centralizer: solid body, split body, or hinged. The hinged type is most commonly installed.

Centralizers are held in their relative positions on the casing by either the 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. Therefore, the bow-spring type centralizer should not be allowed to ride free on a casing joint.

Load-deflection curves may be used for determining the spacing required to achieve desired standoff ( Figure 1 , centralizer with proper stop collar location and example load-deflection curve). The standoff required to prevent differential-pressure sticking is normally less than that required to centralize casing for good displacement efficiency.

Figure 1

The lateral load imposed on a casing centralizer is the combined effect of centralizer spacing, casing weight, hole angle, and weight of casing below the centralizer and dogleg (a minor effect).

Equations to calculate lateral load are available in World Oil's Cementing Handbook (Suman et.al., 1977), p. 44. These can be programmed for calculators, and are effective design aids. Data is also available from manufacturers and from API Spec 10D.

Field practices for centralizer spacing are summarized in Table 1 below.

Surface casing One centralizer should be placed immediately above the shoe and one at the top of each of the bottom six joints, to ensure centralization and uniform placement of cement in this critical section. Centralizers may also be installed to improve cement placement around any critical water sands.

Intermediate casing One centralizer should be placed immediately above the shoe and one at the top of each of the bottom six joints. Centralizers may also be placed within the cement interval to ensure uniform cement distribution opposite critical zones.

Production casing Place one centralizer immediately above the shoe and one at the top of each of the bottom six joints. They should be placed on every joint through the producing zones and extending 100 feet above (and below, if applicable). Other potential problem zones, key seats, sticking areas, etc. should also be protected with centralizers.

Liners Use centralizers if clearance and hole conditions permit.

Stage cementing Centralizers should be spaced over the cemented interval above the stage collar and one joint below, since there is no casing movement in such jobs. When used, the external packer acts as the lower centralizer.

Table 1: Rules of thumb for centralizer spacing in vertical holes. Source: World Oil Cementing Handbook.

Wipers and Scratchers

Wipers and scratchers are used primarily to remove borehole mud cake. They also aid in breaking up gelled mud. Both rotating and reciprocating styles are available. See ( Figure   1 ,

Figure 1

part a,b and c: rotating types ; part d: rotating type and Figure   2 , part e and f: reciprocating types ).

Figure 2

These devices are rarely used on liners because of close clearances.

Rotating-type wipers or scratchers are run across the zone of interest plus an additional 20 ft (6 m) above and below the zone. Reciprocating-type scratchers are generally spaced at 5- to l5-ft (1.5- to 4.5-m) intervals throughout the zone and an additional 20 ft above and below.

When reciprocating, the vertical casing movement should always exceed the distance between wipers or scratchers. If reciprocal movement equals the spacing, removed mud cake and cuttings can accumulate at the end of each stroke.

When wipers or scratchers are used, mud circulation should always be started before the pipe is moved; and initially, the pipe should be moved slowly. If no pipe movement is planned, these devices should not be run.

Primary Cementing Operations

Primary Cementing

Primary cementing is the cementing operation performed immediately after casing has been run in the hole. This basic principle varies with the many materials used to perform the many cementing operations. More and deeper wells are being drilled that have extreme temperatures, both hot and cold, in new and more hostile environments. This presents a constant challenge to successful primary cementing. Meeting this challenge has led to an increasing number of ingenious and complex materials, tools, equipment, and techniques.

Primary cementing uses several basic techniques. The most widely used procedure is the single-stage primary cement job using a two-plug method. Cement is pumped down the casing between two rubber plugs. The plugs are equipped with wiping fins to help prevent contamination of the cement by drilling mud, and to help clean the interior wall of the casing.

The use of other common techniques depends on well depth and completion requirements. Two-, three-, and four-stage cementing procedures decrease the hydrostatic pressure of the fluid column in the annulus, help protect weak zones against excessive high pressures, and help prevent circulation loss. In addition to its economic advantages (i.e., it is not necessary to cement the entire string back to the surface), multiple-stage primary cementing is also important in wells where two or more zones are separated by long intervals.

Terminology

Setting the casing at or near the bottom and perforating it for expected production is common practice in the industry. Sometimes the casing is suspended and cemented above the producing formation and the well is produced from open hole; this is called an openhole completion. The final casing string is called the flow string or oil string. The field terms long string and production string are used in some areas. The term casing string denotes the total footage of casing run in the well at one time.

The phrase "waiting on cement," or WOC, has long been a misnomer in most instances: the nonproductive and expensive time spent waiting has usually not been necessary. In most cases, the cement has firmly set some time before operations are resumed. In the early days of cementing, standards for curing concrete in the construction industry were adapted as appropriate WOC time for oil wells. The first wells were shut down for 28 days to allow the cement to set. Ten years later, oil field operators were reducing the time to three weeks, and some were resuming operations after only two weeks. Ten years after that, 10 days was considered sufficient. Some 30 years after cement was first used, most operators accepted three days as sufficient WOC time. Accelerators are currently added to cement, and make it possible to resume operations within a few hours.

Important considerations in the determination of WOC time are:

how much strength the cementing composition must develop before drilling can continue

the strength development characteristics of the commonly used cementing compositions, as well as those of available materials that are not being used to their best advantage

cement-curing temperatures that exist under wellbore conditions

By using curing pressures that closely simulate those found in oil or gas wells, it is possible to have a better understanding of additive performances and more realistic WOC time for cementing compositions.Downhole Temperatures

Hole conditions and curing environments for cement slurries vary in temperature from below freezing in permafrost zones to 700° F (371° C) in geothermal steam

wells. The capabilities and versatility of most API cements can be extended by using additives. A blend of additives usually produces an optimum range of cement qualities.

Temperature studies conducted along the Gulf Coast of Texas and Louisiana in the early 1950s formed the basis of API testing schedules and cement specifications. The schedules are based on bottomhole temperatures: °F = 80° F + [0.015 x depth in feet]. The cooling effect of mud displacement lowers considerably the circulating temperature of the hole during casing cementing. During squeeze cementing, there is less cooling because there is less well fluid preceding the slurry. Thus, a cementing composition can be pumpable longer during casing cementing than during squeeze cementing at the same depth.

The bottomhole cementing temperature may be determined from logs and API temperature data. Log temperatures taken approximately 24 hours after the last circulation ended may be considered static for use in API Spec 10.

Slurry Volume

The amount of cement used in creating a slurry depends on the estimated total slurry volume. If a caliper log is available, an allowance of 10% above the volume calculated from the caliper information is generally acceptable. If volume from the bit size of the drilled hole must be used, allow from 50% to more than 100% above the volume calculated from the bit size. The excess-cement percentages of other wells in the area of interest can be used as a guideline.

In some areas, regulatory requirements dictate how far the top of the cement must be above the uppermost pay zone. Three hundred to five hundred feet of cement above the top of the pay is typical for many locations. This volume is contingent upon contact time — the time it takes for cement to flow past a given point in the annulus. The greater the contact time, the greater the chance of removing the drilling mud from the annulus. Only a specific part of the contact time should be considered in calculating slurry volume: when the cement is pumped at high velocity past the highest point in the annulus where good zonal isolation is needed. Any time spent displacing at a low rate just before bumping the top plug need not be included. Once we have an estimate of total slurry volume,we can easily determine our bulk dry cement requirements and water requirements along with the amounts of additives needed, by going to service company cementing tables.

Suppose for example, that we have calculated a slurry volume of 1,000 ft.3 of class 'G ' neat cement for a surface string of 10 3/4" casing in a 14 3/4"

hole. From the cementing tables (Halliburton, 1981) we know that 1 sack of class 'G ' cement yields 1.15 ft3 of slurry, and that this slurry requires 5.0n gal per sack of cement. Our cement and water requirements, therefore, are 870 sacks and 4,350 gals., respectively.

Depth

The first practical instruments for investigating the effect of pressure on cement thickening time were developed by R. F. Farris (1946). He indicated that the reduction in thickening time caused by the increase in pressure from atmospheric to 5000 psi averages about 35% for all cements. Pressure imposed on a cement slurry

by the hydrostatic load of well fluids also reduces the pumpability of cement. In deep wells, hydrostatic pressure plus surface pressure during placement can exceed 20,000 psi (137,900 kPa). Increased pressure seems to alter the forces of the contact surfaces of the water and cement, which accelerates hydration.

Strength to Support Axial Loads

Laboratory Tests

High axial loads may be imposed on the casing string and/or surrounding cement by landing and suspension methods and later operations. The cement strength required to support such axial casing loads has been determined through shear-bond tests ( Figure   1 , Lab test setups to measure casing-cement bonding characteristics).

Figure 1

The axial load which breaks the cement bond was measured and the ability of the cement to support axial casing loads was found to be proportional to the area of contact between cement and the casing. Therefore, "support coefficient," "shear bond," or "sliding resistance," as described by various investigators, is the load required to break the bond divided by the surface area between cement and pipe.

Based on worst-case results, Bearden and Lane provided a relationship for determining the support capability of a cement sheath, conservatively utilizing results for mud-wetted and nondisplaced conditions. Modifying their relationship to utilize compressive strength (assumed to be 10 times tensile strength), gives the formula (in conventional oilfield units),

F = 0.969 ScdH (1)

where:

F = force or load to break cement bond, lb

Sc = compressive strength, psi

d = outside diameter of casing, in.

H = height of cement column, ft

For example, for one bonded foot of 7-in. casing, using 500-psi compressive strength cement,

F = 0.969 x 500 x 7 x 1 = 3390 lb

Required Strength

The load to break the cement bond during hanging and drilling-out operations normally does not exceed the weight of the casing string (such as surface pipe) plus miscellaneous loads (such as weight on bit when drilling out the shoe joint).

Therefore, the load capacity noted above (3390 lb/ft [5045 kg/m] of cement column), provided by the relatively low compressive strength of 500 psi (3450 kPa), should be more than adequate to handle anticipated axial loads.

Cement composition normally can be formulated to rapidly develop adequate strength for casing landing loads. This allows drilling operations to proceed with little or no WOC time.

Also, low-strength filler cements, which are relatively inexpensive and of low density, and are less likely to induce lost circulation when high cement columns are required, may have adequate compressive strength to meet axial-load support requirements.

Needs for Zonal Isolation/Hydraulic Bonding

High Strength Needed

Although low-compressive-strength cement may be adequate to handle axial and rotational casing loads, ultimate high strength may be required for zone isolation and to support the borehole. Therefore, cement compositions should be selected that provide both adequate immediate compressive strength for drilling operations and adequate ultimate strength for production operations.

A comprehensive study of factors governing zone isolation under downhole conditions would be very complex. Therefore, only qualitative judgments have been attempted in studies to date, and these usually relate to the hydraulic bond that indicates adhesion between casing and cement or between cement and formation.

The actual relationship between hydraulic bond measured in the laboratory and downhole zone isolation has not been reported.

Bonding Tests

Various investigators have measured hydraulic bond. Test arrangements are shown in Figure   1 (Lab test setups to measure casing-cement bonding characteristics).

Pressure is applied to the exterior surface of the casing, causing the casing to become smaller in diameter and pull away from the cement, forming a microannulus that permits leakage. Results of the setup in Figure   1 are shown in Table 1, below.

  Type mud Hydraulic bond (psi)

Surface finish Wetting Water Gas

New mill-varnished None 200-250  

Varnish removed (chemical) None 300-400  

Varnish removed (sandblast) None 500-700 150

Varnish removed (sandblast) Fresh water 100 50

Varnish removed (sandblast) Invert oil emulsion

100 50

Varnish removed (sandblast) Oil base 100 50

Resin-sand coat (new, sandblast)

None 1,000-2,000

450

Resin-sand coat (new, sandblast)

Fresh water 100 55

Resin-sand coat (new, sandblast)

Invert oil emulsion

100 45

Resin-sand coat (new, sandblast)

Oil base 100 45

Cement: API Class A      

Water content: 5.2 gal/sk      

Curing temperature: 80° F      

Curing time: 24 hours      

Casing size: 2 in. inside 4 in.      

Table 1 : Hydraulic bond vs. casing surface and type of fluid wetting.

Surface condition Surface coating Hydraulic bond (psi)

Dry Mill varnish < 20

Mud film Mill varnish < 20

Dry Rusty 350-450

Mud film Rusty 20-50

Dry Acid-etched 250-400

Mud film Acid-etched 40-50

Dry Sandblasted 500-600

Mud film Sandblasted 50-60

Dry Epoxy-coated, 6-12 mesh sand

700-950

Mud film Epoxy-coated, 6-12 mesh sand

500-600

Curing time: 24 hours    

Curing temperature: 120° F

Table 2: Effect of mud film on bond strength.

Annular Devices Help

The pressure at which failure of the hydraulic bond occurred in the test can be increased by:

· preventing formation of the microannulus by controlling pressure differential across the casing as the cement sets, and/or;

· attaching seal rings of deformable rubber (similar to those available for field installation) to the exterior of the casing.

However, zone isolation is routinely obtained in the field at greater differential pressures than those causing failure in these hydraulic-bond tests. Therefore, such tests are probably not completely representative of downhole conditions.

Mud wetting and Ruff Cote

Further tests were conducted to more directly measure adhesion between cement and pipe. These tests showed an advantage to the resin-sand (Ruff Cote) exterior in the mud-wetted condition, which was not apparent in the previously discussed test (see Table 2, above). When resin-sand coatings are used downhole, however, their effectiveness should be increased by removing mud from the casing surface with preflushes ahead of the cement, and by cement scouring.

Casing with Ruff Cote should be well centralized to avoid the embedment of mudcake or shale into its roughened surface. This may not be possible in irregular, doglegged, or high-angle holes, or where mud is poorly conditioned.

One advantage of the resin-sand is that it inhibits formation of a microannulus under certain pressure and temperature conditions. This appears to be verified by cement bond logs.

Casing Support in the Borehole

The cement sheath can protect the casing against several types of downhole damage, including:

· deformation by perforating guns;

· formation movement, salt flows, etc.;

· bottom-joint loss on surface/intermediate strings during drilling.

However, added resistance to casing collapse for design purposes is questionable. In fault-slippage zones, doglegs, and certain sand-control failures, the cement sheath may contribute to problems.

