CEMENTING AND COMPLETION

• PART ONE CEMENTING TECHNICH

• PART TWO COMPLETION

Part one Cementing technique

• Section one : Preface • Section two : Portland cement • Section three: Cementing design

Section 1 Preface

• The history of Cementing technological advances

• The functions of cementing• The implications of cementing on well

performance

1-1 Cementing technological advances

• Available cementsDuring the early days, only one or two cements

were available for cementing. As wells became deeper, more flexibility in cement performance was required than could be achieved with available cements. It was with the advent of the API Standardization Committee in 1937 that more and better cements were developed. Today, eight API classes of cements are available, each with distinct characteristics

• Cement additivesCement additives have played an important

role in the advancement of cementing technology. To properly use the available cements, additives were developed to control the major cement properties (thickening time, consistency, fluid-loss rate, free water, setting time)

• Fluid-loss control Perhaps one of the most notable developments among all t

he additives is the one that controls the fluid-loss rate of the cement and maintains the proper water-to-cement ratio. These additives made their debut in the early 1950s in response to deeper drilling below 10,000 to 12,000 ft. For a cement to be pumpable, excess water above that required for proper hydration is required. Some or all of this excess water can be easily squeezed from the slurry, if the cement encounters a permeable formation in the well-bore during the cement job. The loss of only a portion of this water can significantly alter the cement properties. If a high portion of the excess water is squeezed from the slurry, the cement may experience what many call a “ flash set”. At this point, the cement is no longer pumpable and the job is terminated prematurely. Fluid-loss additives tie up the excess water, and prevent it from being squeezed from the slurry.

• Reduction in WOC timeIn the early 1960s, a significant development

occurred in cement design which has allowed tremendous saving in rig costs to be realized. This was made possible by reducing the time for the cement to harden, the waiting-on-cement (WOC) time. During the early days, WOC time averaged 10 days and in some instances up to 28 days before operations could be resumed. But today, the WOC time is just several hours. So you can image the big role the reduction of WOC time played in drilling.

• Density-Altering AdditivesThe density of neat cement, i.e.,

water and cement, varies from 14.8 to 16.4 lb/gal depending on the API Class of cement used. In many cases of high bottom-hole formation pressures, the density is too low to control the well fluids. In other cases, lower density cements are required to prevent lost circulation during the cement job. Many additives have been developed to control and meet density requirements.

• Testing EquipmentsOne of the outstanding developments of

mechanical devices for cement slurry design was the high-temperature, high-pressure thickening time tester developed in 1939 by R. F. Farris. The device allowed a more accurate determination of the thickening time of cement slurries under a simulated down-hole environment of temperature and pressure

• Flow After CementingPerhaps the most important

development for deeper high-pressure gas well has been the control of flow after cementing. Gas must be prevented from invading the cement. There are several successful methods to control gas migration. Usually a combination of methods works best.

• Well preparation and hole conditioningUppermost in all planning and drilling decisions must be tha

t the well-bore be cementable. The cost of repairing a faulty cement job can far exceed savings in drilling costs. Mud displacement efficiency during the cementing job can be enhanced by properly conditioning the mud. This is one phase of the entire operation that should not be rushed-up to 24 hours may be required to properly condition the mud and well-bore after the casing is on the bottom. At best, a cement slurry can only follow the path of the drilling mud circulating ahead of it in the annulus. Therefore, the time required to properly condition the mud and the hole will be very well spent. Centralization of the casing, as well as pipe movement during mud conditioning and cementing, also improves the chances for a successful cement job. Beneficial results are obtained with either pipe reciprocation or rotation, or both simultaneously.

• Job execution and monitoringEquipment and techniques have been developed

to properly monitor all of the many parameters of a cement job. In turn, this allows timely decisions to make changes during execution to improve job success. Recorded data normally include pump rate in, annulus rate out, well-head pressure, density of fluids pumped in and those returning, cumulative displacement volume, cumulative return volume, and hook load during pipe reciprocation.

1-2 The functions of cementing

• Cementing bonding – building a base for future

• Prevention is better than cure

Cement Bonding—building a base for future production

Production activities after drilling the well depend on a good primary cement job. A solid, continuous cement sheath around the casing is a necessity for protecting formation integrity, promoting maximum production from pay zones, as well as prolonging the productive life of the well. Poor bonding between casing wall and cement or between the cement and the well bore can provide paths for fluid migration.

Along with some very important secondary objectives, a successful cementing job is primarily depend on:

1. The isolation of porous formations under all applied loads.

2. The exclusion of unwanted fluids from producing intervals

3. And the confinement of abnormally pressured formations.

Prevention is better than the cure

In an oil well, as in the human body, prevention of a health problem is better than a cure. A long and productive well life is possible if the right care is taken in the primary cementing job. The consequences of a bad cement job are often a costly squeeze job or damage to producing formation which may result in costly production efforts such as block squeezing or the installation of expensive fluid treating equipment and often drilling of water disposal well.

Factors important to a good cement jobAchieving a perfect primary cement job involves several key elements:1.Cleaning the annulus without gouging, enhancing cement bonding to

the well bore.2. Centering the casing in the holes to form a uniform sheath around

the casing and minimize the chances of a channeling effect on the cement job.

3. Strengthening the cement in the annular spaces to allow for proper perforation in the producing zones.

4. Bonding of the cement to the casing surface to eliminate the possibility of a micro-annulus.

5.Providing the necessary pipe movement, either rotation or reciprocation to increase turbulence, improve circulation, and provide complete displacement of the drilling fluid with cement.

1-3 Implications of cementing on well performance

• 1-3-1 Introduction Zonal isolation is surely the most important function of the

cement sheath. While flow of any fluid along and through the cement sheath is undesirable, upward gas flow or gas migration through and along the cement sheath has received particularly attention. Gas migration can open additional flow paths, in the form of interconnected porosity through the setting cement. Flow paths may also take the form of discrete conductive channels( micro-annuli ) at the pipe/cement or cement/formation interfaces. A seemingly small micro-annulus width will result in a very large effective permeability through the cement sheath. So the creating of a micro-annulus should be of primary concern.

