36734159 CSG and Cementing Operations

DRILLING OPERATIONS MANUAL DRILLING PRACTICES

SVP07.DOC SECTION V, PART 7, PAGE i Revision 1, January 1998

CASING AND CEMENTING OPERATIONS

7.0 CASING AND CEMENTING

7.1 Casing Design

7.1.1 Casing Setting Depths7.1.2 Wellbore Geometry7.1.3 Collapse Resistance7.1.4 Burst Strength7.1.5 Axial Tension7.1.6 Buckling Stability Analysis7.1.7 Bi-Axial Stress Effects7.1.8 Casing Wear Allowance7.1.9 Corrosion Considerations

7.2 Cement Slurry Design

7.2.1 Primary Cementing7.2.2 Squeeze Cementing7.2.3 Kick-off and Abandonment Cement Plugs

7.3 Casing Installation and Cementing

7.3.1 Hole Conditioning7.3.2 Pre-Job Checks7.3.3 Casing Installation7.3.4 Casing Cementing7.3.5 Casing Pressure Testing

7.4 Casing and Cementing Checklist

7.4.1 Pre-Job Checks7.4.2 Hole Conditioning Prior to Cementing7.4.3 Tripping Out To Run Casing7.4.4 Cementing Casing


SVP07.DOC SECTION V, PART 7, PAGE 1 Revision 1, January 1998


7.0 CASING AND CEMENTING

This section is intended to serve as an operations guide for the Drilling Supervisor as well asa design tool for the Drilling Engineer. The material contained in this section provides generalguidance for the planning and execution of casing and cementing operations conducted byOccidental.

7.1 Casing Design

Casing design is to be performed on a well by well basis. There are no universal casing designprocedures that will enable mechanical determination of an acceptable casing program for aparticular well. However, a certain degree of standardization is usually possible in the caseof single site, multi-well development drilling projects where many of the "unknowns" arewell defined and casing programs can be developed more on the basis of completion geometrythan on anticipated drilling problems.

The need to treat each casing design as unique cannot be overstated. This is particularly truein exploration areas where the chosen casing program can have a significant impact on wellcontrol operations. The purpose of this section is to provide a drilling professional withsufficient practical information to form the basis of a well designed casing program.

7.1.1 Casing Setting Depths

Casing setting depths are to be established following determination of the porepressure and fracture pressure profiles for a particular well. For exploration wells, thewell data is to be based upon the best available data. Once these two pressure profileshave been defined, selection of casing setting depths is usually a routine procedure. In addition, offset well data is to be closely scrutinized for problematic intervals thatmay be encountered in the planned well. Information of particular interest would be:

- zones of whole mud losses and the loss mechanism (e.g., permeability, naturalor induced fractures, depleted pore pressure)

- tight hole sections, suggesting fluid sensitive shales or overpressure

- zones susceptible to differential sticking

- intervals of high formation gas that may impact successful primary cementing




This information, together with the planned mud density schedule for the well, shouldenable selection of optimum casing setting depths. Once the casing setting depthshave been determined, the following calculation is to be performed for each casingsetting depth to determine if adequate kick tolerance will be available to drill to thatparticular casing point.

K = (Dc/Db) x (FG - SF - MW) - Tm

Where: K = kick tolerance at depth of interest, ppg EMWDc = depth of previous casing shoe, TVDDb = depth of interest, TVDFG = fracture gradient at casing shoe, ppg EMWSF = safety factor, ppg EMWMW = mud density at depth of interest, ppgTm = trip margin, ppg

In general, the safety factor and trip margin are to be determined in accordance withthe guidelines established in Section VI, Well Planning - Mud Density, which areas follows:

A. A minimum overbalance pressure of 0.5 ppg EMW is to be specified from themudline to +/- 7500' TVD RKB. Below 7500' TVD RKB, a minimumoverbalance pressure of 200 psi is recommended when formation strengthspermit.

B. A trip margin, in excess of overbalance pressure, is to be specified for alldepths and should take account of wellbore geometry, annular clearances,drilling fluid density and rheological properties, and pipe tripping speeds. Ingeneral, a minimum trip margin equivalent to the anticipated swab pressureis to be used. However, this value is to be increased if dictated by wellspecific conditions.

Using these guidelines, if the calculated kick tolerance at each new casing point is lessthan 0.5 ppg EMW, the casing setting depth is to be altered until the kick toleranceis equal to or greater than 0.5 ppg EMW. Use of the kick tolerance equation isillustrated as follows.

Well Data (Vertical Well):

13-3/8" casing set at: 6500' MD RKBLeak-off test at casing shoe: 15.3 ppg EMWNext casing point: 10,500' MD RKB




Mud density at next casing point: 12.7 ppgEstimated trip margin: 0.25 ppg EMWSafety factor at 9-5/8" casing point: 200 psi

Calculate Kick Tolerance:

Safety Factor in ppg EMW = 200/(0.052 x 10500) = 0.366 ppg

K = (Dc/Db) x (FG - SF - MW) - Tm

= (6500/10500) x (15.3 - 0.366 - 12.7) - 0.25

K = 1.13 ppg EMW, which is acceptable.

7.1.2 Wellbore Geometry

Wellbore geometry can vary significantly between land and offshore operations. There can be many variations of the wellbore geometry between wells because offormation characteristics, formation pressures and depth of the well. Thenomenclature for a casing string should be compatible with the Occidental reportingsystem and data base. The nomenclature will be derived based upon the number ofcasing strings that are planned or are included as a contingency.

The following is a typical example of an offshore well.

Structural Pipe : 30" diameter

Conductor Casing : 20" diameter

Surface Casing : 13-3/8" diameter

Intermediate Casing : 9-5/8" diameter

Production/Drilling Liner : 7" diameter

Production Liner : 7" or 5" diameter, as required

The combinations of this casing program are illustrated in Figures 7.1 and 7.2. Finalwellbore geometry must take into account total project economics. In addition,selection of wellbore geometry must take into account the following considerations,which will have a significant impact on realizing planned objectives.




Figure 7.1: Example Exploration Casing Program




Figure 7.2: Example Development Casing Program




A. Structural and conductor casing must be of sufficient strength to provideadequate support for the following externally applied loads:

1. Environmental loads due to wind, waves, current, and temperature.

2. Axial loads due to the weight of casing strings, blowout preventerstacks, wireline equipment, coiled tubing units, and snubbing units.