Perforating - Expendable versus Carrier Guns

The cement sheath tends to minimize casing damage caused by expendable perforating charges. Expendable guns of nominal charge — for example, through-tubing guns — may be used in cemented pipe with little or no danger of serious casing damage. However, expendable charges may split casing collars that are unsupported by cement, and expendable gun charges of over 20 g frequently damage partially supported or unsupported casing.

Figure   2 (Cement sheath affects casing deformation by perforating with expendable guns ) (top) shows lab tests on casing deformation with 20-g charges and three cases representing no cement (top curve), 3/4-in.

Figure 2

(1.9-cm) sheath supported by thin steel (middle curve), and a strongly encased sheath (lower curve). Compressive strength of the cement in the sheath had little influence on results, as shown in the bottom figure.

Conventional hollow carrier, shaped-charge guns cause only slight casing deformation and essentially no damage regardless of support, because most forces from the exploding charges are contained by the carrier body.

Salt Flow

Casing damage can be caused by lateral loads resulting from flow of salt formations. Salt may flow in various ways, and it may not be economically practical to design casing for the most severe situations of nonuniform loading possible, such as the flattening effect illustrated in Figure   3 (No cement or partial sheath results in eccentric pipe loading )

Figure 3

and Figure   4 (With fault slippage, unconstrained pipe may minimize damage ).

Figure 4

However, when the annulus is completely filled with cement, casing is subject to a nearly uniform loading approximately equal to the overburden pressure. Although the modes of failure may differ, casing designs for withstanding salt pressure can be computed on the same basis as those for withstanding fluid pressure.

Casing failure caused by formation movement along natural or induced fault planes — as opposed to salt flow — is best handled by elimination of cement through the affected interval and perhaps by opening the hole to enable fault slippage to occur without loading the casing in shear ( Figure 3 and Figure 4 ).

Other downhole conditions, such as borehole doglegs and sand-control failures, also may cause casing damage similar to the types described above. Knowledge of the failure mechanism is essential to the selection of the failure-prevention method-i. e.., cement sheath or no cement sheath.

Adequate cement strength and good cementing and operational practices may be required to prevent parting or other failure in bottom joints of surface and intermediate casing strings.

Visual inspection of a joint failure reveals whether the casing is unscrewed or broken. Unscrewing occurs because of high-level torque impulses transmitted to the casing by the bit as it hangs up while drilling cement and cementing equipment out of the bottom joints. It can also be caused later by tool joint torque action on the lowermost joints as drilling proceeds ahead.

The problem is usually prevented by welding or by using thread-locking compounds on the connections of the lowermost two or three joints and controlling rotary speed. Other prudent cementing practices include the following:

· Apply standard good practices when cementing: e.g., maximize casing movement; use high-rate displacement, centralization, and proper washes and flushes.

· Around the shoe, use quality cement with early high-compressive strength.

· Use two plugs to prevent mud fill around the shoe joint, and do not overdisplace even if a top plug is used.

· Release pressure to avoid microannulus formation (if this is compatible with landing methods).

· Keep drill pipe out of the hole until the cement has adequate initial set. Minimum strength for drillout is 500 psi (possibly 1000 psi [6895 kPa]).

A lowered casing design safety factor in collapse (perhaps 0.85 versus 1.125) is sometimes considered for casing to be used below the cement top, on the assumption that cement will provide additional support. This is not a valid practice.

According to Cheatham and McEver, cement in the annulus between salt and casing is compressed by salt pressure, reducing stress transmitted to the casing. However, this reduction is less than 5% for 8 5/8-in. casing in a 12-in. hole, or about 200 psi (1380 kPa) for 6000 psi (41,370 kPa) acting on the cement. Furthermore, this load

reduction depends on uniform placement of cement, a condition not normally achieved.

Other tests suggest that a cement sheath may provide greater collapse-resistance support for lower-grade casing (H-40, J-55). However, minor radial or longitudinal discontinuities in the cement sheath eliminate this support.

Stage-Cementing Equipment and Methods

Multiple-stage cementing consists of conventional placement of cement slurry around the lower portion of a casing string followed by placement of successive upper stages through ports in a stage or port collar. Although most stage cementing is done in two stages, additional stages are possible.

Stage cementing may be appropriate:

· when a thick interval requires cementing and a weak formation will not support it

· when two or more widely separated intervals must be cemented

· in special cases (such as in arctic wells in permafrost) where cement is placed near surface to help suspend casing

· in deep, hot wells, to place faster-setting slurry above retarded compositions in lower, hotter zones

Various tools allow flexibility and variety of application.

Stage collars are most commonly used. The stage collar contains ports that are initially isolated by a sliding sleeve. The sleeve can be moved downward to open the ports — and moved up to close them — with a special bomb or tripping plug. Figure   1 (application of stage tools - displaced type method )

Figure 1

and Figure   2 (application of stage tools: free fall plug method )shows two types of collar-opening methods: displaced plugs and free-fall plugs.

Figure 2

Port collars can be opened or closed by mechanical action of an inner string, such as drillpipe. Two types of port collars are shown schematically in Figure   3 (two types of port collars opened and closed by pipe movement ); these are actuated by inner-string rotation or vertical manipulation.

Figure 3

The tools shown in Figure   3 are applicable to specialized jobs such as the placement of fluids behind pipe for corrosion protection or sand control, or cementing with treating packers.

Petal-Basket Packer

Mechanical devices are frequently used below stage tools to prevent upper-stage slurry from dropping through the mud. They may also be used below conventional shoes where casing is landed above the open hole.

The most common support device is the metal petal basket attached around the casing exterior. The basket allows vertical fluid movement but opens against the borehole to prevent downward movement. Strength and sealing ability limit its use to shallow depths.

A more rugged support device is the solid rubber or inflatable external casing packer. Typically, this is placed below the cement-outlet port and inflated with mud or cement prior to the opening of the cementing port ( Figure   4 , External packer supports cement column over a weak zone at shoe or for stage cementing).

Figure 4

Types of Casing

Conductor

The conductor pipe ( Figure 1 , conductor pipe) is the first string set in the well. It may be set by the rotary rig drilling the hole, or by a smaller rig (or rathole machine) before the larger rotary rig is moved in.

Figure 1

This casing string serves as a conduit to raise circulating fluid high enough to return it to the pit. Conductor casing also supports part of the well load where ground support is inadequate or where the well is going to be drilled to a great depth.

The purposes of conductor casing are:

to prevent washing out under a rig

to provide elevation for the flowline

to provide support for part of the wellhead

A blowout preventer (BOP) is not usually attached to the conductor casing.

Some characteristics of conductor casing and its placement are as follows:

Casing is usually large: 20 to 30 in. in diameter.

The hole for the casing may be severely eroded.

Casing can be easily pumped out, and is usually tied down.

Setting depth can vary from as little as 20 ft to as much as a few hundred feet.

The most common pipe and hole sizes are 16-in. pipe in a 20-in. hole, and 20-in. pipe in a 26-in. hole.

Recommended cements for use with conductor casing are: accelerated neat

ready-mix concrete

thixotropic cement

LCM additives

Typical slurries for conductor-casing application include API Class A, C, G, or H with 2% calcium chloride as the accelerator. Lost-circulation additives such as sand, gilsonite, and cellophane may be added without significant effect on the slurry-thickening time or compressive strength. Where lost circulation is severe, a thixotropic cement can be used.

The following is a brief summary of conductor-casing cementing practices:

The amount of cement used should be sufficient to provide returns to surface

The casing is often cemented through drillpipe with a sealing sleeve.

When cementing down casing, plugs may not be used; cement is simply placed.

Large-diameter (30-, 26-, and 20-in.) casing plugs are wooden body plugs. If bumped on baffle or float, care must be taken in pressuring up to prevent bypassing the plug with displacement fluid.

The amount of excess cement is usually determined by experience in the area of interest.

The following factors must be considered in the selection of the correct slurry composition for a conductor casing:

The set cement must have a compressive strength high enough to support an appreciable wellhead load; therefore, high-compressive-strength completion cements are best.

Since the temperature at shallow depth is usually only 80 or 90° F (27 or 32° C), the cement should be accelerated for a shorter thickening time and earlier compressive-strength development than is possible with neat cement. This early strength saves rig time and ensures sufficient strength to support continued drilling operations.

When the cement cannot be circulated back to surface, a top-out slurry is usually pumped into the annulus through small tubing on top of the primary cement.

Surface Casing

Surface casing ( Figure   1 , surface casing) is usually the second string of pipe set in the well. However, when a conductor casing is not set because the well is on firm ground or will not be drilled to great depth, the surface pipe is the first string set.

Figure 1

The purpose of surface casing is to

· protect freshwater sands, particularly underground sources of drinking water

· case unconsolidated formations

· provide primary pressure control (BOP is usually nippled up on surface casing)

· support future casings

· case-off potential lost-circulation zones

The casing head and other fittings used for completing the well are attached later.

Some characteristics of surface casing and its application are as follows:

· Casing sizes normally range from 7 5/8 in. on shallow wells to 20 in. on deep, multistring wells.

· The hole in which it is set may be severely eroded.

· Shallow strings can be easily pumped out.

· Drilling muds are often viscous, with little water-loss control.

· Casing may stick easily in unconsolidated formations.

· Loss of circulation may be a problem.

· Most areas require that cement be circulated.

· A guide shoe (or float shoe), float collar, scratchers, and centralizers are commonly used.

· Casing may be set from a few hundred feet to several thousand feet; the depth depends on the proposed total well depth, the competency of shallow formations encountered, and state regulations regarding protection of freshwater zones.

Recommended Cements

Shallow surface casing is cemented in the same manner as conductor casing. Completion cements with accelerated thickening times and compressive strengths are used. Top-out slurries are used on surface jobs when cement is not circulated back to surface.

For deeper strings of surface casing, a lightweight lead cement is used, followed by heavier-weight completion cement. Sometimes, when zones are penetrated by long surface casings, a lightweight lead cement may help keep these formations from breaking down under the hydrostatic pressure exerted by a long column of cement. The bottom of the surface casing around the shoe is cemented with the high-strength completion cement.

This creates a strong seal with the pipe and formation for solid support of the casing.

There is a cost advantage to using a high-yield completion slurry to cement the entire string. When the well is shallow and a significant load is to be placed on the wellhead, a densified filler slurry can be used to cement the entire casing. Omission of the tail-in slurry is not economically advantageous.

Recommended cement types include:

· The amount of cement used should be sufficient to provide returns to surface. This is a regulatory requirement in many locations.

· filler cements (with a high water content) followed by neat or high-strength tail-in

· accelerated cements

· LCM additives

· high-strength cements, which are often used on deep-well surface casing to support future strings

The following is a brief summary of surface-casing cementing practices:

· Large-diameter strings are often cemented through drillpipe with a sealing sleeve.

· Both bottom and top plugs should be used to prevent mud contamination.

· The bottom joints and thread lock should be centralized to prevent backing off during drilling.

· Regulator rules usually require WOC of 8 hours, or 500 psi minimum compressive strength.

During displacement with mud, a float collar placed two joints above the guide shoe helps prevent mud from contaminating the cement around the shoe joint. Scratchers and centralizers are the final consideration of casing equipment. Scratchers are sometimes used to help clean the mud from the formation face. Centralizers center the casing in the hole to help place the cement completely around the pipe.

A top and a bottom plug should be used to wipe the pipe clean ahead of the cement when mud is the drilling fluid. If only a top plug is used, the mud wiped off the casing builds up behind the cement and contaminates the cement around the shoe.

Intermediate Casing

The intermediate casing ( Figure   1 .,intermediate casing) is the first string of pipe set after the surface casing.

Figure 1

It is sometimes called the protection casing. Intermediate casing strings extend from the surface to a formation able to hold the mud weights expected at greater depth. This depth can vary by several thousand feet in a single-stage job. When a second intermediate string is set, the casing is run to just below the weak zone to a competent formation and is cemented at that point.

The purpose of intermediate casing is to

· separate the hole into workable increments for drilling

· case-off lost-circulation zones, water flows, etc.

· isolate salt sections

· protect the open hole from increases in mud weight

· prevent flow from high-pressure zones if mud weight must be reduced

· control pressure; the BOP is always installed

· support subsequent casings

· Some characteristics of intermediate casing and its application are the following:

· Pipe and hole sizes are determined largely by the number of casing strings to be run below the intermediate string.

· Casing sizes range from 6 5/8 in. to 20 in. Most common are 9 5/8 in. 10 3/4 in., and 13 3/8 in.

· Some sections — particularly salt sections — may erode severely.

· Strings may be very heavy and set on bottom.

· Both extremely weak zones and high-pressure zones are covered by intermediate strings.

· Cement volume is dictated by wellbore condition.

· A guide shoe (or float shoe) and float collar are commonly used.

· Cement volumes are usually largest in the well.

· Intermediate casing is often cemented in stages.

· Prolonged drilling may be done through this casing, and damage is common.

· Completion may be made in intermediate casing.

Recommended Cements

Because of the large volume of cement required, and the types of formation to be covered, both filler and composition cements are used to cement most intermediate casing. Sometimes, as many as three different slurries are needed. Formation-fracture gradients, lost-circulation zones, formation temperatures, possible future producing zones, and well depth determine the number and types of slurries to use.

The slurry requirements for a single-stage cementing job are similar to those for a long surface job. The filler slurry needs to be light enough not to break down the weaker formations. The completion slurry needs to have enough strength to hold the pipe and provide a good seal between the pipe and the formation.

The bottom of the pipe is cemented (usually at 100 to 3000 ft) in a single-stage intermediate job because of cost considerations, or because the uncemented sections of casing may be reclaimed from the well later and reused. In the latter case, only a high-strength completion slurry with a retarder is needed. Retarders ensure sufficient pumping time to get the slurries in place, and also impart some friction-reducing properties to the slurry.

Unlike the conductor and surface casings, additives such as friction reducers, fluid-loss additives, and retarders are required for intermediate slurries. Where the annulus is small, friction reducers lower pump pressures and reduce the chance of losing fluids in a lost-circulation zone. Fluid-loss additives prevent slurry loss into lost-

circulation zones and dehydration in the annulus caused by permeable zones, and also give better bonding results.