• 1-3-2 Zonal isolationZonal isolation is the most

important function of cementing, the simple way to attempt the amount of the zonal isolation is to compare the producing rate of the active layer into the well with the contributions of an overlying or underlying formation through the cement sheath.

• For simplicity, let us consider steady-state flow into the well from the producing layer. The equation is given below:

q=

( )

141.2 [ln ]

c wf

e

w

kh P prB sr

q= flow rate (stb/D)K=permeability (md)h=thickness (ft)Pc=reservoir pressure (psi)Pwf=flowing bottom hole pressure (psi)U=viscosity (cp)S=skin factot B=formation volume factor

For a gas well, the equation is

q=

2 2( )

1424 [ln ]e

w

kh Pe PwfrZT sr

For flow into the producing layer from another formation, there will be

* 2 2 2 2

1

( )( )1424 ( )w cas i wf

cem

k r r p pq

ZT L

• ConclusionThe above discussion demonstrates that the ability

of a well to achieve its production potential is influenced most by the degree of zonal isolation achieved during the completion. The quality of the cement sheath is in turn the most important factor influencing zonal isolation. Therefore, the cementation of a well should be of critical importance to every operator.

Section 2 Portland cement• Introduction Portland cement is by far the most important

binding material in terms of quantity produced. It is used in nearly all well cementing operations. Portland cement is the most common example of a hydraulic cement., which involves chemical reactions between water and the compounds present in the cement, not upon a drying-out process. In this section, fundamental information is presented regarding the basic materials and the classification.

2-1 Materials :Portland cement consists principally of four compo

unds: tri-calcium silicate( ) , di-calcium silicate ( ), tri-calcium aluminate ( ) and tetracalium aluminoferrite ( ). These compounds are formed in a kiln by a series of reactions at temperatures as high as 1500 between lime, silica, alumina, and iron oxide.

3C S2C S 3C A

3C AF

• In the above • Two types of raw materials are needed to prepare a mixture that will produce Portland cement: “calcareous” materials which contain lime, and “argillaceous” materials which contain alumina, silica and iron oxide.

2

2 3

2 3

C CaOS SiOA Al OF Fe o

2-2 Classification

• API classification systemThere are 8 classes of API Portland cements,

designated A through H. They are arranged according to the depths to which they are placed, and the temperatures and pressures to which they are exposed. If you meet some problems in using the specifications, you can refer to them in some handbooks. Here is the simple classification.

• Class A : intended for use from surface to a depth of 6,000 ft (1830m), when special properties are not required. Available only in Ordinary type, Class A is similar to ASTM type I cement.

• Class B intended for use from surface to a depth of 6,000 ft (1,830m), when conditions require moderate to high sulfate resistance.

• Class C: intended for use from surface to a depth of 6,000 ft (1830 m), when conditions require high early strength. Class C is available in all three degrees of sulfate resistance.

• Class D: intended for use at depths from 6,000 ft (1830m), to 10,000 ft (3,050m), under conditions of moderately high temperatures and pressures .

• Class E: intended for use from 10,000 ft (3,050m) to 14,000 ft (4,270m) depth, under conditions of high temperatures and pressures.

• Class F: intended for use from 10,000 ft (3050m) to 16,000 ft (4,880 m) depth, under conditions of extremely high temperature and pressures.

• Class G: intended for use as a basic well cement from surface to 8000 ft

Class H: (2440m) depth as manufactured, or can be used with accelerators

and retarders to cover a wide range of well depths and temperature .they are identical in chemical compositions

2-3 Cement additives• 2-3-1 Introduction In well cementing, Portland cement systems are routinely designed for

temperatures ranging from below freezing in permafrost zones to 700 in thermal recovery and geothermal wells. In addition to severe temperatures and pressures, well cements must often be designed to contend with weak or porous formations, corrosive fluids, and over-pressured formation fluids. It has been possible to accommodate such a wide range of conditions only through the development of cement additives. Additives modify the behavior of the cement system, ideally allowing successful slurry placement between the casing and the formation, rapid compressive strength development, and adequate zonal isolation during the lifetime of the well. Today over 100 additives for well cements are available, many of which can be supplied in solid or liquid forms.

0 0(350 )F C

2-3-2 Categories• Eight categories of additives are generally

recognized.1.Accelerators: chemicals which reduce the setting

time of a cement system, and increase the rate of compressive strength development.

2.Retarders: chemicals which extend the setting time of a cement system

3.Extenders: materials which lower the density of a cement system, and/or reduce the quantity of cement per unit volume of set product.

4.Weighting Agents: materials which increase the density of a cement system

5.Dispersants: chemical which reduce the viscosity of a cement system

6.Fluid-Loss Control Agents: materials which control the loss of the aqueous phase of a cement system to the formation.

7.Lost Circulation Control Agents: materials which control the loss of cement slurry to weak or vugular formations

8.Specialty Additives: miscellaneous additives, antifoam agents

2-4 Special cement system• 2-4-1 Introduction As the technology of well cementing has

advanced, certain problems have been encountered for which special cement systems have been developed. This chapter presents cement technologies specific to such problems as slurry fallback, lost circulation, micro-annuli, cementing across salt formations, and corrosive well environments.

2-4-2 Thixotropic cements• Thixotropy is a term used to de

scribe the property exhibited by a system that is fluid under shear, but develops a gel structure and becomes self-supporting when at rest.

In practical terms, thixotropic cement slurries are thin and fluid during mixing and displacement, but rapidly form a rigid self-supporting gel structure when pumping ceases. Upon reagitation, the gel structure breaks and the slurry is again fluid and pumpable.

2-4-3 Expansive cement systems

• Cement systems which expand slightly after setting are recognized as a means of sealing micro-annuli and improving primary cementing results. The improved bonding is the result of mechanical resistance or tightening of the cement against the pipe and formation. Good bonding can be obtained even if mud is left on the casing or formation surfaces.