3. Bending moments due to the lateral movement of axial loads orthrough the application of external forces; for example, bendingmoments exerted on subsea wellheads due to rig offset.

B. Casing diameters must allow for adequate clearance between rotary drillingtools and the inside diameter of the casing. In addition, allowance must bemade for the annular clearance necessary to use standard fishing tools.

C. Having decided on an acceptable wellbore geometry, the expected annularpressure losses and surge and swab pressures for each hole section must bedetermined. These calculations should be performed using the planned drillingassemblies and drilling fluids program for each hole section.

D. The final casing program must take into account the planned completionconfiguration, which will, in many cases, automatically define the casingprogram. If the well will not be held for production, then the primary concernwill be to ensure that well testing objectives can be realized within theconfines of the planned wellbore geometry.

E. When planning exploration wells, sufficient allowance must be made forunanticipated drilling problems that would require the installation of aprotective string of casing. This requirement will often result in the use oflarger than necessary casing diameters, but may avoid the need to redrill a welldue to the limited hole size available to reach the planned objective. As moreexperience is gained in a particular area, the need to allow for contingencyprotective pipe can be relaxed.

7.1.3 Collapse Resistance

The collapse resistance of tubular goods is ordinarily expressed in terms of theminimum external pressure that must be applied in order to initiate permanentdeformation of the pipe body. The means of determining the collapse resistance oftubulars is dependent on a number of factors including API grade, outside diameter,wall thickness, and minimum yield strength. The API has developed a number of




methods for calculating the collapse resistance of pipe using both practical andtheoretical techniques. While no attempt is made in this section to delve into thesetechniques, the reader should be aware that the collapse failure mechanism will notbe the same in all cases. While the difference between these failure mechanisms willnot adversely impact the vast majority of casing designs, critical service applicationsshould be closely scrutinized to ensure that the possibility of unexpected failure incollapse does not occur.

Collapse loadings can be exerted on a section of pipe under the following conditions,which may or may not occur simultaneously.

A. Applied Differential Pressure

Applied differential pressure is generated through application of surfacepressure to the annular void space of a string of pipe in excess of the pressurepresent on the inside of the pipe. This condition is most critical during BOPand wellhead pressure testing operations where failure of an annulus pack-offseal could result in applying sufficient pressure to cause the pipe to collapse.

B. Differential Hydrostatic Pressure

Differential hydrostatic pressure is produced due to a difference in averagefluid density between the inside and outside of a string of casing. Thiscondition is a critical concern for gas lifted wells where, under certainconditions, the equivalent fluid density inside the casing can be reduced tonothing more than a gas fluid gradient. Hydrostatic pressure below a packerin an electrical submersible pump should be assumed to be zero as thiscondition often occurs on pump start up.

C. Wellbore Curvature

Changes in hole angle that result in bending of the pipe body produce loadingconditions that reduce the collapse resistance of tubulars. This condition isseriously aggravated through intervals of high angle change (i.e., high doglegseverity).

D. Formation Matrix Flow

This condition is characterized by plastic flow of the rock matrix against theouter surface of the pipe body resulting in severe stress loading of the tubular.Salt flows are widely known to produce this condition, although flows ofclaystone formations and active faults can produce similar results.

E. Heating of Confined fluids




The heating of fluids confined in annular void spaces (for example, betweena casing x casing cement top and wellhead pack-off) can generate pressureincreases of sufficient magnitude to collapse casing. Ordinarily these pressureincreases are not large enough to cause concern. However, the wide variancein temperature profiles generated under drilling and production conditionsdictates that the magnitude of anticipated pressure increase be evaluated forevery well.

Additional mechanisms leading to collapse failure can occur due to acombination of dynamic loading conditions that are ordinarily addressedwithin the context of buckling failure analysis. These failure modes will notbe discussed here, but rather are deferred to a subsequent part.

Each of the collapse loading conditions discussed above must be addressed ona well by well basis. It is simply not adequate to accept a particular casingdesign for broad application within an operating area. Adopting such anapproach increases the likelihood that catastrophic equipment failure willeventually occur, which could, in certain cases, result in unmanageableconsequences.

When designing for collapse resistance, the following guidelines are to befollowed.

1. A minimum design safety factor of 1.125 should be used in all cases.This will result in the casing being subjected to a maximum of 88.88%of its rated collapse resistance under worst case conditions. This safetyfactor must be maintained when allowance has been made for all of theloading conditions mentioned above. In addition, allowance must bemade for anticipated casing wear (Part 7.1.8) and the reduction incollapse resistance due to bi-axial stress affects (Part 7.1.7).

2. The annulus fluid should be assumed to have a density equivalent tothe highest anticipated fluid density while drilling the previous holesection. The fluid column for design calculations is to extend from thesurface to the casing shoe. The physical properties of the annulusfluid are to be used in calculations to determine the impact of wellboreheating.




3. The fluid inside the casing is to be assumed to be gas with a fluidgradient equivalent to 0.150 psi/ft, unless overwhelming technicalevidence can support the use of a higher or lower value. For wellsthat will be gas lifted, the production casing collapse designcalculations are to be performed assuming a gas fluid gradient insidethe casing of zero psi/ft. This will allow for the possibility that gas liftpressure could be completely bled off to zero.

For wells that will be pumped with submersible pumps, the hydrostaticpressure inside the casing below the production packer should beassumed to be zero psi/ft.

4. The anticipated static collapse loading following primary cementationof each casing string should also be taken into account. This isparticularly important for large diameter tubulars which haveinherently low collapse resistance.

7.1.4 Burst Strength

The burst strength of tubular goods is expressed in terms of the minimum internalpressure that must be applied in order to initiate permanent deformation of the pipebody. The expressions "burst strength" and "burst resistance" are really misnomersbecause the pipe generally will not fail at the API specified minimum internal yieldpressure. As the definition states, the minimum internal yield pressure is the minimumpressure at which initial permanent deformation of the pipe wall begins to occur - itis not the point at which failure occurs.

Burst loads are typically generated under the following circumstances:

A. Applied Internal Pressure

Applied internal pressures are commonly generated during pressure testingoperations and well testing (e.g., for the operation of downhole tools). Ingeneral, the application of these pressures can be closely controlled to limitthe potential of accidental pipe body failure.