The following is a brief summary of intermediate-casing cementing practices:

· Both bottom and top plugs should be used to minimize contamination of the cement.

· Stage tools are used occasionally in cementing long strings of pipe where there is risk of breaking down a weak formation.

· The number of slurries required may be determined by possible production, weak zones, and wellbore temperatures.

· Scratchers, centralizers, and flushes can be important in the successful completion of an intermediate-casing cementing job.

Production Casing

The production casing ( Figure   1 , production casing) is the last full string of pipe set in the well, and extends to the surface.

Figure 1

Production tubing, downhole pumps, and other equipment needed for the production of oil and gas are housed in this casing. The production-casing cement must give a pressure-tight seal between the formations and the production casing. It is essential to isolate the reservoir from fluids both within the producing zone itself and from other zones penetrated by the wellbore. These fluids (e.g., oil, water, gas) can create emulsions, scale deposits, paraffin deposits, severe corrosion, and a decline in production. Besides primary producing operations, remedial workover jobs such as squeezes or chemical treatments are also run through the production string.

The purpose of production casing is to

· complete the well for production

· effect zonal isolation

· protect pay zones from unwanted fluids

· provide pressure control

· cover worn or damaged intermediate casing

Since the production casing may extend from total depth to surface, the setting depth can vary from a few thousand feet to as much as 14,000 ft (4270 m). Below 14,000 ft, liners may be set to reduce cost and because less pipe weight is needed. The size of the casing depends on the number of strings of production tubing to be run into the well and the size of production equipment used.

The following are some characteristics of production casing and its application:

· Common casing sizes are 4 1/2 in., 5 1/2 in., and 7 in.

· Drilling mud is usually in good condition.

· The cement job is usually not circulated, but cemented back to intermediate casing depth.

· A good cement job is vital to a successful completion.

To achieve a pressure-tight seal and protect the reservoir, special consideration must be given to the production-casing cement properties. As with intermediate casing and long surface pipe, both filler and completion cement are usually employed. The filler cement needs good fluid-loss control. It must have enough compressive strength to protect upper, potentially productive zones which might be completed in the future. The completion slurry needs to have good fluid control and sufficient compressive strength to hold the weight of the pipe and to bond the formation to the pipe. The setting times of both slurries should be minimized to help prevent cement contamination from formation fluids and formation contamination by cement filtrate.

Recommended types of cement are

· filler cements with high-strength tail-in

· low-water-ratio cements (for all potential pay zones)

· densified cements (for high competency and pressure control)

· fluid-loss control additives

Summary of Production Casing

Batch mixing or continuous batch mixing is recommended for all large or critical jobs. Since the production string affects the success of the well more than any other casing, a good job may mean the difference between success and failure of the well.

Efficient removal of the mud is essential. Spacers or flushes may be used to remove mud and to water-wet the pipe and formation face for good cement bonding. Usually casing reciprocation or rotation is used. A float shoe and float collar, centralizers, scratchers, and pipe movement should be used.

Liner Cementing

A liner is a string of casing that does not extend up to the wellhead. It is used to case-off the open hole below an existing casing string.

Several types of liners may be categorized by their function:

Drilling liners permit deeper drilling operations by isolating lost circulation or highly pressured intervals and controlling sloughing or plastic formation. In lieu of full-length casing, the drilling liner improves drilling hydraulics, i.e., the greater cross section above the liner top enables the use of larger drillpipe and/or reduces annular pressure drop.

Production liners provide isolation and support functions when casing has been landed above the producing interval.

A tie-back stub liner extends from the top of a liner to a point uphole, inside another string of casing or liner. The stub liner is used to cover damaged or worn casing above an existing liner, and to provide added protection against corrosion and/or pressure.

Tie-back casing extends a liner to the wellhead. It is used primarily for the same purposes as the tie-back liner. Running such a string at the end of a drilling operation ensures that the completion will be run in unworn casing.

Figure 1 (Example of deep-well tubulars, liner/tieback application ) shows the tubular program of a modern deep well using two liners and tie-back casing.

Figure 1

Cementing Procedures

Cementing procedure is illustrated in Figure 2 ,

Figure 2

Figure 3 ,

Figure 3

Figure 4 , and Figure 5 (Typical liner cement procedure).

Figure 4

With the liner hung in the casing but still attached to the drillpipe, slurry is pumped into the drillpipe without a bottom wiper plug.

Figure 5

The cement is followed by a drillpipe wiper plug that latches into a liner wiper plug, positioned below the liner hanger. The combination plug then wipes the liner clean and finally latches into a landing collar to complete slurry placement.

The following are important details in cementing procedure:

With the liner in position, mud is circulated to ensure that the liner and the float equipment are free of any foreign material, and to condition the mud. A clean mud system is important so that materials will not fall out on top of the liner-running assembly during the cement job.

The cement can be batch-mixed, circulated through a holding tank or ribbon blender, and/or double-pumped to obtain the desired cement-slurry properties.

Cement slurry should be pumped in turbulent flow, or as fast as possible, refer to the heading titled "Fluid Flow Properties and Mud Displacement". Such flow minimizes excess cement-volume requirements. Most operators prefer to limit excess cement volume, which, of course, is pumped into the drillpipecasing annulus. It is usually desirable to pump some type of spacer fluid (buffer) ahead of the cement.

If no bottom plug is used, the drillpipe and liner plugs wipe mud film off the ID of the drillpipe and liner. This mud collects below the plugs and can contaminate cement in the bottom of the liner. Spacing between landing

collar and float shoe should be adequate to keep contaminated cement out of the liner-openhole annulus.

With cement in place, it is standard procedure to pull the liner-setting assembly out of the liner hanger. With the tailpipe of the liner-setting assembly above the liner top, excess cement can be reversed out. However, reverse circulation places an extra pressure on the annulus that must be controlled to prevent formation breakdown. A liner packer keeps reverse-circulation pressures off the formation.

One method is to pull the drillpipe all the way out of the hole and leave cement inside the casing to be drilled out. WOC time depends on cement composition and hole conditions.

Liner-Cementing Equipment

A liner is usually run on drillpipe that extends from the liner-setting tool to surface. Special tools perform various running, setting, and cementing operations ( Figure   1 , Typical equipment used to install and cement liners).

Figure 1

Shoes/Collars

A float shoe placed at the bottom of the liner contains a check valve designed to prevent backflow of the cement. A float collar can be run above the shoe to provide a back-up check valve. Automatic fill-up-type float equipment may be selected, but it is rarely run on liners.

A landing collar is usually run one joint above the float collar or two or more joints above the float shoe to provide space for mud-contaminated cement inside the liner. The collar's function is to latch and seal the liner wiper plug. It prevents the liner wiper plug from moving uphole if a check valve fails, and prevents it from rotating, which aids drillout.

Liner wiper plugs can be attached to the end of the tailpipe or slick joint with a shear-pin arrangement. The selection of the proper shear rating is very important in the prevention of premature shearing and release of the liner wiper plug.

The liner wiper plug can also be latched to the tailpipe to prevent premature shearing. Release of this type can only be effected by engagement of the drillpipe water plug.

Hangers and Setting Tools

The liner hanger is installed at the top of the liner. Hangers are usually classified by the method used to wedge slips against the casing wall; two such classifications are mechanical and hydraulic.

The presence of slips between liner and casing reduces the bypass area for circulating. This reduced area can create high-pressure loss during circulation and cementing. Hangers are available with multiple split slips that increase bypass area and provide increased slip-contact area.

The liner-setting tool, a rental item furnished by the liner service company, provides the connection between drillpipe and liner. Swab cups attached to tailpipe, or a packoff bushing and slick joint, are inserted into the liner to provide a seal between setting tool and liner.

Once the liner is hung, the setting tool can be released and picked up a short distance to confirm, by indicator weight loss, that the setting tool has separated. A new retrievable packoff bushing eliminates bushing drillout.

Liner packers can be installed at the top of liners to seal between liner and casing, after cement placement. Seal elements may be rubber or lead, or a combination of the two. They may be run as an integral part of the liner hanger and set by manipulation of the liner-running tool. However, this type of packer should be considered only if clearance is such that the hole can be circulated at desired rates without increasing back-pressure excessively.

Special packers can be set in conjunction with a tie-back sleeve after cementing and cleanout operations have been completed. These packers seal both in the tie-back sleeve and against the suspending casing.

External casing packers have been used on liners to isolate between zones in open hole. They are inflated following cement displacement before the cements set up to provide more effective zone isolation.

Setting on Bottom

Except in unusual cases where buckling is not expected or can be prevented through centralization, liners to be cemented should be suspended from slips set in existing casing, or the drilling liner. However, equipment is available for the special application in which liners are cemented and set on bottom.

A special float shoe can be run on the bottom of the liner with an extra internal left-hand thread. First the liner is run into the well and hung from surface slips. Then the cementing string is run and engaged into the thread at the shoe. The liner is run to bottom on the cementing string, and the cement job is completed. The inner string is disconnected from the shoe by rotating to the right.

Typical Problems in Deep, Hot Wells

Liner cementing is a major problem in deep wells for the following reasons:

Tight Holes. As seen in Table 1 (below), liner-to-borehole clearances can be very small. This is a highly undesirable situation that frequently results from poor planning, misguided economics in selecting well tubular/bit programs, or unforeseen downhole conditions. Small clearances require flush joint liners that approach drill-collar size. Key seats and collar-worn grooves cause differential sticking and prevent effective mud removal by cement

Liners, in. Hole, in. Casing, in. Cement sheath thickness, in.

9 5/8 10 5/8 11 3/4 1/2

7 3/4 9 1/2 10 3/4 7/8

7 5/8 9 1/2 10 3/4 15/16

7 3/4 8 1/2 9 5/8 3/8

7 5/8 8 1/2 9 5/8 13/16

5 1/2 6 1/2 7 5/8 1/2

5 6 1/2 7 5/8 3/4

5 6 1/8 7 9/16

4 1/2 6 1/8 7 13/16

3 1/2 4 3/4 5 5/8

Table 1: Typical liner/casing and hole size combination. Long Intervals, Mud Cake. In West Texas, liner lengths may be 2500 to 11,000 ft (762 to 3350 m); they average 8000 ft (2440 m). High temperature and prolonged exposure

causes mud to gel excessively. Shale instability in long geopressured sections causes hole irregularities. Mud is difficult to remove from enlarged sections.

Temperature Differential Top to Bottom. As shown in Figure 1 (Long West Texas drilling liner has high temperature differential over its length), static geothermal temperature may vary as much as 1200 F over the length of a long liner.

Figure 1

Cement composition and setup time must be compatible with this gradient. Yet, circulating temperatures may be radically different, actually causing maximum temperatures to occur perhaps 2000 ft (610 m) uphole for nearly an hour after circulating.

Gas Cutting, Liner Top Leakage. Premature cement setup uphole by high temperature or filtrate leakoff to long permeable zones can reduce hydrostatic pressure and allow gas to permeate the partially cured column. The resulting channels are too small to effectively squeeze cement, but they continue to channel gas to liner tops. Two compositions that minimize problems are (1) fluid-loss additive spotted across upper zones and (2) retarder that keeps

slurry fluid, then sets up rapidly, rather than thickening gradually. Special compressible cement that maintains its volume during setting to prevent gas leakage and thixotropic cementing compositions are also available.

Special Primary Cementing Methods

Inner-String Cementing

Cementing large-diameter casing requires some special considerations. Such casing is subject to being pumped out of the hole. This occurs when pump or hydrostatic pressure acting on the cementing-head area and on the bottom of the hole through the shoe opening provides an upward force exceeding the buoyed weight of the casing. Pressure increase on bumping a plug is, of course, offset, and does not contribute to the problem.

Large casing can also be floated out of the hole if the weight of the casing and the mud in the pipe do not exceed the buoyancy provided by the annular column of cement. The possibility of casing collapse must also be considered. Heavy mud may be required to prevent these occurrences.

Inner-string or stab-in cementing is now a fairly common practice for large-diameter casing. The string is cemented through drillpipe stuck into a special sealing sleeve in the shoe ( Figure 1 , stab-in cementing technique for large-diameter casing).

Figure 1

Small-diameter plugs can be used. The drillpipe can be raised from the seal and the excess cement reversed back.

In geothermal wells where no voids can be tolerated outside the casing because of later heating and boiling problems, slurry can be continuously pumped until good circulation to surface is established. Conventional methods, conversely, pump a calculated volume that is difficult to determine in surface holes without the use of caliper logs.

Various adaptations are possible using cup packers, etc. with stab-in methods. Port collars can be opened or closed, and external packers can be inflated to permit stage cementing of long, large-diameter pipe.

External Cement-Filled Packer

Extra-long (20- or 40-ft) elastomer-sheath covered inflatable packers can be run as part of the casing string. One packer (or more) is landed across the productive zone to be perforated and the primary job is completed conventionally.

When initial slurry displacement is complete and the top plug is bumped, increased pressure opens shear-pin controlled valves in the packers and additional cement is pumped into the packer elements to expand them tightly against the borehole wall. Inflation cement is pumped down the casing between the first top wiper plug and a second top wiper plug.

After curing, the cement-filled packer and the casing joint mandrel on which it is run are perforated by conventional methods. Inflation cement transport and the completed production system are illustrated in Figure 1 (Inflatable external cement-filled packers during running and after perforating ).

Figure 1

Two cement-filled packers can be used effectively to straddle a productive interval for zone isolation.

External cement-filled packers offer several advantages in primary cementing:

Complete mud channel removal is ensured by the application of high internal pressure to the end-reinforced element, to squeeze mud from the rubber-formation interface.

A quality pipe/cement bond is ensured by the use of uncontaminated cement, mud-free pipe, and pressure setting. Interzonal flow and the need for squeezing may be eliminated.

Producing zones are supported by the pressure-set cement and will not dilate or flow when fluid inflow causes a pressure differential.

Without conventional slurry circulation first, cement may be placed solely in the packers, and thus not contact water-sensitive zones.

System limitations include the following:

Long elastomer-covered packers are durable in properly conditioned holes but are inherently sensitive to restricted-clearance holes and problem holes with casing burrs, broken centralizer pieces, nontapered liner shoulders, etc.