2-4-4 Freeze-protected cements

• Permafrost is defined as any permanently frozen subsurface formation. When permafrost exists, thawing of the formation must be avoided during drilling and completion. Two types of cement systems have been shown to perform successfully in this severe environment: (1) calcium aluminate cement, and (2) gypsum/Portland cement blends

2-4-5 Salt cement systems• Cement systems which contain significant quanti

ties of sodium chloride (NaCl) or potassium chloride ( KCl) are commonly called “salt cements” .

• 2-4-6 Latex-modified cement systemsLatex is a general term describing an emulsion pol

ymer. The material is usually supplied as a milky suspension of very small spherical polymer particles(200 to 500 nm in diameter). Most latex dispersions contain about 50% solids.

2-4-7 Cements for corrosive environments

Set Portland cement is a remarkably durable and forgiving material; however, there are limits beyond which it will rebel. In a well-bore environment, Portland cement is subject to chemical attack by certain formations and by substances injected from the surface. In addition to geothermal well cementing ,one must also pay close attention to cement durability in wells for chemical waste disposal and for enhanced oil recovery by CO2-flooding.

Section 3 Cementing design

• 3-1 cementing materials Before describing the design and function of

cementing equipment, one must be familiar with the physical and chemical properties of the various cementing materials.

1.Cement 2.Water Fresh water is normally used for

cementing onshore wells , and seawater for offshore locations.

3.Dry cement additives4.Liquid additives

3-2 Basic equipment1.Tansportation of bulk materials or blends to the well-site, such as

using land rigs or offshore rigs.2.well-site storage of cement or blends3.Metering of water A set of twin 10-bbl tanks is preferred.4.Liquid-additives storage and mixing The mixing system consists of

two principal parts –a storageunit and a metering unit (which consists of 3 or 4 25-gal or 10-L tanks

with visible level scales )5.Cement mixing There are several mixing systems : conventional jet

mixer, recirculation jet mixer and without conventional jets.6. High-pressure pumps 7.Cementing units 8.Casing hardware It includes rubber plugs, centralizer, float collar and

guide shoe.

3-2 cementing equipments

Typical process

Mixing and pumping equipment on rig site

• The equipment used on or within the casing string to enhance casing placement and cementing operations, within the oil industry, this equipment is commonly referred to as casing hardware and cementing tools. Casing hardware consists of a wide variety of mechanical devices which are used to enhanced primary cementing operations. Some common types of casing hardware include guide shoes, floating and auto-fill shoes and collars, stage collars, and external attachments such as scratchers and centralizers. Cementing tools are generally retrievable devices, and may require some form of operation from the surface. Packers, bridge plugs, and retainers are examples of cementing tools.

Typical cementing truck

Types of centralizing

Cementing plugs

• Retrievable squeeze packers are used in multiple setting operations

3-3 Cement job design

3-3-1 Introduction The factors need to

be examined are:1. Depth/configuratio

nal data 2. well-bore environ

ment 3. Temperature data

• 1 Depth/ configurational dataThese include information concerning the vertical depth, m

easured depth, casing size ( and weight), open-hole size, and string type. Depth data are particularly important because they strongly influence the temperature, fluid volume, hydrostatic pressure, and friction pressure. High angles of deviation can have a tremendous impact on many well parameters, and may require the design of special systems for mud displacement and cement slurries exhibiting no free water. In principle, open-hole size is dictated by drill-bit size which, along with casing size and type, should be selected on the basis of the expected well conditions and the final expected completion configuration.

• 2 Well-bore environment The specific problems posed by the nature of the

open-hole interval traversed by the casing string require careful evaluation. One must consider the presence of pay zones, of over-pressured formations, or, etc. Pore pressures are important from a those with low fracture gradients, gas, massive salt zones well-security standpoint, and information on this chemical properties of the mud also need to be may be obtained by mud logging. The physical and considered when designing a cement job. Chemical washes, spacers, or other flush fluids must be compatible with the mud as well as the cement, and may need to contain special additives.

• 3 Temperature dataBoth bottom-hole circulating temperature (BHCT) and

bottom-hole static temperature(BHST) need to be considered as well as the temperature

differential (DT) between the bottom and top of the cement column. The first of these, BHCT, is the temperature to which the cement will , theoretically, be exposed as it is placed in the well. As such, it is the temperature which will be used for high temperature, high-pressure thickening time testing of the proposed cement formulation. BHST is important principally for either the assessment of the long-term stability, or the rate of compressive strength development of a given cement system. The temperature differential between the top and bottom of the cement can be extremely important when embarking upon a cementing design.

3-3-2 The design of casing size1.Longitudinal forceW=L*q W-the force exposed at the casing head ,N L-the length of the casing, m q-the weight per meter, Kg/mConsidering the force of the mud: Wf=L*q*(1-Rn/Rg)Rn-the density of the mud , Rg-the density of the casing, 7.8 2. The compression from the outsideP=0.1*H*RnH-the length of the casing

3/g cm3/g cm

3-3-3 The design of cement 1.The volume of cement

D-the diameter of the well-holed1-the outside diameter of the casingd2-the inside diameter of the casingH-the height of the mud to be liftedh-the height of the slurry

2 2 21 1 2( )

4 4V k D d H d h

2. G=k2*Q*VG-the volume of the cement , bagQ-the volume of dry cement needed per 1 V-the volume of the cement slurry3.The volume of fresh waterVw=V1*GV1-the water needed to mix into slurry per bag ce

ment4. The volume of mud to be displaced

2 2 21 1 2 2( )

4mud n nV L d L d L d

3m2 2 2

1 1 2 2( )4mud n nV L d L d L d

5.The maximum of the pumping pressureIf the depth is less than 1000m p=0.1*(H-h)*(R1-R)+0.01L+8If the depth is more than 1000mP=0.1*(H-h)*(r1-r)+0.01+16H-the height of the cement slurry in the annulus h-the length of the slurry in the case tube6.The time needed to squeeze cement T=T1+T2+T3T1-the time of mixing cementT2-the fixing time of equipments ,about 1-3 minutesT3-the time to squeeze cement

Example of job design procedure

The plan is to cement a 47-lbm/ft, 25-cm casing at a depth of 9,300 ft (2,835 m). The well is vertical, and the previous casing (68-lnm/ft,13 .3/8 in ) is set at 5,350 ft (1,630 m). The hole is reasonably gauge, with an open-hole diameter of 12.5 in. (32 cm) for much of its length. Two shale sections show some washout (to a maximum of 15.5 in.[39.3 cm]), while two other intervals are tight (12.25in. [31 cm]). Because of the hydrostatic limitations and the temperature differentials, a stage collar will be set just inside the shoe of the 13.3/8 in. (34-cm) casing.