B. Differential Hydrostatic Pressure

This condition is produced when the average fluid density inside the casingexceeds the average fluid density on the outside of the casing. Although thiscondition is usually not of critical concern, when taken in combination withapplied internal pressure, the need for careful design review is clearly evident. Considerations should also be given to lost circulation reducing thehydrostatic pressure outside the casing.

C. Unexpected Release of Formation Pressure




This condition generally occurs during well testing operations when theprimary test string fails, resulting in flowing wellhead pressure being exertedon the production casing. Generally this does not present a problem since theproduction casing is ordinarily designed to tolerate such a condition.

D. Packer Setting Forces

Packer setting forces can produce excessive burst loadings on tubulars,particularly when the slip load area is small relative to packer setting forcesand casing strength.

In addition to these burst loading conditions, the designer must thoroughlyconsider all possible modes of burst loading that may be produced during theuseful life of a well. This is generally a straightforward procedure in the caseof exploration wells; however, long term production wells generallyexperience multiple operating scenarios which must be addressed at the designstage.

When designing for burst resistance, the following guidelines are to befollowed:

1. In general, a minimum design safety factor of 1.1 should be used. Thiswill result in the casing being subjected to a maximum of 90.9% of itsminimum internal yield pressure rating under worst case operatingconditions. This safety factor must be maintained when allowance hasbeen made for all of the loading conditions mentioned above. Inaddition, allowance must be made for anticipated casing wear (Part7.1.8).

2. The annulus fluid should be assumed to have a density equivalent toconnate water. For most offshore operations a static fluid gradient of0.4446 psi/ft (8.55 ppg EMW) is to be used. For most landoperations a static fluid gradient of 0.465 psi/ft. (8.94 ppg EMW) isto be used.

3. The fluid inside the casing is to be assumed to be gas with a fluidgradient equivalent to 0.150 psi/ft, unless overwhelming technicalevidence can support the use of a higher or lower figure.

4. The maximum wellhead pressure during drilling operations is to be thelesser of the following calculated pressures:




a. The pressure produced by the maximum anticipated formationpore pressure for a particular hole section less a gas gradientto the wellhead.

b. The pressure produced by the maximum anticipated leak-offpressure at the casing shoe, less a gas gradient to surface.

5. For exploration wells, the maximum burst loading is to be determinedbased on the assumption that the well is tested and a leak develops inthe test string at the wellhead. The drill string safety valves fail tooperate, and the pressure trapped at the wellhead is then transmittedthroughout the entire annular fluid column to the test packer. Thisloading condition superimposes a static surface pressure on top of thedifferential pressure resulting from the difference in fluid densitiesbetween the inside and outside of the casing. As a result of thissuperposition of pressures, the burst loading above the packer mayexceed the burst loading at the wellhead.

6. For development wells, the burst design criteria discussed in (5) maybe relaxed. The worst case burst loading is to be determined using themaximum wellhead pressure determined in (4) unless well specificconditions indicate more stringent requirements.

7.1.5 Axial Tension

Axial tensile loads are produced by forces acting along the longitudinal axis of thecasing. Resistance of tubular goods to tensile failure is expressed in terms of pipebody yield strength and joint strength. In most cases, the joint strength for aparticular tubular product meets or exceeds the pipe body yield strength, but this isnot always the case. The designer must be certain to use the lesser of joint strengthor pipe body yield strength when specifying tubulars acceptable for a particularapplication.

Tensile loads are generated in tubulars under the following well condition, which mayor may not occur simultaneously:

A. Suspended String Weight

This is the load generated along the axis of the pipe due to its own weight.Ordinarily, this loading does not impose any adverse design constraints.

B. Applied Internal Pressure




Applied internal pressure tends to balloon the casing and generatesincremental tensile loading throughout the full length of the pipe. A moresevere condition is created during primary cementation when the topcementing plug lands and excessive casing pressure is applied. Under theseconditions incremental tensile loading is superimposed onto the static weightof the casing, producing high axial loads.

C. Applied Tensile Loads

Applied tensile loads are generated in a number of ways including:

1. Overpull to free stuck pipe

2. Incremental surface tension to prevent buckling

3. Packer slack-off weight (in uncemented pipe)

4. Liner hang-off weight (in uncemented pipe)

D. Induced Tensile Loads

Induced tensile loads are produced through a number of mechanisms which,in many cases, are not accounted for in the typical casing design. These loadscan result in a net increase or decrease in the magnitude of casing tension. Thefollowing are examples of conditions which increase or decrease themagnitude of tensile loading :

1. An increase or decrease in the average wellbore temperature throughintervals of uncemented pipe.

2. An increase in mud density during subsequent drilling operations thatis in excess of the mud density in the casing annulus.

3. Bending of tubulars through intervals of hole angle change.

4. Shock loads induced by rapid deceleration of pipe and setting of slipswhile running casing.




E. While the above loading conditions will cover the majority of tensile forcesexperienced in practice, well specific conditions may impose additional,unexpected forces. It is the responsibility of the casing designer to thoroughlyunderstand the anticipated operational characteristics of a well, and theconsequences these characteristics have for acceptable tensile designconditions.

When designing for tensile strength, the following guidelines are to befollowed.

1. The minimum acceptable design safety factor in tension is to be 1.6.This will result in the casing being subjected to a maximum of 62.5%of the joint strength or pipe body yield strength, whichever is lower.

2. Calculation of the maximum anticipated tensile loading is to takeaccount of the following forces acting simultaneously :

Casing Weight: Total unbouyed weight of casing withallowance for hole angle.

Pick-up Drag: Maximum anticipated pick-up drag takingaccount of hole geometry.

Bending Force: Maximum anticipated bending force for theplanned hole geometry.

Overpull Allowance: The planned degree of available overpull to freethe casing in the event of sticking.

3. Pipe running loads induced by wellbore deviation are to be taken intoaccount. In particular, the effects of hole drag (both up an down) areto be taken into consideration. For floating rig operations, the degreeof uncontrollable up-drag may significantly impact casing design.

4. The degree of shock loading induced by the planned casing runningspeeds is to be determined. If these loads are sufficiently high, theplanned casing running speeds are to be reduced until an acceptableloading condition is obtained. In certain cases, it will be prudent tosubstitute shock loading for pick-up drag in the maximum anticipatedload calculation performed in (2) above.




5. For water injection wells, or wells programmed for injectivity testing,the degree of incremental casing tension induced by the cooling effectof injection water is to be determined. This force is to be added to thestatic wellhead tensile force without consideration for dynamicloading.