Reliable supply and pumping methods are required to prevent long delays or job interruptions that may complicate inflation-procedure control after protective knock-off plugs are removed by the bottom wiper plug.

ECD completions may prove less flexible for long-term production adjustments than conventionally cemented wells.

Factors That Affect Primary Cementing

Hole Conditions

Sloughing

In many cases, this is the reason for setting an intermediate casing. Sloughing can create several cementing problems: bridging the annulus, sticking the casing, and increasing the annular hydrostatic pressure.

Drill pipe Drag

The cause and location of the drag could be very significant. Drag may indicate the need for centralized casing or fluid-loss control cements.

Low-Pressure Zone

One of the most persistent problems is an incompetent formation that will not support effective columns of cements. This most commonly occurs in intervals covered by surface and intermediate casing.

Mud Condition

A well-conditioned mud greatly increases the mud-removal capability of flushes and cement slurries.

Fluid Movement

Zone isolation fails any time fluid movement is allowed to occur in a cement slurry before it is completely set. If the cement moves during the hardening process, it will not set properly.

Formation Movement

The most common formation movement occurs with salt intrusions.

Mud-Contamination Effects

The possibility of mixing cement and mud always exists during pumping and displacement. Such contamination can result in

accelerated or retarded thickening times

reduced compressive strength

reduced bond strength

increased filtrate loss (higher than in either mud or cement)

severe thickening (with oil-base mud)

Table 1 (below) shows typical mud additives and their effects on cement.

Inorganic chemicals have an erratic effect on oilwell cements, but generally tend to accelerate thickening times. Organic chemicals generally retard, and may completely inhibit thickening in some instances.

Severe thickening occurs with oil muds in cement mixing because these muds are thickened by water-wet solids that are readily available in the high-solids-content cement. The problem is most serious when mud and cement slurry densities are high. Also, oil-emulsion muds often contain calcium chloride in the water phase, which can accelerate setting.  

Additive Purpose Effect on cement

Barium sulfate (BsSo4) Weighing agent Increases density  Reduces strength

Caustic (NaOH, Na2Co3, etc. pH adjustment Acceleration

Calcium compounds Conditioning Acceleration

CaO, Ca(OH)2, CaCl2, CaSO4 and 2H2O

pH control  

Hydrocarbons (diesel oil,  Fluid-loss control, Decreases density

lease crude oil) lubrication  

Sealants (scrap, cellulose, rubber, etc.)

Seal against leakage to formation

Retardation

Thinners, (tannins, lignosulfonates,quebracho, lignins, etc

Disperse mud solids Retardation

Emulsifiers lingnosulfonates, alkyl ethylene oxide adducts hydrocarbon sulfonates)

Form oil-in-water or water-in-oil muds

Retardation

Bactericides (substituted phenols, formaldehyde, etc.)

Protect organic additives against bacterial decomposition

Retardation

Fluid -loss control additives, CMC,starch, guar, Ployacrylamides Lignosulfonate

Reduce fluid loss from mud to formation

Retardation

Table 1: Effects of mud additives on cement.

Mud-Contamination Prevention

To prevent mud/slurry problems, it is best to minimize contact. The bottom wiper plug prevents contamination in the casing, and a spacer fluid reduces cement/mud contact in the annulus.

Two bottom plugs may be required — one preceding, and one behind the spacer fluid — to prevent mud/cement contact if contamination is likely to create serious problems, and the spacer fluid does not by itself strip the mud film from the casing bore.

A single bottom plug, ahead of the cement, removes the film and accumulated mud ahead of the plug and behind the spacer fluid. This accumulated mud can then contaminate the cement ( Figure 1.

Figure 1.

, The lack of bottom wiper cases mud accumulation below top plug).

A variety of spacer or preflush fluids are available, including water, brine, solutions of acid phosphates, diesel oil (weighted or unweighted), oil-base fluids, and emulsions (oil in water, water in oil).

Compatibility of both spacer and mud, and spacer and cement should be verified on every cement job. Selection of the amount and type of spacer depends on the type of mud and on potential reaction problems between the cement and the mud.

A water flush, normally in turbulent flow, may aid mud-displacement efficiency. Salt water has less tendency to cause shales to swell or slough. However, fresh water, salt water, or fluids containing dispersing surfactant should not immediately precede a high-density cement slurry; this can cause thinning and weight material settling

Casing

The following are general rules for casing preparation and application:

Tally all pipe; count, number, and rabbit (gauge) all casing joints on the pipe rack.

Check all casing threads for cleanliness and damage. Additionally, check the threads on all crossover equipment for proper thread type and cleanliness.

Identify all joints by weight and thread type, and place them in proper order for running into the hole.

Landing joints should be spaced out so the cementing head can be installed from the stabbing board or rig floor after the casing is landed.

Floating Equipment

The floating equipment (float collars and float or guide shoes) must be on location and in good working condition. Check operational features if differential floating equipment is used. Measure and prepare stage and floating cementing equipment separately. Use thread-locking compound or tack weld (if necessary) on all field makeup connections between the floating equipment, plus one or two joints above.

Running Casing

The following are general rules for running casing:

Use of a movable stabbing board can minimize downtime.

A safety valve is advised for long production casing strings or suitable pressure rating.

Control running speed of casing to prevent fracturing and lost circulation.

Circulating Time

The importance of circulation before cementing is recognized by all operators, but there are considerable differences of opinion regarding optimum circulating time.

Many believe that because the number of variables affecting the success or failure of a cement job is so great, it does not seem possible to correlate the degree of success with the amount of time spent in precementing circulation.

The following are circulation guidelines:

Condition the drilling mud with good rates up to anticipated cementing rates.

High circulation rates remove gel led mud that develops during static periods because of temperature and fluid loss.

Begin pipe movement and mud conditioning immediately after the casing is on bottom.

Apply scratching technique when wall cake and cuttings in the mud returns have either virtually stopped or declined rapidly in volume.

The casing moves at the start of circulation and continues throughout the circulation period. With reciprocating scratchers, the pipe is commonly moved through a 20-ft stroke, with a 2-min interval for the cycle. If rotating scratchers are used, the pipe is rotated as slowly as possible, usually between 10 and 20 rpm.

Cementing Composition, Volume, and Slurry Weight

In primary cementing, the cement slurry should have a viscosity that will give the most efficient mud displacement and still permit a good bond between the formation and the pipe. The following are some cementing guidelines.

Determine the maximum allowable downhole density to prevent fracturing. The density of cement should be at least 1 lb/gal (preferably 2 or 3 lb/gal) heavier than the drilling mud.

Design fluid loss using differential pressure of 1000 psi. To prevent gas channeling, design on 20 cc/30 min or less.

Design cement slurry to be displaced in turbulent flow for a minimum of 10 to 20 min contact time at the top of the pay zone, if possible.

For slurries to be placed across salt formations, use saturated sodium chloride.

Use 35% silica at static temperatures above 230° F (110° C).

Control free water to 1% or less for normal slurries. To prevent gas channeling, control free water to zero.

Determine cement-slurry thickening time at bottomhole cementing temperature and pressure. Minimum thickening time should be job time plus one hour of thickening time to a consistency of 50 Bc. (Bearden Units of slurry consistency are dimensionless units formerly called "poises.") Minimum

thickening time is the time required to mix the slurry, and pump it down the hole and up the annulus behind the pipe.

Important Tips

Use top and bottom wiper plugs, and inspect the plugs before loading. The bottom (hollow) plug is loaded first, then the top (solid) plug. Do not slit the diaphragm of the bottom plug with a knife before loading.

Use a two-plug cementing head:

Displace the top plug out of the cementing head without shutting down operations. Do not open the cementing head to drop the top plug or a vacuum will be created and the well will take in air.

Pump preflush or spacer ahead of the bottom plug. If you use two bottom plugs, put the first bottom plug in first, then the preflush or spacer, and then place the second bottom plug just before the cement.

Before mixing, check calibration of all density devices with fresh water for proper calibration.

Hook up bulk tanks to the cement mixer. The rate of delivery of cement to mixer should be sufficient to maintain pump rate in the annulus at the design rate.

Batch mix all cement slurries by using a ribbon or batch blender. This operation is extremely important for good control of slurry properties.

A bottom plug is not recommended for use with slurry containing large amounts of lost-circulation material or with badly rusted or scaled casing. Such material may collect on the ruptured diaphragm, bridge the casing, and thus prevent total displacement.

Personnel

The supervisor and the person on the pump throttle should understand the importance of the pumping rate to the success of a job. They both need to know:

why variations in cement density should be held to close limits

control parameters, so they will not be easily satisfied with less control

how to change over from pumping to displacement in 15 seconds, rather than 2 minutes

Maintain a log of operations that includes time, density measurements, mixing rate and displacement rate, wellhead pressure, operation in progress, volume of fluid pumped, etc. Record pump speed (strokes per minute) and total strokes. Insist on a properly operating pressure-recording chart from the operator.

Make sure that all service personnel involved are given ample notice of commencement of casing operations, so they can be available and rigged up before this time.

For the following items, prepare and record data on the appropriate company casing cementing report as required:

Determine the elapsed time and volume or strokes required for the cement slurry to leave the casing shoe after the start of displacement; to reach the pressure equalization point after the start of displacement; and to displace the top plug to bump float. Note that when a stage-cementing collar is used, the above calculations should be made for both phases of the cementing operation.

Determine the theoretical weight of the casing in 1000-ft intervals. When differential fillup equipment is used, use all available literature regarding percent fillup and record the weight at 1000-ft (305-m) intervals during casing descent.

Determine the number of barrels or pump strokes needed to displace the pipe after the casing is landed and to circulate one full hole volume, and the number of barrels of mud required to displace the cement.

Estimate the rate of cement mixing and displacement, plus annular velocities.

Squeeze Cementing

Squeeze Cementing

Squeeze cementing is the process of forcing a cement slurry through holes in the casing. Its primary objective is to create a seal in the casing-wellbore annulus. The basic components and concept of squeezing are illustrated in Figure   1 .

Figure 1

(concept of cement squeezing ).

The most common purposes for squeeze cementing are:

· repair of a primary cement job that failed because of cement bypassing mud (channeling) or insufficient cement height (fillup) in the annulus

· elimination of water intrusion from above, below, or within the hydrocarbon-producing zone — commonly called "block squeezing"

· reduction of the producing gas/oil ratio by isolating gas zones from adjacent oil intervals

· repair of casing leaks caused by corrosion or split pipe

· plugging of all or part of one or more zones in a multizone injection well to direct injection into desired intervals

· plugging and abandonment of a depleted or watered-out producing zone

Basic Concepts and Misconceptions

There have been persistent misconceptions about squeeze cementing, including the following:

Cement squeezed through holes (perforations) in casing under high pressure generally forms a horizontal cement pancake opposite the holes, thereby developing a barrier to vertical fluid movement.

Injecting drilling mud into perforations at high pressure opens all perforations.

High final squeeze is a positive indication of a successful job.

In zones with good permeability, cement penetrates the formation without fracturing.

These have been disproved by field experience.

Filter Cake

A cement slurry consists of finely divided solid particles dispersed in liquid. Such particles cannot be displaced into normal formation permeability, since a permeability greater than 100 darcies would be required to allow a normal slurry to penetrate a sand formation without fracturing.

Therefore, when slurry is forced against a permeable formation, solid particles filter out on the formation face as filtrate is forced into the formation permeability. The filter cake has much lower permeability than most sand formations and, as cake forms on part of the formation, slurry may be diverted to other exposed zones.

A properly designed squeeze job causes dehydrated cement to fill the opening(s) between formation and casing and, if allowed to cure, the dehydrated filter cake will form a nearly impermeable solid.

In cases where slurry is to be placed in a fractured interval (either natural or induced), cement solids have to develop a cake on the fracture faces and/or bridge the fracture.

Most successful squeezes in fractured formations have used a staging technique in which a highly accelerated slurry, or a slurry with bridging agents such as gilsonite or sand, is followed by a second stage of moderate fluid-loss slurry. This system encourages bridging and filter-cake development and helps divert movable slurry to unsealed fractures.

Fluid Loss

If fluid loss is uncontrolled, cement may dehydrate and bridge off the upper portion of a perforated interval before slurry is displaced to the lower perforations. Conversely, very low fluid loss can result in very slow filter-cake development and unacceptably long placement operations.

Slurry-fluid (filtrate) loss can be varied and controlled with cement additives as required over the wide range of temperature and pressure conditions normally encountered in oil and gas wells.

In formations with unimpaired natural permeability, slurry with a water-to-solids ratio of 0.4 (by weight) and a low fluid loss of 50 to 150 cc in 30 minutes under 1000 psi differential should provide satisfactory caking for most low-pressure squeeze jobs.

When squeezing against shales, dense limestones, dolomites — or permeable formations where natural permeability is plugged with mud — a low-fluid-loss cement may not be desirable. In these situations, a high-pressure squeeze job is usually performed, and low-fluid-loss slurry could be undesirable because its restricted filtrate loss could inhibit filter-cake development.

High-Pressure Methods

High-pressure squeeze cementing is defined as a job in which fluid pressure in the wellbore exceeds formation-fracture pressure prior to, or during, the time that cement slurry is in contact with the formation.

High-pressure methods are recommended only for squeezing relatively impermeable zones, or where squeezing is conducted with drilling mud in the hole.

Fracturing of the formation permits displacement of mud or workover fluid through holes in the casing. The slurry then displaces this fluid into the fractures, permitting development of cement filter cake on the fracture surfaces.

Potential Problems

High-pressure squeezes offer no control of either the location or orientation of the generated fracture. The fracture will be oriented perpendicular to the least principal stress

Horizontal fractures will not be created if fracture pressure is less than overburden pressure. Thus, horizontal fractures containing cement pancakes cannot be generated by high-pressure squeeze cementing in deep wells.

Fracturing during high-pressure squeezing may be counterproductive, since fractures induced in formations deeper than 3000 ft are nearly always vertical. Even if the casing-wellbore annulus is sealed, vertical communication between zones may be established in the fracture ( Figure 1 , probable result of fracture-type squeeze-cement job).