There are several features of the open-hole interval which require special attention. The most obvious in the presence of a major pay zone extending from 8,450 to 8,850 ft ( 2,576 to 2,697 m). This has the highest pore

pressure and, therefore, probably poses the greatest risk to well control. Fracture pressures for the entire open hole are fairly low, but a large depleted interval extending from 6,500 to 7,000 ft (1,981 to 2,134 m) exhibits the lowest fracture gradient in the well. This further restricts the choice of fluids. The mud in the hole is a water-base polymer system with a density of 11.4-lb/gal (1.37 g/cm*3) ,a system which maintains adequate coverage of the pay zone’s 10.8-lb/gal (1.30 g/cm*3) equivalent mud-weight pore pressure.

The report BHST for the well is 238 (114 )0F 0C

which corresponds to a geothermal gradient of 1.7 /100 ft . The calculated circulating temperature (BHCT ) in the well (from API tables, Appendix B) is 168 (76 ). The calculated static temperature at the TOC is 167 (75 ), which is close to the BHCT. For this reason, the cement’s compressive strength development should not be impaired. A summary of the well data can be found in Table 11-5. From this information, we can draw several conclusions:

* Two cement slurries, a low-density lead and a normal density tail, will probably be required due to hydrostatic limitations. The tail slurry should be used to cover the pay zones and a reasonable length of annulus above them.

0F0F 0C

0F

0C

• Both slurries will require the incorporation of fluid-loss additives to avoid damage to pay zones, possible bridge, etc.

• Dispersants will probably be required due to the use of fluid-loss additives, and to the fact that the friction pressures generated by viscous slurries could pose a risk to weak zones.

• A cement retarder will be required to achieve adequate placement time.

• It is unlikely that the cement slurries will be pumped in turbulent flow, because of the size of the annular gap and the presence of weak zones.

• With mixing and pumping time taken into account, the duration of the job is likely to be 2.5 to 3 hours. With one hour for safety, we would normally look for a minimum thickening time of 3.5 to 4 hours for the lead slurry, and somewhat less for the tail. However, considering that this is a two-stage job, the possibility exists that the cement may be lifted above the stage collar because of inaccuracies in the hole caliper.

Based on these observations, the “first-guess” preferred job design would be as follows.

First-Stage Lead Slurry API Class G cement + Extender + Fluid-Loss Additive + Retarder mixed at 12.5 lb/gal (1.50g/cm*3) using rig water Thickening time :

4 to 5 hours API Fluid-Loss Rate: 150 to 300 mL/30 minFirst-Stage Tail Slurry API Class G Cement + 35% BWOC silica Flour + Fluid-Loss Additive + Dispersant + Retarder mixed at 15.8 lb/gal (1.90 g/cm*3) using rig water Thickening time : 3 to 4 hours API Fluid-Loss Rate: 50 to 150 mL/30 min

Mud Removal chemical Wash: 20 bbl Turbulent Flow Spacer (12 lb/gal [1.44 g/cm*3]): 80 bbl Total volume 100 bbl The casing should be well centralized and rotated/reciprocated through

the job. Laboratory testing optimizes the slurry formulations to meet the require

d performance specifications, and also provides data concerning the rheological properties of the slurries, spacers, and mud at both surface and down-hole conditions. These data ( Table 11-6, 11-7, and 11-8 ) are then used in the final job design.

It must be stressed here that these calculations are based purely on hydrostatic pressures, and are used to determine well security after placement. A graphical representation of these data is shown in Fig, 11-3. a simulation of the actual operation, including shutdowns, rate changes, U-tubing, etc., is shown in Figs 11-4 and 11-5 . A job schedule table, representative of the expected rig procedures, upon which the simulation is based, is illustrated in Table 11-9 . Figure 11-4 illustrates the fact that flow rates in and out of the well are not equivalent for a large part of the job.

• Figure 11-4 Flow-rate comparison at depth of 9300 ft

3-4 Primary cementing techniques

3-4-1 IntroductionPrimary cementing is a technique for placing

cement slurries in the annular space between the casing and the bore-holes. The cement then hardens to form a hydraulic seal in the well-bore, preventing the migration of formation fluid in the annulus. Primary cementing is therefore one of the most critical stages during the drilling and completion of a well.

3-4-2 Classification of casing strings

A series of casing strings is necessary to complete a well, and produce the desired fluids successfully. The design of the casing program is contingent upon several factors –(1) depth, (2) the sizes of the holes in which the casing strings are to be set, (4) the mud-column and formation pressures, (5) the condition of the formation, and (6) the drilling objectives. The casing string must also be designed to withstand the mechanical and chemical stresses in the well.

1. Conductor pipeThe conductor is usually the first and shortest casing string.

Its purpose is to protect shallow sands from being contaminated by drilling fluids, and help prevent washouts which can easily occur near the surface because of loose, unconsolidated topsoils, gravel beds, etc. the conductor pipe also serve as a channel to raise the circulating fluid high enough to return to the mud system. It can be used for the attachment of a blowout preventer (BOP), should gas sands, for example, be encountered at shallow depths. The conductor pipe serves to protect the subsequent casing strings from corrosion, and may be used to support some of the wellhead load when the ground support may be inadequate.

• 2 Surface casingThe second string of casing, which serves to case off unco

nsolidated formations and aquifers found at relatively shallow depths, is known as surface casing. In addition to maintaining hole integrity, the surface casing prevents the contamination of fresh groundwater by drilling fluids, subterranean brines, oil, or gas. Quite often, the surface casing is the first string to which BOPs are connected. Therefore, the selected casing must be strong enough to support a BOP and to withstand the gas or fluid pressures which may be encountered. Surface casing should have the strength to support further casing strings and production tubulars, and provide a solid anchor for the casing head when the well is put on production. Ordinarily, the burst pressure should be equal to one psi per foot of depth to which it is set.