7.1.6 Buckling Stability Analysis

Buckling stability analysis is critical to ensuring the success of any drilling operation.It is not enough to perform the design calculations required for burst, collapse, andtension only to ignore the possibility that the pipe will fail due to buckling instability.Buckling instability is generally a condition that presents itself long after the casinghas been cemented, and frequently after the rig has moved off location. Tubularfailures attributed to buckling instability occur without warning and with catastrophicresults.

Well conditions leading to buckling instability generally occur following primarycementation of a string of casing. The primary factors contributing to bucklinginstability are as follows:

- Changes in fluid densities inside and/or outside a string of pipe.

- Changes in surface pressure inside and/or outside a string of pipe.

- Changes in average well temperature.

- Uncemented casing through intervals of significant hole enlargement.

Other factors to be considered are:

- Compressibility rating of a connection with buoyancy effects and/or hangingup when running in the hole.

The time to assess the need for preventative measures to deal with buckling is duringthe planning stages for a particular well. Buckling instability can generally be resolvedthrough application of any one, or a combination, of several simple techniques duringthe primary cementing operation. However, in the case of subsea operations, oncethe cement takes an initial set, the opportunity for corrective action has been lost.

Common techniques for eliminating the possibility of buckling stability failure are:

A. Raise the column of primary cement above the calculated neutral point. Itshould be noted that the neutral point in this context is not the point of zero




axial stress. The neutral point in buckling stability analysis is the point atwhich the axial stress is equal to the average of the radial and tangentialstresses.

B. Maintain internal pressure on the casing while the primary cement takes aninitial set. The magnitude of applied pressure must be calculated to suit thespecific well conditions.

C. For surface operations, where "throw in" slips will be used to suspend thecasing, application of a suitable overpull prior to setting the slips will normallyremedy a buckling stability problem. The degree of overpull must becalculated based on specific well conditions.

D. Ensure that the casing is adequately constrained from lateral movementthrough the use of positive stand-off centralizers. This technique is the leastdesirable of the four techniques mentioned here and should be used only as alast resort.

Based on the above discussion, it is apparent that one of the most vulnerable pointsin a well, relative to buckling failure, is the rathole section below the previous casingshoe. In many cases, cement is not brought up inside the previous casing shoe inorder to prevent the possibility of pressure build-up in the confined casing annulusduring subsequent operations. Although the desired pressure relief valve is nowavailable (i.e., formation leak-off pressure at the casing shoe), the ideal conditions forbuckling failure have been created. The decision to not cement inside the previouscasing shoe must be a considered one, following careful design analysis.

7.1.7 Bi-Axial Stress Effects

Combined loads due to tension and pressure can produce in-service conditions wherethe performance properties of tubulars are exceeded, although design calculationssuggested that this would not be the case. This is due to common casing designprocedures which evaluate tubular loading conditions in one dimension; i.e., tensile,collapse and burst loads are all considered independently. This design procedure isencouraged by specifications for tubular performance properties, which are generallygiven in one dimension with no allowance for combined loading conditions.In certain well applications, tubular performance properties are so adversely effectedby simultaneous loading conditions that allowance must be made for loss of strength. This is particularly true with respect to collapse resistance. If collapse resistance iscritical to the success of a particular project, then the reduction in collapse resistancedue to bi-axial stress must be determined.




The API has developed a technique for determining the reduced collapse resistanceof tubulars manufactured according to API specifications. The procedure is beyondthe scope of this manual, but the reader is referred to API Bulletin 5C3, Bulletin onFormulas and Calculations for Casing, Tubing, Drill Pipe, and Line PipeProperties, for guidance on application of the technique to a particular casing design.

7.1.8 Casing Wear Allowance

Casing wear in drilling operations is due primarily to the rotation of drill pipe tooljoints against the casing wall. In highly deviated wells the drill pipe body will beginto contact the casing wall, but pipe body induced wear is generally negligiblecompared to tool joint wear.

The degree of drill string induced casing wear is critically dependent on the type ofhardbanding (also called hardfacing) applied to the tool joints in use on a particularwell. Care must be exercised in the selection of hardbanding materials and in theprocess of application to tool joints. In all cases, a smooth weld, flush with theoutside diameter of the tool joint, should be selected. Flush hardbanding will resultin a more uniform load distribution along the length of the tool joint, thereby reducingthe severity of casing wear.

When planning operations to limit the degree of drill string induced casing wear, thefollowing practices are to followed:

A. Plan directional wells to limit the degree of dogleg severity. In general, thedogleg severity for conventional directional wells should not be planned toexceed 3.0 degrees/100 feet.

B. Use tool joints with smooth overlay hardfacing. If possible, "wear in" newpipe in the openhole section of the well.

C. Minimize the volume of sand and coarse formation solids retained in thedrilling fluid through active use of the solids removal equipment. Thesematerials aggravate the degree of drill string induced casing wear and shouldnot be tolerated. In particular, maintain the sand concentration at less than0.5 percent.

D. The effects of drill string induced casing wear should be accounted for byusing heavier wall casing. Casing design programs are on the market that willcalculate casing wear.

7.1.9 Corrosion Considerations




All casing designs should include a thorough assessment of the degree of corrosionprotection required to ensure that minimum acceptable casing performance propertiesare maintained throughout the useful life of a well. Frequently, as in the case of majorfield developments, this will require considerable laboratory testing of casing materialsunder simulated well conditions.

Corrosive agents that impact casing design include produced hydrogen sulfide, carbondioxide, and connate water, as well as surface injected materials includinghydrochloric acid, hydrofluoric acid and oxygen. The concentration of thesereactants, and the tubular metallurgy selected to cope with production conditions, willhave a direct impact on total project economics and the long term mechanical integrityof the wellbore.

Factors that effect the degree of corrosion include: concentration of the corrosivereactants, temperature and pressure, and the velocity and pH of fluids passing overthe material surface. Since corrosion reactions are very complex processes, there areno universal guidelines for assessing the performance of steels when subjected to aparticular set of well conditions. However, there is a growing body of informationon designing for corrosion resistance, and this material has been summarized in thissection.

Hydrogen Sulfide Induced Corrosion

The selection of tubular steels for use in hydrogen sulfide environments is critical tomaintaining the performance properties of these materials. H2S induced casingfailures are usually catastrophic, resulting in the expenditure of considerable time andmoney to reinstate a well to operational status.