Figure 1

Other problems are

large slurry volumes required to fill fractures: 100 to 150 sacks may be lost in a job

resistance of mud-filled perforations to fracturing: many may not readily receive cement

Recommendations

Generally, it is recommended that solids-free workover fluids be used whenever fluid has to be displaced into the formation ahead of cement. Acid or chemical washes can also be used ahead of the slurry.

Low-Pressure Methods

Low-pressure squeeze cementing jobs are those in which fluid pressure in the wellbore is maintained below fracture pressure of exposed formations prior to, and during, the time slurry is in contact with the formation.

Low-pressure squeeze cementing methods we generally preferred to high--pressure squeezes, because they are more effective and less potentially damaging to the formation.

In practice, safe squeeze pressure is usually specified as some value below established fracture pressure — 300 psi has been used in some areas.

Low-pressure squeeze cementing utilizes a small volume of low-fluid-loss slurry placed against exposed permeable formations with a moderate squeeze pressure. Filtrate from the slurry is forced into formation permeability, allowing buildup of cement filter cake. Low fluid loss reduces dehydration rate and discourages bridging as the slurry is forced along openings or channels.

A properly designed slurry will leave only a small cement filter-cake bump

(node) inside the casing after excess slurry has been circulated out. Improperly designed slurries can result in excessive caking with enlarged nodes, or inadequate caking and inability to hold pressure ( Figure 1 , cement filter-cake node buildup after 45-minute squeeze).

Figure 1

The casing can be left with cement nodes small enough that drilling-out is not required. Also, the ability to reverse-out excess cement in many applications makes low-pressure squeezing compatible with through-tubing techniques.

Field Practices

In low-pressure squeezes, perforations and channels must be clear of mud and other solids. If the well has been on production, such openings may have been purged. If the job is to be performed through new perforations, results may be enhanced by perforating in a solids-free, nondamaging fluid with pressure underbalanced to permit purging of perforation cavities. In existing perforations, pressure/ suction washing with or without acid may be considered.

Summary

In practice, the following steps may be used as a guideline for conducting a low-pressure squeeze job:

Initiate injection. Determine downhole injection pressure.

Circulate slurry to desired location in the casing.

Apply moderate squeeze (downhole) pressure.

Restore squeeze pressure by engaging the pump as bleed-off occurs.

Gradually increase downhole pressure to 500 to 1000 psi above the pressure required to initiate flow. When bleed-off ceases for about 30 minutes, stop displacing cement slurry and hold the pressure. Do not exceed safe squeeze pressure.

Reverse-circulate excess cement from casing, or pull work string leaving cement to be drilled out later, if necessary.

Squeeze Techniques

Hesitation Techniques

The most important principle of hesitation techniques is the alternation of pumping and hesitation. The hesitation is to encourage cement filter-cake buildup. Hesitation methods can be used in either high- or low-pressure applications.

Hesitation procedures are much more of an art than a science, since the operator observes hesitation time and pressure changes during pumping and waiting, and varies these on subsequent jobs, according to experience. The alternation of pumping and hesitation is continued until the desired final squeeze pressure is obtained ( Figure 1 , example pressure response to hesitation-type cement squeezing).

Figure 1

Final squeeze pressure may be misleading. Years ago, high final squeeze pressure was one primary indicator used to measure success. However, high final pressure may occur because dehydrated cement has bridged off the casing or perforations; and mud-cake-filled perforations are also capable or withstanding high differential pressure, particularly in the direction of the formation. Thus, high final squeeze pressures can be achieved where the squeeze was unsuccessful.

Bradenhead versus Packer Methods

The Bradenhead squeeze technique is normally used on low-pressure formations. Usually, the interval to be squeezed is at or near the bottom of the well. The operational steps of the general procedure ( Figure 2 , Bradenhead squeeze method applicable to competent casing strings) are as follows:

Circulate cement across the zone to be squeezed.

Figure 2

Pull drillpipe (or tubing) above cement.

Close BOPs or annulus valve and apply pressure to cement through drillpipe.

Reverse out excess or WOC and drill out.

Squeeze pressure is limited by casing-string and wellhead-burst strength, so the technique is usually used with a low-pressure squeeze. It is not a precise cement-placement technique, and is not generally recommended with several open intervals and only one to be squeezed, or where casing is not pressure-tight.

Packer-squeeze techniques permit precise slurry placement and isolate high pressure from casing and wellhead while high squeeze pressures are applied downhole. A packer squeeze can be conducted with either drillable or retrievable squeeze packers.

Wellbore fluid below the packer is usually displaced through perforations ahead of the cement when this method is used. Dirty fluid may block flow of cement to a portion of any exposed permeability. Figure 3 (cement squeeze using retrievable packer and bridge plug ), is one example of the many tool configurations possible

with packer squeezing.

Figure 3

Packer location should be carefully considered and may vary depending on the type of job. If set too far above perforations or holes to be squeezed, excessive volumes of either workover fluids or mud must be displaced into the formation ahead of the cement, or the slurry may channel through the mud ( Figure 4 , possible problems caused by setting squeeze packer too high).

Figure 4

Conversely, a packer set too close to perforations or holes could become stuck if pressure on the outside of the casing is transmitted above the packer and causes the casing to collapse.

Usually, the packer should be set 30 to 60 ft (9.14 to 18.28 m) from perforations. If corrosion holes or split pipe are being squeezed, more space is recommended.

It is desirable to test and then maintain some pressure on the casing annulus above the packer. Observation of this pressure can be a check for leaks in squeeze string, packer, or casing. Annulus pressure can also prevent casing-collapse pressure during high-pressure jobs.

Squeeze cementing in permanent and tubingless completions requires some special precautions, but basic techniques are similar to those used in conventional wells, and normally only low-pressure jobs are attempted.

A permanent completion is one in which tubing and welihead remain in place during well life. Squeeze cementing can be performed with concentric small-diameter tubing. Through-tubing tools such as inflatable bridge plugs and packers can be run

on wireline or small-diameter tubing strings to permit conventional but small-scale operations.

Squeezing through small tubing uses very small slurry volumes which are susceptible to contamination. Maintaining accurate volume control is particularly important in ensuring proper slurry placement.

Job Evaluation

Proof of a successful squeeze comes when we apply pressure to the set cement. It is best to test the squeeze job before removing the rig, just in case the test fails and re-squeezing becomes necessary.

Squeeze jobs are most commonly tested by applying pressure from the rig or cementing unit pumps. A better way to test the squeeze however, is to create a pressure differential in the wellbore by swabbing, by artificially lifting fluid from the well, or y circulating a lighter fluid down the tubing and closing the circulation ports above the packer. The pressure differential should be less than or equal to the expected drawdown pressure under producing conditions.

In some production wells, it may be impractical to unload the wellbore without returning the well to production. In these cases, a positive pressure test that does not exceed formation-fracture pressure should be conducted after cement has set and, if required, after drillout.

In squeeze jobs where cement is to be drilled out, the way the cement drills is an indication of success. If it drills hard all the way, results may be good. Soft spots or voids usually indicate an unsuccessful job.

Cement Plugs

Reasons for Setting

By far the most common application of cement plugs - particularly in mature areas - is well abandonment.

Some other reasons for setting plugs are:

to cure lost circulation during drilling

for directional drilling and sidetracking (or whipstocking)

to provide zone isolation

to provide a seat for openhole test tools

Abandonment

To seal off a dry hole or depleted well, cement plugs are placed at required depths ( Figure 1 , Cement plugs for abandonment).

Figure 1

These plugs prevent zone communication and any fluid migration that might infiltrate underground freshwater sources or cause undesirable surface conditions. Well plugging regulations are driven to a large extent, by requirements relating to the protection of underground sources of drinking water. Most states, fro example, require a bottom plug, a plug across casing stubs, spacer plugs, and perhaps remedial squeezes at abandonment.

Lost-Circulation Control

If drilling-fluid circulation is lost during drilling, it can sometimes be restored by spotting a cement plug across the lost-circulation zone ( Figure 2 , Cement plug for lost circulation control) and later drilling back through the plug.

Figure 2

Directional Drilling and Sidetracking

To sidetrack a hole around unrecoverable junk or for an undesirable direction or poor structural position, a cement plug is placed at a specific depth. This plug helps support the whipstock for directing the bit into the desired area ( Figure 3 , Cement plug for directional drilling and sidetracking).

Figure 3

Zone Isolation

In a well with two or more producing zones, it is sometimes beneficial to abandon a depleted or unprofitable producing zone by placing a cement plug above it ( Figure 4 , Cement plug for zone isolation). This plug prevents possible production loss into, or fluid migration from, the lower interval.

Figure 4

Formation Testing

A cement plug is sometimes placed below a zone to be tested that is a considerable distance from total depth ( Figure 5 , Cement plug for formation testing). This plug is necessary when a straddle packer with sidewall anchor or bridge plug is not possible or practical.

Figure 5

Job Design

Cement plugging consists of placing a cement column in open or cased hole. Although this sounds relatively simple, many problems may be encountered during the plugging operation. Major difficulties include fluid migration, cement contamination, and poor cement-slurry design.

Nevertheless, cement-plug failures may be minimized by:

using a caliper log to determine hole gauge

carefully determining cement, water, and displacement volumes, and always planning to use more than enough cement

using spacer or preflush ahead of and behind the cement column to minimize contamination

rotating drillpipe/tubing and using centralizers and scratchers while placing cement

placing plugs with care, and moving pipe slowly out of cement to minimize contamination

using diverter tools and viscous pill spacers

In addition to the precautions listed above, there are several other important factors to consider in designing for a cement plug: slurry composition and volume, government regulations, placement technique, and well conditioning.

Cement volume needed for a specific plugging operation depends on plug length and hole diameter. Government regulations may also dictate plug length for well abandonment. For sidetracking, 200 to 300 ft is generally required to minimize drilling-fluid contamination that occurs at the plug top. Moreover, allowances are usually made for dressing off drilling-fluid-contaminated cement before attempting to sidetrack.

Fluid spacers should be used both ahead of and behind cement slurry to minimize mixing of cement and drilling fluid. Also, spotting a viscous pill spacer at the intended plug bottom can improve cement-plug stability. Use of a diverter tool, which forces fluid to flow directly at the wellbore face, provides for a more uniform placement of spacer, viscous pill spacer and cement slurry. A diverter-tool application to the balanced method placement technique is illustrated by these cement plugs: Figure 1 (Idealized case ),

Figure 1

Figure 2 (Experimental results ) and Figure 3 (Recommended technique ).

Figure 2

Figure 3

Cement-Slurry Design

Cement-slurry design is closely related to objectives of the plug and also depends on well depth, BHCT, and drilling-fluid properties. Some key design considerations are

rheology

density and compressive strength

thickening time and WOC time

For lost-circulation plugs, slurry density should be controlled to reduce bulk slurry loss. Bentonite and silicate extenders are useful slurry-density-reduction additives, and they lower ultimate cement compressive strength. Gilsonite, a granular hydrocarbon, is also a lightweight cement additive used in lost-circulation plugs. Low compressive strength is desirable in a lost-circulation cement plug because sidetracking is more likely to occur off a high-compressive-strength plug. Thixotropic cement slurries are also used as lost-circulation cement plugs. Self-supporting properties of these slurries help prevent total cement loss into the lost-circulation zone.

A sidetracking or whipstock plug is set to enable a new hole to be drilled away from the original hole. Since the success of a whipstock plug depends to a large extent on high compressive strength, use of a densified cement (API Class A, G, or H) is recommended. Densified cements:

provide high strength

tolerate drilling-fluid contamination

expand upon setting

decrease fluid loss

have negligible permeability when set

provide strong bonding

Drilling-fluid contamination is always possible when placing an openhole cement plug. When drilling fluid commingles with cement slurry, slurry retardation as well as dilution of the cement plug can occur. The effect of drilling-fluid contamination on two different density slurries is shown in Table 1 (below).

Because of the properties listed above, densified or reduced-water-ratio cements generally produce more successful results. Table 2 (below) shows typical compressive strengths of densified Class G and H cements used for setting sidetracking cement plugs.

Additives such as calcium chloride, dispersant, or retarder can be used in densified slurries. However, because slurries with dispersants have lower consistency and viscosity, the amount of dispersant should be kept to a minimum for better plug stability. Laboratory testing for maximum viscosity, ample thickening time, and compressive strength should be performed before each job.

Some operators using whipstock plugs claim that higher compressive strengths and better success ratios are achieved when 10 to 20% sand and/or silica flour are included in the cement composition. A possible explanation of this phenomenon is that sand may improve drilling-fluid removal by its scouring action, and thus may reduce drilling-fluid contamination. Therefore, sand and/or silica flour may affect compressive strength in a way unrelated to silica/cement reaction.

To further reduce mud contamination, it is advisable to pump a spacer fluid ahead of and behind the cement. The density of the spacer fluid should be equal to or greater than that of the drilling fluid. It is important to note that because of the density difference between mud and cement. The cement will tend to migrate downward in the well. This is another reason for including a preflush in the plugging treatment.  

Drilling-Fluid contamination (%)

Compressive strength (psi) at 230o F for 12 hours

  15.6 lb./gal slurry 17.4 lb./gal *

0 2,910 7,010

10 2,530 5,005

30 1,400 2,910

60 340 2,315

* contains dispersant Table 1: Effect of drilling-fluid contamination on cement compressive strength.  

Slurry weight        

(lb./gal) 100° F 140° F 170° F 200° F

  1,600 psi 3,000 psi 3,000 psi 3,000 psi

After 12 hours        

16.5 2,075 4,000 7,800 9,035

17.0 2,850 6,535 8,375 10,025

17.5 3,975 6,585 8,550 10,675

After 24 hours        

16.5 5,475 8,985 9,750 10,460

17.0 6,035 9,060 11,075 12,660

17.5 7,025 10,125 11,860 12,875

Table 2: Typical compressive strengths of API Class G and H cements at API curing conditions.

Mixing

A poorly mixed cement slurry may lead to cement-plug failure, so a high-quality slurry should be prepared. Because of the small cement volumes associated with plug cementing, the slurry should be batch mixed or mixed through a ribbon blender, if possible. These methods lead to a very uniform cement slurry. Should either of these mixing techniques be impractical, the cement should be mixed at a rate that will ensure uniform slurry density.