• 3 Producing casingSetting this string of casing is one of the principal objectives

when drilling a well. In many ways, the production string is the oil well. This string of casing serves to isolate the reservoir from undesirable fluids in the producing formation, and from other zones penetrated by the well-bore. It is the protective housing for the tubing and other equipment used in a well. The production casing is normally run and cemented through a zone to be produced, and then perforated to allow communication with the formation. Sometimes it is set just above the zone, and an open-hole completion is performed. The production casing is normally the last casing set in the well. It may be subjected to maximum well pressures and temperatures, and must be designed to withstand such conditions. The cementing of production casings is critical.

3-4-3 Cement placement procedures

• The vast majority of primary cement jobs is performed by pumping the cement slurry down through the casing and up the annulus. Other techniques also exist for solving various well-completion problems. For large-diameter casings, the traditional cementing technique is frequently inadequate; consequently, cementing through the drill-pipe or a grouting technique, where the cement is circulated into place by pumping the slurry down one or more small diameter pipes place in the annular gap, is performed. when cementing intermediate or production casings, well conditions and the length of interval to be cemented will decide the placement technique to used.

1. Single-Stage cementing After the casing is in place, the mud is circulated

as long as necessary to remove high-gel-strength mud pockets formed during the semi-static period of removing the drill-pipe, logging, or running the casing. Mud circulation is usually performed through the cement head to avoid stopping for an excessive period of time after the mud has been conditioned. If a single-plug cement head is used, circulation must be stopped prior to cementing to load both cement plugs.

Typical one-stage primary cement job on a surface casing string

2.Multiple-Stage cementingMultiple-stage cementing may be necessary for a variety of

reasons:• Down-hole formations unable to support hydrostatic

pressures exerted by a long column of cement,• Upper zone to be cemented with ( higher density, higher

compressive strength ) uncontaminated cement, and • Cement not required between widely separated intervals.Most of the reasons for multiple-stage cementing fall in the

first category. Three standard multistage techniques are commonly employed:

• Regular two-stage cementing where the cementing of each stage is a distinct and separate operation,

• Continuous two-stage cementing with both stages cemented in one continuous operation, and

• Three-stage cementing where each stage is cemented as a separate operation.

4. LinersA liner is a string of standard casing which does not extend

all the way to the surface, but is hung from inside the previous casing string. The overlap depends on the purpose of the liner, and could vary from 50 ft ( 15 m) for drilling liners to as long as 500 ft (152 m) for production liners. Liners can be classified as follows:

* production liners: run from the last casing to total depth, they replace production casing. Cementing is usually critical as zonal isolation is essential during production and any subsequent stimulation treatments that may be necessary.

• Drilling or intermediate liners: these are set primarily to case off and isolate zones of lost circulation, highly over-pressured zones, sloughing shales, or plastic formations, so that drilling may be continued.

• Tieback stub liners: these extend from the top of an existing liner to a point up-hole inside another casing.

Types of liners

Regular liner cementingThe liner cement head and manifold are installed

on the drill-pipe with the “pump-down” slurry displacement plug placed between the two inlets. The plug releasing stem holds the plug in cement head. After the cementing lines are rigged up and pressure tested, the chemical wash or spacer is pumped down the drill-pipe. No bottom wiper plug is used ahead of the spacer or slurry. Once the slurry is pumped into the drill-pipe, the pump-down plug is dropped and displaced to the liner hanger. At this point, the pump-down plug passes through the liner setting tool, and then latches into and seals the hole in the liner wiper plug.

3-4-4 Putting the squeeze on cement

Three techniques of squeeze cementing are in use today. The seldomly used Braden head method pumps slurry into casing at the surface below a closed wellhead. The “bullhead” squeeze method displaces slurry through open-ended tubing or drill pipe, usually with the casing head closed.

Both of the above procedures are risky because the slurry is not controlled or confined to depth. By far, the mostly widely used approach uses drill pipe and tubing packer or cement retainer. A packer or retainer is run in place, the working string is seated and squeezing is accomplished below.

Squeezing is a “touchy” undertaking, it is for two reasons:

First, due to formation pressure, temperature, porosity, permeability and chemical makeup of reservoir fluids, cement slurries don not always react according to specifications.

Secondly ,the cost of washing over is enormous. For 100 ft of working string covered, recovery time with a work-over rig on daylight schedule can take up to 1 months, barring unforeseen difficulties. Occasionally the well is lost in such cases.

3-4-5 Mud removal

• IntroductionThe main objective of a primary cement job is to pr

ovide complete and permanent isolation of the permeable zones located behind the casing. To meet this objective, the drilling mud and the pre-flush(if any) must be fully removed from the annulus, and the annular space must be completely filled with cement slurry. Therefore, good mud removal and proper slurry placement are essential to obtain well isolation.

Research concerning the cement placement process began in the 1930s. Some key factors influencing primary cement job failures were identified, and solutions were proposed as early as 1940. But mud displacement remains a subject of much current experimental and theoretical work. The major difficulty arises from the fact that both the experimental and theoretical approaches suffer from severe limitations.

3-5 Horizontal well cementing

• 3-5-1 Horizontal well classificationsHorizontal wells are those in which part of the well-

bore is inclined 90 centigrade with respect to vertical, although less-than-horizontal, high-angle wells often receive this designation. The horizontal portion of the well is often called a “drain-hole “. Horizontal drilling techniques can be subdivided into three different groups, depending on the angle build rate : long, medium, and short radius.

3-5-2 Completion proceduresMost horizontal holes are completed without cementing.

The horizontal section is often lined with a slotted liner, pre-perforated liner or, in some cases, wire-wrapped sand control liners. In such wells, the formation rock must have sufficient integrity to prevent collapse or sloughing, particularly when approaching depletion. Very rarely can horizontal wells be completed as an open hole without some method of lining.