The mechanisms and conditions under which hydrogen sulfide leads to mechanicalfailure of oil-field tubulars are still not completely understood. Materials that haveproven to be acceptable in one application, often fail under similar conditions inanother area. Although general guidelines exist for the evaluation of H2S resistantmaterials, project specific laboratory testing of casing material coupons must beperformed in critical service applications. These tests should closely model theanticipated well conditions with particular attention given to the partial pressure ofgases, composition of the liquid phase, flow conditions, test coupon geometry, andmaterial surface finish.

Hydrogen sulfide induced failures normally fall under three broad classifications:sulfide stress cracking (SSC), stress corrosion cracking (SCC) and hydrogenembrittlement (HE). Sulfide stress cracking results in failure due to brittle fracturingof high strength steels. Stress corrosion cracking leads to failure of tubulars due to




high levels of localized corrosion and stress. Hydrogen embrittlement is normallyassociated with failures that occur at stresses below the specified yield strength of aparticular material due to a loss of ductility.

The National Association of Corrosion Engineers (NACE) has issued standards forthe selection of materials resistant to hydrogen sulfide induced failure. The reader isreferred to NACE Standard MR-0175-94, section II on Drilling and Well ServiceEquipment, for further guidance.

When using NACE Standard MR-0175-94, the reader should not interpretqualification to this standard as granting universal acceptance of a particular materialfor all H2S environments. Rather, the standard sets very narrow limits of acceptabilityand only states that sulfide stress cracking should not occur within the specifiedoperating limits. Do not read more into MR-0175-94 than is actually there.

In general, when assessing the suitability of steels for H2S environments, the followingguidelines (as per NACE MR-0175-94) are to be adhered to:

A. For sour gas production, if the anticipated partial pressure of H2S exceeds0.05 psi, tubular goods are to be selected for resistance to H2S.

B. For sour oil and multi-phase systems, H2S resistant materials are to be selectedunder the following conditions:

1. The maximum gas/liquid ratio is 5000 scf/bbl or higher.

2. The gas phase contains a maximum H2S concentration of 15% byvolume or greater.

3. The partial pressure of H2S in the gas phase is 10 psi or greater.

4. The surface pressure is 265 psi or greater.

C. Specify materials with a maximum hardness on the Rockwell C scale of 22.However, it should be noted that certain steel metallurgies may be acceptableup to HRC = 26. Therefore, don't rule out a particular material on the basisof Rockwell hardness alone.

It is commonly accepted that the suitability of most grades of steels for H2S serviceimproves with increasing temperature. The research supports this view with respectto hydrogen embrittlement (HE) induced failure, where higher in-service temperaturestend to diffuse absorbed atomic hydrogen out of the steel matrix. However, high




temperatures enhance the susceptibility of steels to stress corrosion cracking(SCC). For this reason, the reader should have a complete understanding of thefailure mechanism(s) at work under a given set of well conditions. Contact the OxyCorrosion - Materials Specialist for the right material selection.

Chloride Induced Corrosion

The presence of chlorides in produced well fluids tends to accelerate or enhance thedegree of all other corrosion reactions. As a stand alone corrosive agent, chlorideswill promote a high degree of general corrosion, pitting, and crevice corrosion. Thesecorrosion mechanisms are further accelerated in the presence of oxygen. For thisreason, injected solutions high in chloride ion concentration should be adequatelytreated to remove entrained oxygen. This is critically important in water injection andwell stimulation operations. As with most corrosion reactions, the rate of chlorideinduced corrosion increases with increasing temperature. In general, the degree ofchloride induced corrosion can be alleviated through control of oxygen content andby alloying steels with chromium and nickel.

Carbon Dioxide Induced Corrosion

Carbon dioxide, which forms carbonic acid when mixed with water, is a highlycorrosive material in the presence of oil-field tubulars, even at low concentrations.Carbon dioxide ordinarily produces general weight loss corrosion, although in thepresence of chlorides, severe pitting corrosion and stress corrosion cracking (SCC)can occur.

CO2 corrosion attack is primarily a function of the partial pressure of the gas in theproduced flow stream. In addition, corrosion rate is particularly sensitive totemperature, being accelerated at elevated temperatures. Small increases in eitherCO2 partial pressure or temperature, can produce an order of magnitude increase incorrosion rate.CO2 corrosion attack is particularly severe in thread areas, across material sectionswhere there has been an abrupt change in metallurgy (e.g. tubing and nipples ofdissimilar metallurgy), and in areas where there is a significant change in the flowcharacteristics of the produced fluids (e.g., through couplings, downhole safetyvalves, and nipples).

In general, CO2 corrosion attack of oilfield tubulars is treated with the selection of theright tubing. This could be full body normalized tubing or tubing with increased levelsof Chromium which is known to resist CO2 flow induced corrosion.

Effect of pH on Corrosion




While pH, in and of itself, is not a direct cause of corrosion, the level of pH (whetheracid or base) will have a direct impact on the rate of corrosion and the type ofcorrosion reaction(s) (i.e., pitting, general weight loss, stress corrosion cracking, localattack, etc.). Low pH leads to an increase in general corrosion rates and increases thesusceptibility to stress corrosion cracking and sulfide stress cracking.

While little can be done to alter the pH of produced fluids, treatments to reduce pHare generally accomplished through downhole chemical injection systems. However,the pH of drilling and completion fluids left behind pipe can be adjusted as the fluidis spotted in place. In general, the pH of fluids left behind pipe for prolonged periodsshould be elevated to a minimum value of 10.0.

Sulfate Reducing Bacteria, (SRB's)

All surface waters (i.e. drilling fluids and completion fluids) contain SRB bacteriawhich are known to enhance H2S production. To avoid contamination of SRB's andH2S in the wellbore or reservoir all drilling fluids left behind the casing and allcompletion fluids left inside the casing should be treated with a suitable biocide toeliminate SRB bacteria.

Dissolved Oxygen Corrosion

Oxygen in water increases general and pitting corrosion by a factor of x 8. Thereforeall drilling fluids left behind the casing and all completion fluids left inside the casingshould be treated with an oxygen scavenger to avoid pitting corrosion.

For 1 p.p.m.v. of oxygen, 8 p.p.m. of oxygen scavenger should be used.