Placement Techniques

There are three basic techniques for placing cement plugs: the balanced method, the dump-bailer method, and the two-plug method.

The Balanced Method

The balanced method involves pumping cement slurry down the drillpipe or tubing until the level of cement outside the workstring is equal to that inside. The workstring is then pulled slowly from the slurry, leaving the plug in place. No special equipment is required for plug placement other than a cementing service unit.

For this method to succeed, the drilling fluid or other well-bore fluid must circulate freely. It is also important that the well be static, neither gaining nor losing returns, while the cement plug is being placed or is setting. Density differences between drilling fluid and cement slurry should be minimized if possible. Otherwise, a viscous pill spacer and a cement plug should be spotted through a diverter tool. The viscous pill spacer may be prepared from either bentonite (25 to 30 lb./bbl [71.325 to 85.6 kg/m3] total to a portion of the existing drilling fluid) or downhole intermixing of 20% calcium chloride and sodium silicate.

The height of the balanced cement column may be calculated by

H = Vc/(Va + Vt)where (in oilfield units):

H = height of balanced cement column (ft)

Vc = volume of cement slurry (bbl)

Va = volume per foot of annulus (bbl/ft)

Vt = volume per foot of workstring (bbl/ft)

For example, determine the volume of cement slurry required to set a 500-ft cement plug at 8000 ft in 7-in., 26-lb./ft casing. The workstring is 2 7/8-in. 8.6-lb./ft tubing with an ID of 2.259 in.

The required volume of cement slurry for such a job is 19.1 bbl:

Vc = (500 ft)(0.0382 bbl/ft) = 19.1 bbl

Va = 0.0302 bbl/ft

Vt = 0.00496 bbl/ft

Therefore, H = (19.1 bbl)/(0.0302 bbl/ft + 0.00496 bbl/ft) = 543 ft

Displacement fluid volume is 37 bbl: (8000 ft - 543 ft) (0.00496 bbl/ft) = 37 bbl

The Dump-Bailer Method

The dump-bailer method ( Figure 1 , cement plug- dump-bailer method placement) is usually used in low-pressure, cased holes at shallow depths. Under these conditions, drilling fluid is not normally required, since the well can be controlled with produced brines.

Figure 1

Unless the well is to be plugged from total depth, a bridge plug is normally placed at the base of the intended cement plug. Cement slurry is then lowered in a dump bailer on a wireline. The bailer is opened by touching the bridge plug, and the slurry is then dumped by raising the bailer.

Two advantages of the dump-bailer method are lower cost and easy control of cement-plug depth. However, it is not readily adaptable to deep wells, contamination with drilling fluid is possible, and the slurry quantity is limited to the dump-bailer volume.

The Two-Plug Method

The two-plug method ( Figure 2 , cement plug - two-plug method placement), which uses a plug-catcher-type tool, offers a means of cement plug placement with less likelihood of overdisplacement and contamination. Cement plug top is also easily established.

Figure 2

The tool consists of a bottomhole sub installed at the bottom of the workstring, aluminum tailpipe, bottom wiper plug (which carries a dart), and top wiper plug. The bottom plug is pumped ahead of the cement slurry to its seat. It cleans the drillpipe and isolates cement from drilling fluid. A shear pin connecting the dart to the plug is broken by increased pump pressure and pumped down through the aluminum tailpipe. The top plug is pumped behind the cement to isolate cement slurry from displacement fluid. Another increase in surface pressure indicates when the plug has arrived at its seat. Drillpipe is pulled up until the lower end of the tailpipe is at the calculated depth for the cement plug top. (Should the aluminum tailpipe get stuck in cement, an increase in pull will break the tailpipe and free the drillpipe.) The shear pin between the catcher sub body and sleeve is then broken, allowing the sleeve to slide down and open reverse-circulation ports.

Some advantages of the two-plug method are:

it provides isolation ahead of and behind the slurry

the pipe is cleaned to the bottom of the tailpipe

breakable tailpipe can be readily abandoned if stuck

reverse-circulation is accomplished through the bottom of the tailpipe

it allows accurate placement of the cement plug

it shows positive surface indications

Additional Planning

Regardless of the method, if a cement plug is to be set near the bottom of the wellbore, sand or gravel can be used to fill the hole to the desired depth. This approach may be very useful for plugging back to recomplete a higher zone, or for cement plugs that will be drilled out at a later date.

When drillpipe is used to place a cement plug, centralizers and rotating scratchers may be placed on the lower end of the workstring to help minimize drilling-fluid contamination. Scratcher rotation cleans drilling fluid from the wellbore, promoting better bonding, and allows bypassed drilling fluid to mix uniformly with the cement slurry. This procedure helps eliminate mud channels in the unset cement.

Testing Cement Plugs

After placing the plug and waiting on cement, the first step in testing the plug is to 'tag' the top of the cement with the drill pipe or tubing. This step is very important, because the actual top of cement is different from that at which the plug was placed. The usual test for a cement plug is a performance test. For example, if a cement plug has been drilled for lost circulation and full returns are observed during further drilling, the operation is considered to be successful.

It is important to allow adequate setting time before tagging a cement plug. Normal WOC time ranges from 12 to 36 hours. However, by using a densified cement or an accelerator, this time may be reduced to between 8 and 18 hours. When the BHST is above 230° F, 35% silica flour in the cement composition produces a high-strength, low-permeability cement plug after a minimum placement time.

Operations may resume following primary cementing after the cement has a compressive strength of approximately 500 psi (3447 kPa). But, when sidetracking, cement-plug compressive strength must be substantially higher before the plug is kicked off. In general, for a successful sidetrack, the cement plug must be harder than the formation. Past experience in a given location should give an indication of the compressive requirement for a whipstock plug.

Failure of Cement Plugs

Depending on the purpose of a cement plug, failure can occur for the following reasons:

· lack of adequate compressive strength (sidetracking)

· poor isolation (plug back, abandonment)

· wrong depth (all plugs)

· the plug is not in place because— it has sunk to the bottom (all plugs)— it has been lost to a thief zone (lost circulation)

Reasons for failure can be traced to the following:

· inadequate compressive-strength slurry design

· insufficient WOC time

· inaccurate BHST

· drilling-fluid contamination during cement displacement and POH

· cement slurry not designed for the specific problem

· inadequate cement volume

· too great a difference between cement slurry and well-fluid densities

· improper placement technique

Evaluating/Testing the Cement Job

Evaluating/Testing Primary Cementing

Evaluation of a primary cement job can determine the existence of one or more of these potential problems:

failure of the cement to fill the casing-borehole annulus to minimum acceptable height failure to provide a seal at the casing shoe, or at the top of a liner failure to provide effective isolation of the zone(s) of interest

If any of these failures is detected, squeeze cementing remedial operations are usually required.

Common evaluation techniques include:

temperature surveys radioactive tracer logs cement bond logging pressure/inflow tests production testing, production logging

Temperature Logs and Acoustic Bond Logs

Temperature Logs

Temperature surveys are used to detect maximum height of cement in the casing-wellbore annulus. Although reasonably accurate in this application, such surveys cannot measure cement quality or its effectiveness in preventing vertical fluid migration.

The method consists of running a recording thermometer in the casing after the cementing operation. Setting cement generates "heat of hydration," which increases the temperature of adjacent fluid in the casing by several degrees ( Figure 1 , idealized temperature logs in homogeneous lithologies).

Maximum temperature anomalies may range from 10 to 40° F (-12 to 5° C). The magnitude depends on the thickness of the cement behind the casing, as well as the thermal diffusivity of the surrounding formation. Where lithology is fairly uniform, the temperature log indicates relative thickness of the cement behind the casing. Caliper surveys can be particularly helpful in analyzing the temperature survey.

To locate the cement top, the survey should begin either at surface or at least 1000 ft (305 m) above where the top is expected to be. The survey should be run at 5° F/in. (6° C/cm) sensitivity under normal conditions. Well conditions must remain static from the time the plug is bumped until the survey is completed.

The rate at which temperature changes depends on the temperature to which the cement is exposed. This is usually a function of the depth of the cement job ( Figure 2 , cement-temperature rise as a function of depth and temperature of environment ).

Figure 2

Temperatures often peak 4 to 12 hours after the start of mixing, and remain elevated for more than 24 hours. Therefore, temperature surveys should be run between 8 and 24 hours after the cement is mixed.

Addition of radioactive tracer material to the lead portion of the cement slurry provides a positive indicator of the cement top. Either long or short half-life material can be used. Several radioactive materials used as tracers have half-lives of 8 to 80 days.

Principal drawbacks of radioactive tracers include possible health hazards, interference with natural radioactive surveys, and high cost.

Acoustic Bond Logs

Sonic signals from acoustic cement bond logs are transmitted to a receiver that is acoustically isolated within a combination tool. In traversing through casing, signal amplitude is attenuated to varying degrees, depending on the material outside the casing. Attenuation effect is greater if that material is solid and bonded to the casing.

Signal amplitude is converted to electronic signals and varies inversely with degree of attenuation. Thus, a high-amplitude casing signal indicates that there is no bond between cement and casing ( Figure   1 , cement-bond log signature and variable-density comparison).

Figure 1

When cement is firmly bonded to casing and formation, there is a low casing signal, and the signal received is characteristic of formation behind pipe. When cement is bonded to pipe but not formation, both casing and formation signals have low amplitude ( Figure   1 ).

An example bond log is shown in Figure   2 (example response of amplitude and acoustic signature tracks).

Figure 2

This example illustrates a half-wave signature in the right column, which is an oscillograph picture of amplitudes shown schematically in the previous figure. Other logs may display the acoustic signature log in the right column as a variable density log ( Figure   1 ).

CBL interpretation has been a subject of controversy ever since the tools first appeared in the early 1960's Lack of industry standards for tools and procedures, inadequate information on log headings, miscalibration of tools, lack of effective tool centering and poor running procedures have all fueled this controversy. Proper recognition of the tool's characteristics, however, and an understanding of how hole characteristics affect them, can help greatly in obtaining a valid log. Properly run and interpreted, the CBL has been found to provide correctly more than 90% of the time. (Pilkington, 1992).

Downhole conditions that can cause errors in acoustic CBL interpretation (and recommended preventive measures) follow:

· The extent to which the cement is set (hardness) affects sonic signal velocity and amplitude. As cement hardens, acoustic transmittability increases and casing signal is dampened out. Therefore, it is best to run CBLs at least 24 to 36 hours after the job, or when compressive strength reaches 1000 psi (6894 kPa).

· Cement composition affects acoustic transmission. If a high degree of sensitivity is applied where low-density cementing materials have been used, poor bonding may be indicated although good bonding actually exists. Conversely, tests indicate that small sections void of cement can only be located by high sensitivity. Therefore, voids or channels may not always be indicated on CBLs unless the proper sensitivity is selected with respect to cement composition.

· Cement-sheath thickness may vary, causing changes in attenuation rate. Lab tests indicate that a thickness of 3/4 in. (2 cm) or more is required to achieve full attenuation.

· Cement compressive strength and the percent of casing circumference that is bonded affect CBL amplitude. It is not possible to determine the difference between a job in which cement strength is lower than anticipated, and one in which cement strength is as estimated but small mud channels exist. Vertical zone isolation does not exist in the latter case.

· A microannulus is a very small gap between casing and cement. This gap would affect the CBL presentation although the presence of a microannulus does not usually prevent isolation between zones, and it usually heals with time. Running the CBL under pressure can help eliminate the microannulus.

Attenuation Rate Tools: Attenuation rate tools, unlike acoustic CBL's are not affected by fluid travel time. These tools measure amplitude at two receivers located 1 ft. Apart, and then calculate a compensated attention rate. The quantity measured is the acoustic signal as it travels down the 1 ft. Of casing in the well. High attenuation rates generally reflect a good pip-to-cement bond. Attenuation logs share some of the same limitations as CBL, including microannulus problems and the need to carefully center the tool in the well.

Circumferential Bond Logs: These tools are designed to survey the complete circumference of the casing, and to detect smaller channels that can be found using an acoustic CBL. Circumferential tools include multi-pad attenuation-type tools, as well as tools that employ rotating pulse-echo transducers.

Inflow Tests and Production Testing/Logging

Water Shutoff

Pressure tests are conducted to verify integrity of the casing following primary cement jobs. Government regulations specify procedures in most locations. The casing-pressure test is conducted after cement has set but prior to drilling out the cement shoe. These tests are not an indication of cement effectiveness.

In some locations, regulations require that the casing be perforated and tested by either bailing or inflow evaluation tests, called water shut-off tests. In California, the tests provide assurance that a cement seal of the annulus exists, to protect shallower freshwater reservoirs.

Perforating and checking the rate and content of inflow have been used to verify a cement seal above or below hydrocarbon-producing zones in many areas. The

advantage of this technique is that if a failure is indicated, a cement squeeze of the holes will be opposite a nonproductive formation.

Casing Seat Test After Drillout

When casing is cemented in an impermeable formation where additional drilling is to be conducted, the casing shoe can be drilled out and the casing seat inflow tested. The amount of open hole to be drilled below casing is specified by law in some locations, but is usually 5 to 10 ft (1.5 to 3.0 m). Tests can be made with a conventional tester set near bottom.

A pressure test can also be conducted after drilling out the casing shoe and 5 to 10 ft of open hole. Two objectives of this procedure are to (1) test the effectiveness of the cement seal at the casing shoe and (2) determine the formation strength (fracture gradient) of the shoe.

Liner-Top Testing

Pressure testing the overlap to check the seal at the top of the liner prior is usually preferable to cleaning out the float collar or float shoe. If the liner is not sealed, a cement squeeze is most easily applied at this time. The overlap pressure tests may use applied internal pressure to create a differential toward the formation.

Where high formation pressures exist, low-density fluid inside the liner may provide sufficient differential toward the borehole to indicate leakage. High differential could be ensured by using a drillstem test (DST) tool. Such differential pressure should be equal to or greater than the maximum differential expected during future drilling or production operations.