The previous intermediate casing, which is frequently highly deviated, must have a good cement job. This is necessary to protect the intermediate string from produced fluids, and to provide isolation between the upper cased off zones and the lower producing intervals.

Often, however, there are horizontal well completion and production circumstances which dictate that casing must be run, and some form of isolation initiated. Some of these are listed below.

• When subsequent multi-interval stimulation treatments of the reservoir are planned.

• When “gas-coning” and “water-coning” control problems are foreseen due to the bore-hole penetrating or being too close to the gas cap or water table. This may result from loss of directional control causing the bore-holes to meander, or simply penetration of the gas cap prior to entering the oil producing zone.

• When current producing intervals may require remedial cementing to prevent unwanted water or gas breakthrough.

• Examples of typical horizontal completions and cementing methods are illustrated.

3-6 Cement job evaluation• 3-6-1 Introduction• Cement job evaluation consists of checking whether the

objectives have been reached after the job has been performed. No evaluation of the cement job will be efficient if the objectives are not clear. Cement provides some corrosion protection to all the casing strings. Before the development of cement bond logs, the evaluation of cement jobs was performed either by testing the hydraulic isolation or locating the top of the cement. The method of evaluation must be selected according to the objective to reached.

3-6-2 The methods of evaluation

1.Hydraulic testingIt consists of testing the isolation provided

by the cement. This can be after primary cement jobs, when water zones are located near the oil or gas zone to be produced. There are several techniques which are common used, such as pressure testing, dry testing.

2. Temperature, nuclear and noise logging measurements

• Temperature logging is often used for cement evaluation. It is used for primary cementing evaluation, mainly in top-of-cement detection. Temperature surveys are also run to detect leaks or channeling.

• Nuclear loggingIn the oil industry, it is common practice to add radioactive

materials as tracers. This technique can be used to tag drilling mud and to estimate circulation times and volumes, by detecting the radioactive material in the returns. Several radioactive tracers can be used in cementing.

Noise logging It can be used to detect fluid flow behind the casing, or

fluid/gas entry inside a well-bore.

3.Acoustic logging measurements

Acoustic logs are without a doubt the most widely used and efficient method to evaluate cement jobs. Cement job evaluation through acoustic log interpretation seeks the relationship between the response of a tool and the quality of the cement job after a given time following cement placement, with the response of acoustic tools, related to the acoustic properties of the surrounding environment( casing, cement, and formation) , it is possible to determine the quality of the acoustic coupling between the casing, cement, and formation. The analysis of the log must be performed very carefully to determine the origin of the log response.

PART Two Completion

Section 1 Introduction

Section 2 Connecting the pay zone and the borehole

Section 1 Introduction to completion

• 1-1 Main factors influencing completion design1.Parameters related to the well’s purposeThe purpose of drilling can vary depending on the well, with a

distinction basically made between: an exploration well; an appraisal well; a development well

2.Parameters related to the environment There may be constraints on operation due to the country or site where

the well is located, whether on land or offshore.3.Parameters related to drillingType of drilling rig ,well profile and the drilling program are the factors

should be considered.4.Parameters related to the reservoirThe reservoir pressure and its changes is the main factor that we have

to consider.5.safety

Diameters available according to the drilling and casing program

1-2 Overall approach to a well’s flow capacity

• A well’s flow capacity is a crucial parameter because of its economic consequences. It is therefore important to endeavor to assess it. However, it should be pointed out that the flow capacity evolves over time and unfortunately tends to decrease.

1. Base equationA well’s flow rate depends on ;• The existing pressure difference, the reservoir pressure( Pr) and t

he back pressure exerted down-hole (Pbh).• Parameters that involve the type of reservoir and in-place fluid1-1 the case of an oil wellHere, provided there is no tree gas, that the low can be considered to b

e of the radio cylindric steady-state type and that the fluid velocity is not too great in the vicinity of the well-bore, the flow equation can be simplified to :

Q=PI*(Pr-Pbh)

Where the productivity index (PI) mainly depends on the viscosity of the fluid, the permeability of the formation itself, the disturbances in the vicinity of the well-bore and the thickness of the reservoir.

In fact the actual productivity index (PI) can be compared with the theoretical productivity index (PIth) of a vertical well at the level of the formation that would have been drilled under ideal conditions. By this we mean without having interfered with the reservoir characteristics in the vicinity of the well-bore (permeability especially) and with no restrictions on the connection between the reservoir and the well-bore.

Here the theoretical productivity index is as follows:

With : numerical coefficient depending, among other things h reservoir thicknessK reservoir permeabilityu- viscosity of the fluid in the reservoirR- well drainage radiusrw- well-bore radius

lnth

w

hkPI Rr

• As far as the real well is concerned, all of the disturbances in the vicinity of the well-bore (skin effect) are lumped together under the term “s” (skin factor) in the following way:

furthermore, the flow efficiency (Fe) is defined as the ratio between the actual flow rate and the theoretical flow rate that the “ideal” well would have under the same bottom-hole pressure conditions:

(ln )w

hkPI R sr

ln

(ln )

w

th th

w

RrQ PIFe RQ PI s

r

• In practice lnR/rw often ranges between 7 and 8 , hence the simplified form :

7 87 8th

PIFe toPI s s

• A skin factor of 7 to 8 therefore corresponds to a flow capacity that has been divided by two. A factor of 14 to 16 therefore means it has been reduced by two-thirds. In contrast, a skin factor of -3.5 to -4 (after well stimulation for example) means that it has been doubled.

1-3 Major types of completion 1-3 Major types of completion configurationsconfigurations• 1. The purpose of completion is to enable wells to 1. The purpose of completion is to enable wells to

be exploited as rationally and economically as be exploited as rationally and economically as possible and it can involve a large number of possible and it can involve a large number of configurations. In selecting the type of configurations. In selecting the type of completion, certain principles of relativity and completion, certain principles of relativity and anticipation must be kept in mind:anticipation must be kept in mind:

(1) How do completion and maintenance costs (1) How do completion and maintenance costs compare with expected profits?compare with expected profits?