7.2 Cement Slurry Design

Planning for cementing operations, and the design and specification of acceptable cementslurries, must be performed based on project specific well conditions. To adopt standardizedcement slurry formulations is generally a recipe for disaster, since there will always be the onewell that does not fit the standard mold. Furthermore, well by well planning should lead totechnical optimization of cementing programs which will generally result in the most costeffective slurry formulations. This section is designed to offer general planning guidelines forrealizing technical and economic objectives.

7.2.1 Primary Cementing




Primary cementing operations offer the greatest opportunity for minimum cost zoneisolation. This can only be accomplished through careful evaluation of all variableseffecting the operation including zones of lost circulation, formation damagesensitivity, rheological properties of the cement slurry and spacer, hole conditioning,and wellbore geometry, to mention a few. This section offers specific guidelines forthe design of cementing programs which will increase the probability of realizingplanned objectives.

A. Lead Slurry Design

Lead slurries are generally thought of as scavenger slurries designed as a typeof "pre-flush", and used to condition the formation and casing surfaces priorto placement of the tail slurry. This is true to a certain extent; however, thelead slurry performs several other critically important functions, including:

1. Providing mechanical support for the upper section of the casing stringto prevent buckling failure during subsequent drilling and/orproduction operations.

2. Isolating potential cross-flow between shallow zones that wouldotherwise produce adverse corrosion and potential long term casingfailure.

3. Reducing the degree of potential collapse loading that can be exertedon the casing during subsequent drilling and/or production operationsby isolating the hydrostatic head of drilling mud above the cement top. Once the cement sets, hydrostatic pressure due to the drilling fluidcan no longer be transmitted below the cement top.

B. Tail Slurry Design

Tail slurries are designed to provide maximum early and ultimate compressivestrength. The mechanical integrity of the solidified tail cement is generallycritical to successful execution of subsequent operations whether they becontinued drilling or completion for production. The primary functions andcharacteristics of the tail cement are as follows:

1. To provide mechanical and hydraulic isolation between permeableintervals through formation of a solid, low permeability cement sheathbetween the wellbore and casing.




2. To provide adequate mechanical support of the formation and casingto permit subsequent drill-out or production operations. This isparticularly important with respect to mechanically weak producingformations that would otherwise slough into the wellbore.

3. To retain adequate mechanical strength following perforatingoperations to maintain support of the casing and provide for continuedzone isolation.

C. Cement Slurry Design Guidelines

Whether designing lead or tail slurries, several properties and designconsiderations must be reviewed to ensure job success. The following listprovides general guidance for the design and planning of successful cementingoperations. When reporting cement slurry test results, the reporting formatgiven in Table 7.1 is to be followed.

1. Thickening time tests are to be performed at the maximum anticipatedbottom-hole circulating temperature for the casing size underconsideration. If field measurement of bottom-hole circulatingtemperature is not possible, then this figure is to be estimated usingthe API circulating temperature tables given in API Specification 10.It should be noted that these tables are only an approximation basedon compilation of a considerable amount of field data. Therefore, itmay be appropriate in critical situations to consult with offsetoperators or the cementing contractor to determine if more accuratedownhole temperature data is available.

For all thickening time tests, the elapsed time to 80 and 100 Beardenunits of consistency (Bc) is to be measured in hours and minutes, withthe 100 Bc figure taken as the measured thickening time. Thedifference between the 100 Bc and 80 Bc times is to be used as anindication of the time period during which the cement slurry changesfrom a pumpable to an unpumpable condition. Both the 80 Bc and100 Bc measurements are to be reported on all thickening time tests.

2. Thickening time is to be specified to allow for mixing and placementof slurries, plus an allowance for possible equipment failure anddowntime. In general, slurry mix rates of 6-8 bbl/min should beallowed for in design calculations. If the cement density is +/- 14 ppgor higher, then use 6 bbl/min. For lighter weight slurries in the +/-12.0ppg range, use 8.0 bbl/min. These rates are based on maximum




pumping rates that can be reasonably achieved in the field with aconventional re-circulating mixer, while still maintaining uniformslurry density. On this basis, thickening time requirements are to becalculated as the sum of the following:

Thickening Time = Total lead slurry mixing time +(lead slurry) Total tail slurry mixing time +

Time to launch top plug +Spacer pumping time +Displacement time +Equipment breakdown time

As a rule of thumb, 15-30 minutes should be allowed to launch the topcementing plug, and one hour should be allowed for equipmentbreakdowns. The other time elements will have to be calculated basedon the fluid volumes to be pumped and the planned pumping rates.

Tail slurry thickening time can be calculated using the equation above,but with the lead slurry mixing time set equal to zero.

3. Fill-up height is to be based on the size of casing to be cemented,casing stability requirements and collapse loading considerations. Ifcement is overlapped into the previous casing shoe, then it must beensured that the collapse resistance of the casing being cemented isnot exceeded as the mud in the annulus above the cement top is heatedduring subsequent drilling and/or production operations.For 30" and 20" casing as applicable on offshore wells, fill-up is to bespecified to the mud-line. The fill-up height for all other casing stringsis to be determined on the basis of well specific requirements.

4. Displacement rates are to be specified based on the maximum pumpingrate that can be obtained without exerting sufficient annulus pressure(due to circulating pressure losses) to break-down the formation andlose returns. Computer modeling of allowable pump rates is to beperformed as part of the planning process to enable accuratespecification of cement rheological properties to meet thisrequirement.




5. Cement additive concentrations are to be determined to ensureadequate pumping time and optimum rheological properties. Rheological properties of the cement are to be specified to ensure thatthe cement is in turbulent flow during placement in the casing annulusat the rates established in (4) above.

6. For slurries that will contact producing formations, slurry design mustinclude the addition of fluid loss additive to limit the degree of filtrateinvasion into productive intervals. For the applications describedbelow, API fluid loss determined at 1000 psi differential pressureshould be as follows:

a. To prevent gas channeling, specify 20 ml/30 minutes, or less.

b. For liners, specify 50 ml/30 minutes, or less.

c. For primary cementing of casing through productive intervals,specify 250 ml/30 minutes, or less.

d. For primary cementing of casing through non-productiveintervals, specify 250-500 ml/30 minutes.

Each fluid loss test should be performed at the anticipated bottom-hole circulating temperature, with the exception of the slurry designedto prevent gas channeling, which should be tested at the anticipatedbottom-hole static temperature.

7. The API free water content of all slurry designs shall be 1% or less,except in the case of slurries designed to prevent gas channeling, inwhich case the allowable free water shall be zero percent. This appliesto vertical as well as inclined free water tests.