Production Testing/Production Logging

The most positive evaluation of cement effectiveness has been obtained by production testing and production logging methods used after completion. These methods include one or more of the following techniques:

production tests for flow rate and content (water, oil, gas, and solids, if any)

inflow evaluation by determination of flow rates and content versus surface flowing pressures

evaluation of historical production data, and comparison between wells with common completions (production surveillance)

pressure buildup and fall-off measurements with downhole pressure recorders

inflow versus depth measurements with downhole flowmeters

flowing and/or static temperature versus depth measurements with high-resolution surface-recording thermometers

flowing fluid density versus depth measurements

downhole fluid samples

radioactive fluid injection and surveys to identify injection points and possible presence of migration channels behind casing

noise logging to detect behind-casing fluid movement

Generally, a combination of production tests and production logging procedures are required to identify and locate channels or other problems associated with lack of effective zone isolation.

Documentation/Trouble-Shooting

Primary cementing has been called the critical period of drilling and completion operations. There is universal agreement that effective primary cementing is a critical requirement for effective completions.

Perhaps the most important primary-cementing procedure is accurate and detailed documentation of casing running and cementing operations. This information is invaluable for evaluating cement jobs, and is essential for the development of improved equipment and procedures.

Fluid Flow Properties & Mud Displacement

Introduction: Fluid Flow Types

The character of flowing fluid is described by the relationship between flow rate (shear rate) and pressure (shear stress) that caused the movement.

There are two basic fluid types: Newtonian and non-Newtonian. Newtonian fluids, such as water, exhibit a straight-line relationship between flow rate (shear rate) and pressure (shear stress) while the fluid is in laminar flow. They begin to flow when pressure is applied. As pressure increases, flow velocity increases from laminar, through a transition zone (part laminar, part turbulent), to fully developed turbulent ( Figure   1 , flow regimes and velocity profile for water-type fluids)

Figure 1

Drilling muds and oilwell-cement slurries are non-Newtonian. These fluids are more complex; they may exhibit resistance to flow (gel strength) when pressure is applied. Fluids with gel strength can flow at very low rates in a solid or pluglike manner. Such fluids thus have three flow regimes — plug, laminar, and turbulent — with transition zones between each ( Figure   2 , flow regimes and velocity profile for cement).

Figure 2

Extensive study has resulted in the development of mathematical models that can be used to predict flow properties and pressure-velocity relationships of such muds and cements. The Bingham plastic model and the Power law model are most commonly used. The former has been used for drilling-fluid analysis since the mid-1940s. Power law model equations presented in the late 1950s are generally considered to be more accurate than those of the Bingham model.

These models attempt to describe the relationship of shear and shear stress for muds and slurries. Although very useful in analyzing the displacement process, they are not precise techniques. They should be used to determine flow regime and pressure requirements for displacement, but results should be considered more qualitative than quantitative — i.e., if analysis indicates a potential displacement problem, believe it; if it shows acceptable displacement conditions, attempt to enhance displacement anyway.

Flow Properties of Wellbore Fluids and Mud Displacement

Slurry Preparation

The procedure outlined here helps determine two slurry properties: flow behavior index (n') and consistency index (K'). These factors then allow estimation of frictional

pressure loss and prediction of flow velocity for turbulence or plug flow for non-Newtonian fluids. It is also advantageous to have n' and K' values for drilling mud in the hole. When a sample of the mud is available, these data can be determined by the same viscometer procedure used for cement slurries. When plastic viscosity and yield point are available, the values can be converted to their equivalent n' and K' values.

Because of the thixotropic, or gelling, tendency of many brands of cement, it is important that slurry-mixing methods be standardized so that reproducible data can be obtained. It should also be recognized that many additives used in cement exhibit time-temperature dependency characteristics somewhat different from those of conventional slurries such as neat cement and gel cement.

Since the advent of friction-reducing cement additives, and with the increased application of turbulent flow, a modification of slow-speed mixing may be desirable. Because emphasis in turbulent flow cementing should be placed on annular conditions and properties of the slurry in the annulus, it is generally preferable to use Steps 2b or 2c, rather than 2a (shown below):

1. Mix the slurry initially for 35 seconds in a Waring blender by the method described in API Spec 10.

2.

a. To produce a slurry similar to that existing on the discharge of the displacing pump, immediately transfer the slurry to a Halliburton consistometer for a 5-minute period of slow-speed mixing at 80° F (27° C), then proceed to Step 3.

b. To simulate average displacement conditions that influence time-temperature dependency, transfer the slurry to a Halliburton consistometer for a 20-minute period of slow-speed mixing at 100° F (38° C), then proceed to Step 3. This procedure is most commonly used for slurries containing fluid-loss additives, cement-friction reducers, and other additives when specific well conditions are not known.

c. To simulate specific well conditions and determine the flow properties n' and K' at the time of slurry entrance into the annulus, transfer the slurry either to a Halliburton consistometer or the pressure-temperature consistometer for a period of slow-speed mixing under a time-temperature schedule duplicating that expected during placement of the slurry. In this case, the time is that required for the first sack of cement to reach the bottom of the casing, and the temperature should be the bottomhole circulating temperature.  

3. Pour the slurry from the consistometer slurry container into a Fann V-G Meter cup with a minimum time lag prior to starting the Fann instrument. Although the slow-speed mixing period has taken the slurry past its rapid initial gel, gelling tendencies of a lesser order still exist and may result in variations in data if the slurry were allowed to remain in the static state between operations. Under conditions in 2c (above) it may be desirable to have the Fann cup, rotor, and bob at an elevated temperature.

Filling the Fann Apparatus

The slurry to be tested should be poured into the sample cup to the line etched inside the cup. With the rotor turning at 600 RPM, the cup containing the slurry should be raised until the liquid level is at the designated level on the rotor (indicated by an etched line). The instrument should be run at 600 RPM during this operation to ensure filling of the annular space between the rotor and bob with the slurry.

Shear Tests

Dial readings should be observed at 600, 300, 200, and 100 RPM, and in that order only. The initial reading at 600 RPM should be taken 60 seconds after the sample cup has been raised into proper position. The rotor speed should be shifted to the succeeding lower speeds at 20-second intervals, and each dial reading taken just before shifting to the next-lower speed.

Interpretation of Data

The following graphs or calculations should be made to obtain n' and K' in conventional oilfield units.

The flow curve is prepared by plotting on logarithmic coordinate paper, as ordinate (Y axis)

shear stress (lb. force/sq. ft) =  (8-1)

where N is the range extension factor of the torque spring.

As abscissa (X axis), rate of shear (Sec-1) may be determined from the following table:  

Speed (RPM) Rate of Shear (Sec-1)

600 1022

300 511

200 341

100 170

When all four data points do not form a straight-line flow curve, the best straight line through these values should be drawn and extrapolated to the shear stress axis. A sample plot is shown in Figure 1 (flow curve for non-Newtonian fluid ).

Figure 1

The flow behavior index (n') may be determined as follows:

n' (dimensionless) = slope of flow curveThe consistency index (K') may be determined as follows:

K' (lb.-sec'/ft.2) = intercept of flow curve at unity rate of shearThe slope of the flow curve, n' can be calculated from two points on the plotted line, but it is necessary to use logarithms of the points since the data were plotted on logarithmic coordinates. The equation below can be used by substituting for the 600 and 300 RPM readings the actual shear stress from the plot for any two points where the ratio of shear rates is 2.

If only the field model of the Fann viscometer is available (rather than Model 35), the 600 RPM and 300 RPM readings are the only ones that can be made and the following formulas can be used to calculate n' and K':

(8-2)

(8-3)

For calculations where plastic viscosity and yield point are known:

(8-4)

(8-5) where:

PV = plastic viscosity, cp

YP = yield point, lbf /l00 ft2

* The multiplier, 1.066, to be used if PV and UP are obtained from dial readings of Fann V-G Meter.

For Newtonian fluids, n' = 1.0, and

(8-6)

Figure 2 (classical Reynolds number friction factor correlation for Newtonian fluids flowing in turbulence in circular conduits ) is the classical Reynolds number-friction factor correlation for Newtonian fluids flowing in the turbulence in circular conduits.

Figure 2

This correlation is presented for comparison of Newtonian data with the non-Newtonian behavior of the fluids described in Figure 3 (correlation shown in Fig.

Figure 3

2, presented for comparison of Newtonian data with the non-Newtonian behavior of fluids)and Figure 4 (correlation shown in Fig 2,

Figure 4

presented for comparison of Newtonian data with the non-Newtonian behavior of fluids ) These figures were prepared from experimental pressure-drop measurements taken while cement slurries were pumped through the indicated pipe sizes. The data may be expected to differ from similar data obtained using other slurries or geometries. The solid curve in these figures describes the equations commonly used for pressure-drop calculations and allows a visual comparison of actual data with predicted values.

The Reynolds number transition limits shown in Table 1 (below) were obtained by procedures designed to minimize the effects of fluid time and energy dependency, as well as the effect of flow-system geometry, since the laminar flow parameters n' and K' do not adequately predict these limits. However, the experimentally derived turbulent flow parameters used for this analysis require such complex equipment that it has been impractical to obtain such data on all the cement-slurry variations that might be encountered in practice. The data points shown in Figure 3 and Figure 4 indicate the deviations encountered, since these points were calculated from experimental data.  

Figure no. Slurry Type Reynolds number transition limits

8.3 Neat API Class A cement

1800-2500

8.4 12% gel cement 2400-3500

Table 1: Reynolds number transition limits.

Formulas for Making Calculations (in Conventional Oilfield Units)

Displacement Velocity

(8-7)

where:

V = velocity, ft/s Qb = pumping rate, bbl/min Qc f = pumping rate, ft3/min D = inside diameter of pipe, in.

For the annulus: D2 = DO

2 - DI2

where:

DO = outer pipe inside diameter (or hole size), in. DI = inner pipe outside diameter, in.

Reynolds Number

(8-8)

where:

NRe = Reynolds number, dimensionless V = velocity, ft/s   = slurry density, lb/gal n' = flow behavior index, dimensionless K' = consistency index, lb-sn'/ft2 D = inside diameter of pipe, in.

For the annulus: D = DO - DI

Frictional Pressure Drop

(8-9)

where:

Pf = frictional pressure drop, psi L = length of pipe, ft   = slurry density, lb/gal V = velocity, ft/s f = friction factor, dimensionless D = inside diameter of pipe, in.

For the annulus: D = DO - DI

Turbulent Friction Factor - for slurries containing no bentonite

f = 0.0303/NRe 0.1612             (8-10)

- for slurries containing bentonite

f = 0.00454 + 0.645/NRe0.7     (8-11)

Plug and Laminar Friction Factor

f = 16/NRe                                 (8-12)

Velocity at Some Specific Reynolds Number

For generalized calculations: NRe for plug flow = 100 (maximum) NRe for turbulence = 3000

(8-13)

where:

V = velocity, ft/s K' = consistency index, lb-sn'/ft2 n' = flow behavior index, dimensionless = slurry density, lb/gal D = inside diameter of pipe, in. NRe = specified Reynolds number, dimensionless

For the annulus: D = DO - DI

Hydrostatic Pressure

Ph = 0.052 H         (8-14)

where:

Ph = hydrostatic pressure, psi   = fluid density, lb/gal H = height of column, ft

Newtonian Fluids

Turbulent flow for Newtonian fluids such as mud flush, phosphate washes, and water may be obtained with very little effort. Values have been calculated for the velocity necessary to obtain turbulence in the annular space for about five different pipe and hole sizes. In all cases, these values were below a flow rate of one-tenth of a barrel per minute. Therefore, if any of these fluids are pumped at a rate greater than 0.1 to 0.2 bbl/min in any combination of pipe and hole sizes commonly used, turbulent flow should result.

Typical Flow-Calculation Problems

The following data consist of four example problems which have been worked out in detail. These problems are normally encountered in flow calculations using different cementing compositions, and are (1) primary cementing, (2) multiple tubingless completions, (3) primary cementing — Newtonian fluid, and (4) liner job.

Problem 1 - Primary Cementing

Calculate

1. Pumping rate for turbulence of slurry in the annulus.

2. Frictional pressure drop of slurry in annulus and pipe.

3. Hydraulic horsepower to overcome friction losses.

Well conditions:

hole size — 10 in. casing size — 7 in. - 35 lb depth — 5000 ft slurry — neat API Class A cement

(From Halliburton Cementing Tables, Section 210:

7-in. x  35 lb casing — ID = 6.004) n' = 0.30 K' = 0.195   = 15.6 lb/gal

1. Pumping rate for turbulence

Equation 8-13 for velocity:

For the annulus:

D = DO-DI = 10 in. - 7 in. = 3 in.

Vc = 10.8 ft/s

Equation 8-7 (rearranged):

For the annulus:

D2 = DO2 - DI

2 = 100 - 49 = 51

Qb =  = 32.1 bbl/min

2. Frictional pressure drop

In the annulus:

NRe = 3000

Equation 8-9:

where D = DO - DI = 10 in. - 7 in. = 3 in.

NRe = 3000

In-casing pumping rate = 32.1 bbl/min

Equation 8-7 for velocity - D = 6.004 in.

Equation 8-8 for Reynolds number:

Equation 8-10:

NRe =6668

Equation 8-9:

To make a complete hydraulic analysis of the system, it is necessary to have n', K', and the density of both the mud in the well and the fluid used to displace the top plug. After calculations similar to those above have been made on these fluids, it is possible to make wellhead-pressure calculations dependent upon the location of the cement slurry in the well, and to estimate what the maximum wellhead pressure will be during the cementing operation. From this figure, the hydraulic horsepower can be calculated by the formula:

(8-15)

where:

pressure is in lb/ft2 pumping rate is in ft3/min HP = 0.0245 x  PSI x  BPM HP = (0.0245) (862) (32.1) = 678 HP required

Problem 2 - Multiple-Tubingless Completions

Calculate

1. pumping rate for turbulence in annulus

2. frictional pressure drop in pipe

3. theoretical horsepower required to overcome friction loss in pipe

Well conditions:

hole size — 12 1/4 in. casing size — 4 1/2 in., 11.6 lb, 2 strings

depth — 12,000 ft slurry — POZMIX A cement + 2% gel + 0.5% retarder

(From Halliburton Cementing Tables, Section 210:

4 1/2-in. casing, 11.6 lb, ID = 4 in.) n' = 0.23 K' = 0.155   = 14.1 lb/gal

1. Pumping rate for turbulence

Equation 8-13 for velocity:

(8-13)

D = equivalent diameter = 4 x  hydraulic radius

hydraulic radius = 

area of flow = area of hole - 2 (area of pipe)

wetted perimeter = perimeter of hole + 2 (perimeter of pipe)

Qcf = flow rate in ft3/min = VA

where:

V = velocity, ft/min

A = cross-sectional area, ft2

V = (7.42) (60) = 445 ft/min

Qc f = (445) (0.597) = 265.7 ft3/min

Qb = (265.7) (0.178) = 47.3 bbl/min for turbulence in annulus

47.3 bbl/min = 23.65 bbl/min down each pipe

Equation 8-7:

Equation 8-8:

Equation 8-9:

From Equation 8-11:

f = 0.00454 + 0.645/(24,888)0.7 = 0.00508

           = 5385 psi pressure drop

For one pipe:

where:

pressure is in lb/ft2

rate is in ft3/min

or HP = 0.0245 x  psi x  BPM = (0.0245) (5385) (23.65)

           = 3120 HP required per pipe, or 6240 total HP required for both pipes

Problem 3 - Primary Cementing - Newtonian Fluid

Calculate the pump rate required to get an aqueous-base flush into turbulent flow.