(2) How does a possible money-saving measure (2) How does a possible money-saving measure compare with the risks it implies? Is the risk worth compare with the risks it implies? Is the risk worth taking?taking?

(3) How will the production of the field and of the (3) How will the production of the field and of the given well evolve in theory ?given well evolve in theory ?

• 1-3-1 Basic requirementsAbove all the completion configuration must be able to

solve the following problems effectively: (1) maintain borehole wall stability (2) ensure selective production of the fluid or formation (3)create a minimum amount of restrictions in the flow

path (4) ensure well safety (5) allow the well flow rate to be adjusted (6) allow operations to be performed on the well at a later (7) make work-over easier when it does become

necessary

• 1 bore-hole wall stabilityThis point is self-evident for wells with wall

stability problems from the beginning. For some bore-holes , wall stability may deteriorate with time due to various factors (depletion, water, cut, etc). even in this case, it is important for the problem to solved as soon as the well is brought on stream to maintain technical efficiency and avoid costly work-over jobs.

• 2 SelectivityThe problem may either involve one bore-hole that

penetrates several reservoir formations or one reservoir containing several fluids. It is necessary to understand the reservoir and its behavior over time , especially in the second case.

The contrast in mobility (ratio between permeability and viscosity for a given fluid )

between the target fluid and the other fluids present is also a very important parameter. It is particularly unfavorable for oil and gas.

3. Minimizing restrictions in the flow pathIn the long run all energy consumption in the form of

pressure losses has a negative effect, either in terms of flow rate or natural flow capability. As a result, it is important to endeavor to minimize these restrictions.

• 4 Well safetyHere we mean both safety during completion operations as

such and also safety later on during production. The main points that need to be taken into consideration are the pressure , equipment corrosion and erosion, and effluent toxicity.

5. Flow adjustmentDuring production the flow of a well needs to be controlled.

In particular reservoir considerations or local regulations may mean that the flow rate must be deliberately limited.

6. Operations at a later dateA number of measurement and maintenance operations ar

e required in order to monitor the reservoir and maintain the means of production . This should be practicable without having to resort to workover. It may also be advisable to be able to carry out certain adaptations or modifications according to the changing operate conditions without having to pull out equipments.

1-3-2 Pay zone-borehole connection: basic configurations

• There are two main types of connections between the pay zone and the borehole:

* open hole completion * cased hole completionHere we will only deal with the general criteria for choosing

between open hole and cased hole systems.However, there are three essential points that should not

be forgotten:• The perforation method ( and the type of perforation )

used if cased hole completion is selected.• The sand control method ,should one be required.• The well stimulation method, if the problem arises.

• 1 Open hole completionThe pay zone is drilled after a casing has been run in and

cemented at the top of the reservoir. It is left as is and produces directly through the uncased height of the borehole. This simple solution can not solve any problems of borehole stability, or selectivity of fluid or level to produced.

A variation on the system consists in placing a perforated liner opposite the producing layer, thereby keeping the borehole walls from caving in. Open hole completions are used where there is only one zone which is either very well consolidated or provided with open-hole gravel packing for sand control. This is valid as long as there are –theoretically at least – no interface problems. Because of this, open hole completions are seldom chosen for oil wells, but it may be suitable to gas well

Open hole completion

• 2 Cased hole completionsAfter the pay zone has been drilled, a casing is run in and

cemented opposite the layer. Then it is perforated opposite the zone that is to be produced in order to restore a connection between the reservoir and the well. The perforations will have to go through the casing and the sheath of cement before they penetrate the formation . The preceding drilling phase was stopped just above the reservoir or at some distance above it and an intermediate casing was then run in and cemented. Cased hole completions are used when there are interface problems and/or when there are several levels. As a result, they are not only much more common, they are the most widespread type of completion.

Cased hole completion

1-3-3 Main configurations of production string

• These configurations basically depend on the number of levels due for production and whether a production string is used (conventional completion ) or not (tubeless completion ).

• 1 Single-zone completionSingle-zone completions with just a tubing and no

production packer are used when the only aim is to have the right pipe diameter with respect to the flow rate.

• 2 Multiple-zone completionsIn the past, the technique of producing

several levels together through the same tubing was used. It required only a minimum amount of equipment. However, the subsequent reservoir and production problems that were experienced have caused this practice to become much less common.

Parallel tubing string completion

• Here several levels are produced in the same time but separately through different strings of pipe. Double-zone completions are the most common, but there can be three, four and even more levels produced separately . However, this significantly complicates the equipment that needs to be run into the well and especially makes any work-over operations much more complex.

Alternate selective completion

• Here the idea is to produce several levels in the same well separately but one after the other through the same tubing without having to resort to work-over. Production alternates in fact and wire-line techniques are used to change levels. This type of completion is especially suited to a situation where one of the two levels is a secondary objective which would not warrant drilling a well.

• Parallel tubing sting and alternate selective completion systems can be combined. For example two parallel tubes, each equipped for two levels in an alternate selective manner, can produce four levels separately , provided that only two are produced at the same time.

3.Tubingless completionsA tubeless completion uses no tubing, but production flows

through a cemented pipe instead. This rather unusual type of completion, which will be covered only briefly here, is mainly used in certain regions and only under specific conditions. There are two kinds: single-zone and multiple-zone tubeless completions. For single-zone tubeless completions, production flows directly through a casing, usually of large diameter. Wells that are big producers of trouble-free fluids can be exploited in this way with minimum pressure losses and the lowest possible initial investment. This system is found in the Middle East. For multiple-zone tubeless completions, production flows directly through several casings whose diameters may be very different from one another depending on the production expected from each level.

Section 2 Connecting the pay zone and the borehole

2-1.Drilling and casing the pay zoneThe pay zone that is going to be produced is by nature poro

us, permeable and contains fluids under pressure. This means that the conditions for a blowout are all present. As such, it is critical to be sure that the drilling fluid in the well has sufficient density to counter the reservoir pressure before starting this phase. Since the pay zone formation pressure is high, so it to important to maintain safety. In practice, at least for development wells, the excess pressure is generally set at around 0.5 to 1.5 MPa.