8. The cement slurry density should be specified to be as high as possiblethroughout the cemented interval without causing formationbreakdown during placement. In general, the cement density shouldbe a minimum of 1.0 ppg heavier than the drilling fluid density in thehole at the time of cementing.

9. For tail cements, the slurry is to be designed to develop high early andultimate compressive strength. If the casing shoe is to be drilled out




and the well deepened, then cementing additives are to be adjusted toproduce a minimum of 500 psi compressive strength prior to pressuretesting or drill out operations. In addition, 2000 psi of compressivestrength must be reached prior to perforating any well for production.

Lead cements are to be designed to develop a minimum earlycompressive strength of 500 psi within 24 hours of placement,provided the lead slurry is not required to support casing loads. Iftension is to be applied to the casing as part of a casing landingprocedure (e.g., surface installations), then it must be ensuredthat the cement has developed a minimum compressive strengthof 500 psi prior to tensioning the casing.

For liner cementing, compressive strength development must bedetermined not only at bottom-hole conditions, but also at the thermalconditions present at the liner lap. It must be ensured that the cementin the liner lap develops at least 500 psi compressive strength prior toconducting any pressure testing to evaluate hydraulic integrity. Withlong liners, it may be necessary to adjust cementing additives toproduce sufficient compressive strength at the liner lap.

10. Lead slurries are to be designed to allow for a minimum contact timeof 10 minutes across zones of critical cement bonding performance.This will require determination of a minimum slurry volumerequirement for the planned pump rate and wellbore geometry.

11. For wells with anticipated bottom-hole static temperatures of 230degrees F or above, the cement slurry is to be designed to preventcement strength retrogression. This is to be accomplished through theaddition of 35% by weight of silica sand or silica flour. Silica flourground to 325 mesh is to be used for slurry densities up to 16.0 ppg.For higher density slurries, silica sand ground to 200 mesh is to beused. In all cases, compressive strength performance at static bottom-hole conditions over a minimum period of 14 days is to be determined.

12. At temperatures above 250 degrees F, do not specify the use ofbentonites, diatomaceous earth or expanded perlite at concentrationsin excess of 5% - 15% without adding +/- 20% silica flour.

13. For cements to be used across massive salt sections, slurryformulations incorporating 20% - 31% salt, are to be used.




D. Cement Spacer Design

Planning for the success of any primary cementing operation is not completewithout thoroughly addressing the design of the cementing spacer. Theseformulations serve several important functions, including:

1. Separation of incompatible fluids - in this case the drilling mud andcement.

2. Displacement of the drilling fluid ahead of the lead cement slurry. Aspart of this process, built-up filter cake must be removed from theformation face.

3. Water wetting of the formation and casing through the action of waterwetting surfactants. This function is particularly important in the caseof oil base drilling fluid displacement.

E. Spacer formulations to achieve these requirements can be obtained from eachof the major cementing contractors and also the mud companies. However,there are significant differences in the performance characteristics of spacers,and it is the responsibility of the cementing program designer to ensure thatthe most technically effective spacer is selected for a particular application.

Frequently, it is more cost effective in terms of total well cost to purchase amore expensive cementing spacer from a firm other than the cementingcontractor, rather than spend considerable time and money on remedialcementing operations to repair a poor primary cement job attributed to poorspacer selection. To ensure that the cement spacer will perform as required,the following guidelines are to be closely adhered to:

1. All spacers should be designed to be in turbulent flow at the planneddisplacement rate for a particular cement job. In this respect, spacersthat achieve turbulent flow at low pump rates are preferred.

2. The spacer should be weighted to a density at least 0.5 -1.0 ppgheavier than the mud density being displaced. However, the spacerdensity should not exceed the density of the cement slurry. If thecement and mud densities are very close, then the spacer densityshould be taken to be the average of the two.

3. The spacer should be formulated to water wet the formation face andcasing surface. This should not be a problem with water base drilling




muds and spacers; however, spacers used in the presence of oil basemuds will require the addition of sufficient water wetting surfactantsto ensure a water wetting characteristic.

4. The spacer should be completely compatible with the drilling mud andlead and tail cement slurries. A compatibility test is to be performedat room temperature and also at the anticipated bottom-holecirculating temperature.

5. The spacer should have good solids suspension characteristics. Thiswill ensure the capacity to suspend weighting material. The solidscarrying capacity of the spacer must also be tested.

6. The spacer should be designed to produce a minimum of 10 minutessurface contact time through intervals of critical cement bonding.This requirement is critically important and must not be under-designed.

7. In addition to the requirement of (6) above, the spacer volume shouldbe sufficient to yield a minimum fluid height of 500 feet in thecasing annulus.

8. All spacers should be batch mixed in the field using a dedicated mudpit. The pit selected for preparing the spacer must have adequateagitation to avoid inadvertent settlement of weighting material. Usually a pit with a combination of paddle and jet mixers will beacceptable.

F. Other Design Parameters Effecting Primary Cementing Success

In addition to the subject areas discussed above, numerous other factorsimpact the success of the primary cementing operation. These designconsiderations are no less important to the success of the cement job thanthose discussed previously.

1. Through intervals of critical cementing performance (e.g., zoneisolation, casing support, production intervals), the well should bedrilled as straight as possible; i.e., the dog-leg severity should be asnear to zero degrees/100 ft as possible. This will enable maximumcasing stand-off and minimize the number of centralizers requiredthrough these intervals.




2. Casing stand-off through critical sections should be a minimum of70%. This is generally accomplished through the use of positivestand-off centralizers. If it is necessary to use spring bow typecentralizers, then centralizer placement to achieve this stand-off canbe determined using computer modeling or the techniques outlined inAPI Specification 10D, Specification for Casing Centralizers.

Note: To enhance casing stand-off through production zones,positive stand-off centralizers are to be used. Refer to GeneralDrilling Program for spacing requirements.

3. Based on the anticipated drilling fluid rheology while running casing,maximum casing running speeds are to be specified that willavoid formation break-down and/or loss of whole mud to weakzones.

4. For large diameter casing strings, it will be necessary to determine ifthe force exerted on the bottom of the casing due to hydrostaticpressure and annular pressure losses will be sufficiently large to causethe casing to be pumped out of the hole during cementing operations.If it is possible for the casing to be pumped off bottom, then cementslurry density and/or displacement rates will have to be adjusted toensure the casing remains on bottom.