Well conditions:

hole size — 6 in. casing size — 4 1/2 in. (11.6 lb/ft) depth — 5000 ft

It is desirable to run mud flush ahead of cement.

where:

D = diameter, in. V = velocity, ft/s = viscosity, cp   = density, lb/gal

Turbulence begins at NRe = 2100

D = DO - DI

     = 6.0 - 4.5 = 1.5 in.

For mud flush:

= 1 cp

  = 8.33 lb/gal

D2 = DO2 - DI

2 = 36 - 20.25 = 15.75

         = 0.166 bbl/min required for turbulence in annulus

Problem 4 - Liner Job

Calculate

1. Pumping rate for turbulence of slurry in annulus

2. Frictional pressure drop of slurry in pipe

3. Hydraulic horsepower to overcome friction losses

Well conditions:

hole size — 6 3/4 in. last casing — 3628 ft of 7 5/8 in. total depth — 6010 ft drillpipe — 3 1/2 in (11.2 lb/ft) 3577 ft liner size — 5 1/2 in. (15.5 lb/ft) 2433 ft slurry — neat API Class A cement

(From Halliburton Cementing Tables, Section 210:

5 1/2 in. - 15.5 lb casing - ID = 4.95 in., 3 1/2 in. - 11.2 lb drillpipe - ID = 2.90 in.) n' = 0.30 K' = 0.195   = 15.6 lb/gal

1. Pumping rate for turbulence

Equation 8-13 for velocity:

For the annulus:

D = DO - DI = 6.75 in. - 5.50 in. = 1.25 in.

From Equation 8-7:

where:

D2 = DO2 - DI2

      = (6.75)2 - (5.5)2 = 15.3

          = 11.24 bbl/min necessary to obtain turbulence in annulus

2. Frictional pressure drop in drill pipe

Equation 8-7 for velocity:

Equation 8-8 for Reynolds number:

Equation 8-10:

f = 0.0303/(10,690)0.1612 = 0.00679

Equation 8-9:

            = 2677 psi

Frictional pressure drop in 5 1/2-in. liner

Equation 8-8 for velocity:

Equation 8-8 for Reynolds number:

From Equation 8-12:

f = 16/2039 = 0.0079

Equation 8-9:

            = 146 psi

Total frictional pressure drop = 2677 + 146 = 2823 psi

Hydraulic horsepower = 0.0245 x  PSI x  BPM

                                        = 0.0245 (2823) (11.24) = 780

Mud-Displacement Principles

Mud conditioning is the single most significant factor in obtaining effective mud displacement. Findings of studies in wellbores indicate that fluid loss control is important in preventing excess filter cake; and that immobile mud filter cake cannot be completely displaced by the cement slurry even under turbulent flow conditions.

In short, "there is no substitute for maintaining drilling fluid properties that enhance the mobility of the mud, enabling displacement by the cement slurry (Halliburton)."

Two basic forces associated with drilling-mud displacement during primary cementing are differential pressure and cement-on-mud (fluid-on-fluid) drag forces. To displace muds effectively, oilwell cements must exert a combination of differential pressure and drag forces of sufficient magnitude to overcome forces resisting displacement. Here we discuss properties that influence these two forces.

Figure 1 (forces acting on bypassed mud column to resist or cause displacement by slurry ) illustrates a bypassed vertical mud channel and displacing/resisting forces of flurry and mud, respectively.

Figure 1

Introduction to Fluid Flow Types

The character of flowing fluid is described by the relationship between flow rate (shear rate) and pressure (shear stress) that caused the movement.

As previously mentioned, there are two basic fluid types: Newtonian and non-Newtonian. Newtonian fluids, such as water, exhibit a straight-line relationship between flow rate (shear rate) and pressure (shear stress) while the fluid is in laminar flow. They begin to flow when pressure is applied. As pressure increases, flow velocity increases from laminar, through a transition zone (part laminar, part turbulent), to fully developed turbulent ( Figure 2 , flow regimes and velocity profiles for water-type fluids).

Figure 2

Drilling muds and oilwell-cement slurries are non-Newtonian. These fluids are more complex; they may exhibit resistance to flow (gel strength) when pressure is applied. Fluids with gel strength can flow at very low rates in a solid or pluglike manner. Such fluids thus have three flow regimes — plug, laminar, and turbulent — with transition zones between each ( Figure 3 , flow regimes and velocity profiles for cements)

Figure 3

Extensive study has resulted in the development of mathematical models that can be used to predict flow properties and pressure-velocity relationships of such muds and cements. The Bingham plastic model and the Power law model are most commonly used. The former has been used for drilling-fluid analysis since the mid-1940s. Power law model equations presented in the late 1950s are generally considered to be more accurate than those of the Bingham model.

These models attempt to describe the relationship of shear and shear stress for muds and slurries. Although very useful in analyzing the displacement process, they are not precise techniques. They should be used to determine flow regime and pressure requirements for displacement, but results should be considered more qualitative than quantitative — i.e., if analysis indicates a potential displacement problem, believe it; if it shows acceptable displacement conditions, attempt to enhance displacement anyway.

Factors Affecting Cement-Mud Drag Forces

Resisting drag forces exist at contact planes between mud and borehole wall, and between mud and casing. When casing is not centered, resisting drag-force effects are not uniform across the annular flow area. This difference increases with

decentralization, and increases the likelihood of bypassing mud on the narrow side of the annulus.

An indicator of the degree of decentralization is percent standoff, and investigations have shown that standoff increases the velocity required to initiate mud flow from the narrow side of the annulus ( Figure 4 , effect of decentralization on velocity in narrow side of annulus). A stand off of at least 60 percent is recommended, and 70% is preferred. These may be hard to achieve in horizontal wells.

Figure 4

In Figure 4 , the effect of decentralization is indicated as a ratio of fluid velocity in the narrow portion (Wn) to average fluid velocity. For example, with 50% standoff, fluid movement at 110 bpm average rate is zero on the narrow side, and never exceeds 60% of average at any higher rate. (Note: percent standoff = 100 x  Wn/borehole ID radius - casing OD radius.)

Contact time is the period during which a position in the annulus (generally above the zone of interest) remains in contact with a cement slurry that is in turbulent flow. If cement-on-mud drag forces are high enough to cause mud erosion, and contact time is long enough, complete mud removal should be achieved. However, those

conditions are most likely to exist when cement in turbulent flow has adequate contact time with mud having a significantly lower velocity.

The resisting drag force between mud and casing can be altered to a positive mud-displacing force by rotating the casing while displacing cement. This positive effect is illustrated in Figure 5 , (Pipe rotation aids mud removal on narrow side of annulus ).

Figure 5

Reciprocation — moving casing up and down — exerts a somewhat less positive displacing-drag force. However, reciprocation also affects velocity of cement and mud.

Improving Mud Displacement

Assuming an effort has been made to drill the hole properly, the following practices should contribute to optimum primary cementing:

Center the pipe in the borehole.

Move the pipe during mud conditioning and cementing.

Know formation-pressure limits in the borehole.

Condition the mud.

Prevent cement/mud reactions.

Control displacement rates and slurry rheology.

Additional discussion of these guidelines follows.

Centering Pipe

Centering pipe in the borehole creates a uniform annular flow area perpendicular to flow direction, and minimizes variation of resistive drag forces across this flow area. Centralizers do not provide perfect casing/borehole concentricity. They do substantially improve standoff conditions, however, since a casing without a centralizer lies against the borehole wall.

The use of centralizers is strongly discouraged under certain conditions by some drilling personnel. Generally, their concern is that the device will hang up, and prevent the casing from being run to the desired depth. Unfortunately, the conditions that generate the greatest concern — such as highly deviated wells with numerous washouts — are often those that require centralizers. In some cases, centralizers can actually increase the chances of properly running the casing.

Rotating versus Reciprocating

Either type of pipe movement alters drag effects between mud and casing from a resistive displacement force to a positive one. However, model studies have shown that rotation appears to be more effective than reciprocation for removing bypassed mud where casing is severely off-center ( Figure 1 , pipe rotation aids mud removal on narrow side of annulus).

Figure 1

Rotation provides more effective cement/casing drag forces than reciprocation, as it seems to pull the cement into the bypassed mud column. Rotating at 15 to 25 rpm provides more pipe movement relative to annular fluids than does reciprocating 20 ft (6.1 m) on a 1-minute cycle.

Reciprocating can cause lateral casing movement, or changes in standoff, as centralizers move across wellbore irregularities. This lateral movement alters the flow area and encourages bypassed mud displacement.

Pressure Velocity Surges

Reciprocal movement also affects flow rate and velocity of fluid in the annulus. During the upstroke, velocity in the annulus decreases, because part of the fluid pumped out of the shoe occupies the volume previously occupied by the casing.

On the downstroke, the casing acts like a piston, displacing fluid in the wellbore below the shoe up the annulus, along with the volume of fluid being pumped through the shoe. This motion creates substantial pressure and velocity surges in the well-bore ( Figure 2 , Measured pressure surges while lifting and running one casing joint smoothly into the hole.), which improve the erosional effect of cement on bypassed mud by substantially increasing displacing-drag forces.

Figure 2

However, it is important to know the magnitude of pressure changes to avoid breaking down the formation and causing lost circulation.

Fracture-gradient information is important in the determination of safe slurry density and/or pump rate, and of whether stage equipment is needed. A profile showing fracture gradient is helpful; however, accurate profiles are not always available. Indications of fracture gradient for a given area are obtained through evidence of lost circulation during drilling and records of breakdown pressure encountered during stimulation and squeeze operations.

Conditioning Mud Before Cementing

Reducing gel strength and plastic viscosity greatly improves displacement efficiency and reduces the pressures required at the cement/mud interface to displace mud. It also reduces displacement drag forces required to erode and remove bypassed mud by reducing resistive drag-force effects.

Under certain well-defined pressure-window limits, it may be desirable to lower mud density, along with gel strength and plastic viscosity, nearly to the minimum wellbore-pressure limit. This would permit a larger pressure increase for displacement purposes. If this is done, pipe should only be rotated (and not reciprocated), to prevent a swabbing action that may reduce pressure to below the lower limit.

In most cases, mud circulation should be adequate for cleaning up the hole and removing cuttings from the mud if favorable mud properties are maintained while drilling the final portion of the hole.

Displacement Rate and Rheology

High displacement rates improve displacement efficiency if cement can be in turbulent flow up the annulus. Conditions that may prevent such flow include:

limited displacement-rate capability (pumping equipment)

breakdown (pressure-window) restrictions that limit pressure

improper flow (rheological) properties of mud and/or slurry

If wellbore conditions can tolerate high displacement pressures, the provision of extra pumping equipment is basically an economic decision. Formation conditions that determine the pressure window are fixed, and attempts to exceed those limits may create serious problems.

Dispersants versus Turbulence

Fluid properties of the slurry can also be altered — i.e., dispersants can be added to lower gel strength to attain turbulent flow at lower rates. This can be desirable where high pump rates would otherwise be required. By adding dispersant and lowering pump rate, an increase in effective contact time can be effected, along with the desired velocity profile. However, if turbulence can be achieved at reasonable pump rates without dispersants, the resulting displacement should be better; i.e., turbulent flow is better than laminar flow, but additional turbulence may not be even more effective.

Once turbulent flow is established, displacement efficiency increases with increased slurry-flow resistance, as displacing drag forces increase with increasing contact pressure at the cement/mud interface. Thus, thinning the slurry to increase turbulence is not recommended.

Buoyancy Effect

The buoyancy effect of higher-density cement slurry on lower-density mud is controversial. Such effects should provide a positive displacing force on bypassed mud as long as there is vertical continuity of the mud column to the top of the rising cement/mud interface.

Contact pressure at the base of the bypassed cement/mud interface increases with increasing height of cement. This increased contact pressure near the bottom of the bypassed mud column should increase both displacing pressure and erosional effects. However, if the cement bypasses a portion of the mud and then reestablishes complete displacement of the movable mud in the annulus above the bypassed mud, displacing drag forces may be the only effective force working to remove the mud.

Plug Flow

When wellbore conditions are such that turbulence cannot be achieved, displacing with cement in a plug-flow regime can maintain a flatter velocity profile in the annulus. Although the resulting drag forces are not as effective as those of turbulence, they can be maximized by increasing cement gel strength as much as possible, particularly in the lead part of the slurry. Also, cement density can improve plug flow displacement when it is maintained at least two pounds per gallon heavier than the mud.

Improved Laminar-Flow Displacement

Wellbore and/or surface conditions that prohibit turbulent flow may also prohibit plug flow. When these uncommon circumstances exist, an alternative is to alter cement rheological properties to increase apparent slurry viscosity.

Even in laminar flow, displacement can be effective if the slurry is thicker (i.e., has higher yield strength and plastic viscosity) than the mud, and if sufficient volumes are used to obtain the desired cement height on the narrow side of an eccentric annulus.

One guide for cement rheological design is to have cement yield strength exceed mud yield strength by a factor equal to maximum annulus clearance divided by minimum annulus clearance.