When the pay zone is being drilled in, the drilling fluid must be treated in order to remove fine-grained solids.

• Completion fluidsThis is the term of the specific fluid that is used opposite the

pay zone, it is designed to cause the least damage possible to the reservoir. it must be pumped into the well before the formation is penetrated, whatever the configuration chosen for the connection between the borehole and the pay zone. This is particularly true and important for sandstone type formations which do not react well to acid. It is often difficulty to formulate a fluid which:

* does not damage the reservoir * provides good characteristic with respect to drillingThe completion fluid is therefore used mainly: * if possible or necessary as soon as the pay zone is

drilled in *during initial completion * to control the well * during work-over, after the well has been produced, to

repair or modify the well

2-2 Perforating2-2-1 The aim of perforating is to re-establish the

best possible connection between the pay zone and the borehole when the chosen configuration is cased hole. Although perforating was done originally by bullets and even though in some very special cases other techniques such as hydraulic perforation may be advantageous, today shaped charges are used almost exclusively. An effective connection depends largely on the perforation method and of the type of support or gun.

• Main parameters affecting the productivity of the zone produced by perforating

1.Number of effective perforationsA fact that is unfortunately often overlooked

is that the important thing is not the shot density but the number of effective perforations . Though there is a relationship with the shot density, it is mainly the conditions lf firing and cleaning that are determining. Wells have been known to have less than 1 to 10% of the perforations effectively flowing.

• 2 Distribution of perforations over the producing zone (partial penetration effect )

This is also a fundamental parameter. 3. Perforation penetration this parameter is mainly significant for a penetration of

less than 0.3 m, but much less so beyond this figure. 4. Number of shot directionGoing from one to two shot directions (located at 180’)

raise the productivity index by about 20%. Beyond this, (three [120’],or four [90’] shot directions), the increase is only slight.

5.Perforation diameterFrom a diameter of 6 mm (0.25m ) and above, this

parameter usually has little impact. However, it is essential because of pressure loss.

2-2-2 Perforating methods and corresponding types of guns

• The choice of the method is the result of a tradeoff between :

1.Well constraints (reservoir pressure, thickness, porosity , permeability and homogeneity)

2.Optimum perforating conditions (which are not necessarily compatible with one another)

3. TCP perforating ( Tubing Conveyed Perforator)We will restrict discussion to the three most

conventional basic methods

• Under-balanced pressure perforating after equipment installation

Perforations are made after well equipment has been run in and once the production tree has been installed, with the well full of a “light” fluid. The guns are run into the well through the tubing by means of an electric cable through a lubricator.

• Overbalanced pressure perforating here a large gun can be run directly through the casing with the following advantages:

* large explosive loads* Multiple shot directions

with close clearance and consequently good geometric characteristics, particularly penetration.

• 3 TCP perforating (Tubing Conveyed Perforator)Here the gun are run in directly with the tubing .

This method combines the advantages of the first two since:

* large diameter guns can be run in * they can be fired with under-balanced pressure

and with the permanent well equipment in place if so desired.

Very ling stretches of casing can also be perforated in one single operation , high shot density can be used, considerable pressure under-balance can be applied, the guns can be run in highly deviated wells.

However, there are some drawbacks that are far from negligible:

• With permanent equipment in the well, if access is required opposite the pay zone for wire-line jobs it is necessary to release the gun after shooting and let it fall to the bottom of the well. This will entail extra costs because a “trash dump” has to be drilled .

• Charges’ temperature resistance and performance decrease with time. Here, since they are run on the tubing rather than with a cable, a lot more time is required to get them to the bottom of the well.

• It is impossible to check that all the charges have been fired except by pulling out the equipment.

2-2-3 Cleaning the perforation• The state of the perforations after firing mainly depends

on the method used for perforating and on the type of the fluid in place in the well.

• Laboratory studies have shown that: * when perforating under-balanced in clean brine, the perf

orations can be made to flow as soon as a pressure differential is exerted. Moreover, there is only a small reduction in the productivity index.

* In contrast, when perforating over-balanced, depending on the type of fluid in the well and the exposure time, the required reverse pressure may be several MPa and the productivity index may be considerably reduced .

When cleaning is required after shooting, one of the methods listed below is usually implemented.

1. Well cleaningThe well is made to flow through a large diameter choke so

that the perforations are exposed to maximum reverse pressure. However, as soon as a few perforations start flowing they limit the reverse pressure that can be applied to others. It is more difficult to lower the bottom-hole pressure and, as it actually becomes lower, the pressure in the reservoir neat the well-bore also tends to decrease. in addition, there would be a risk of detaching fine particles from the matrix, not being able to get them out of the formation and having them plug up inter-pore connections– especially in insufficiently consolidated formations.

2 Back surgingThis technique consists in using a temporary string

equipped with an atmospheric pressure chamber on the lower end. By opening the lower valve, a considerable negative pressure is applied almost immediately to all of the perforations while the flow volume is restricted at the same time.

3 Circulation washing with a washing toolThe perforations are cleaned by circulating from one to the

other beginning at the bottom by means of a tool equipped with cups. The circulating flow rate is in the range of several hundred liters per minute. The technique is mainly used when gravel packing is due to be installed later on for sand control. It is designed to make sure that all the perforations are open, but the circulating fluid and the fines that are stirred up may damage the formation.

4. Acid washingAcid is injected under pressure to restore the connection

between the formation and the well-bore. Acid is pumped down to bottom either before final equipment installation by using a temporary string or after it.

• Conclusion Whatever the cleaning method used, the perforations are

never 100% unplugged and the modifications brought about by treatment may even promote plugging. Additionally, each time that cleaning is undertaken with a temporary string, temporary plugging agents may have to be used afterwards to re-stabilize the well so that the temporary string can be pulled out and the final completion equipment can be run in.

As a result, when the formation itself is not badly plugged up the best way of “cleaning “ the perforations is to perforate under under-balanced pressure conditions after equipment installation to keep from damaging the perforations.