5. Casing float equipment is to be specified to ensure the success ofprimary cementing operations. In general, the following floatequipment specifications are to be followed:a. For 30" and 20" diameter casing, use a positive acting, single

valve float shoe assembly. The use of a float collar will not berequired unless dictated by well specific conditions. Innerstring cementing may be used on non-floating rigs asappropriate.

b. For 13-3/8" casing, use a positive acting, single valve floatshoe and a positive acting, single valve float collar spaced twopipe lengths apart.

c. For 9-5/8" casing, use a single valve, positive acting float shoeand a single valve positive acting float collar positioned atleast two pipe lengths apart.




d. For 7" and 5" liners, use a double valve, positive acting floatshoe and a conventional liner wiper plug landing collarcomplete with a profile to accept a latchdown wiper plug.Float shoe and landing collar are to be positioned at least twopipe lengths apart.

6. Cement wiper plugs are to be used with casing sizes 13-3/8" andsmaller according to the following schedule:

a. 13-3/8" and 9-5/8" casing:

If using subsea cementing system, only run a top plug. Ifcementing conventionally with full bore landing string tosurface, use a top and bottom non-rotating plug system.

b. 7" and 5" liners:

Run a single liner wiper plug complete with latch down facilityfor landing/latching in landing collar.

For casing sizes requiring the use of two cementing plugs, the bottomplug is to be launched following the spacer and/or pre-flush. The topplug is to be launched behind the tail slurry with allowance for +/- 2.0bbls of cement on top of the plug.

In certain critical well applications it may be necessary to use both atop and bottom cementing plug for the 13-3/8" casing. This will haveto be decided on a well by well basis. In addition, under certaincircumstances it may be advisable to use more than one bottom plugto ensure segregation of spacers and/or flushes. Again, thisrequirement is to be reviewed based on well specific requirements.

7.2.2 Squeeze Cementing

Squeeze cementing operations are typically performed as part of a remedial operation(e.g., repair of a poor primary cement job, repair of a poor casing seat, or isolationof water channeling). As with primary cementing, the success of squeeze cementingoperations (on the first attempt) requires considerable job planning. Detailed beloware job planning considerations that must be adequately addressed before projectimplementation in the field.

A. Squeeze cement slurries should be weighted to +/- 16.0 ppg and treated withappropriate additives to ensure adequate thickening time at the anticipated




circulating bottom-hole temperature. Refer to the thickening time calculationguidelines in Part 7.2.1.

B. The API fluid loss for squeeze slurries should be specified to be in the rangeof 50-200 ml/30 minutes at 1000 psi differential pressure. For slurries thatwill be used as part of a circulation squeeze technique, the API fluid lossshould be reduced to +/- 50 ml/30 min., while conventional squeezes are tobe performed with a fluid loss at the higher end of the range specified above.

C. The free water content for all squeeze cementing slurries is to be zero percent.

D. All squeeze cementing formulations should be prepared in a batch mixing tankto ensure uniform rheological properties prior to pumping downhole. Surfacedensity should be checked using a pressurized mud balance. Once the cementhas been completely blended, a sample of cement is to be tested to determineif the API fluid loss is within acceptable limits. Double the volume of filtrateobtained at 7.5 minutes duration and use this figure as an estimate of thefiltrate volume that will be produced after 30 minutes. Pump the cementdownhole based on the 7.5 minute test result.

E. Maximum surface squeeze pressures should be carefully calculated taking intoaccount the current formation fracture pressure, which may be less thanoriginal conditions in permeable zones if reservoir pressure has been drawndown. In addition, the applied squeeze pressure should take account of thehydrostatic pressure exerted by the cement slurry and drilling/completionfluid. Job success will generally be improved if the final squeeze pressure islimited to less than formation fracture pressure less an allowance for a safetyfactor of +/- 250 psi.

F. Dehydration of the cement slurry on the formation face may requirere-application of the final squeeze pressure before the pressure bleed-off rateis reduced to zero. In general, the final squeeze pressure should be stable fora period of 30 minutes before the squeeze is termed "successful" and squeezepressure is released.

G. The use of downhole squeeze tools is to be specified on a well by well basis.In certain instances it will be more technically and economically desirable touse a drillable cement retainer, whereas in other situations a retrievable packerwould be indicated. The specification of these tools will be at the discretionof the job designer based on well conditions and desired results.

H. As with primary cementing slurries, the cement is to be separated from thedrilling/completion fluid by an acceptable spacer or wash fluid. In the




case of squeeze cementing in oil base fluids, the spacer must produce waterwetting of the formation and casing ahead of the squeeze slurry.

I. Prior to drilling out cement to pressure test the squeezed interval, the cementis to have a minimum compressure strength of 500 psi.

7.2.3 Kick-off and Abandonment Cement Plugs

As with all cementing operations, thorough planning and close adherence to goodoperating practices are necessary to ensure job success on the first attempt. Thecommon belief that multiple cement plugs will probably have to be spotted before one"takes", simply is not true. In most cases, failure to obtain an acceptable cement plugon the first attempt can be traced to incorrect slurry formulation or poor placementpractices. This section is intended to provide the program designer and fieldsupervisor with sufficient technical guidance to obtain a successful plug on the firstattempt. The guidelines outlined below should be closely reviewed prior toimplementing these operations.

A. Kick-Off Plug Design and Placement

1. In general, the density of kick-off plugs is to be +/- 17.0 ppg or higherif required to be more dense than the well fluid.

2. Prior to setting open hole cement plugs, a 200' viscous pill (funnelviscosity of 100 + sec/qt) is to be spotted in the open hole below plugsetting depth. If the cement plug is to be spotted inside casing as wellas open hole (e.g., kicking off below 13-3/8" shoe after cutting andpulling 9-5/8" casing), a bridge plug is to be installed inside the 9-5/8"casing prior to cutting the casing for recovery. The cement plug is tothen be spotted on top of the bridge plug.

3. Prior to setting open hole cement plugs in old wells (i.e., previouslycased off interval), the open hole section is to be underreamed throughthe interval that is to be cemented.

4. Plug slurries are to be formulated to allow for adequate thickeningtime at the anticipated bottom-hole circulating temperature at thebottom of the plug. The thickening time must allow time to spot theplug and pull clear, with allowance for a safety factor ofapproximately one hour.

The following formula can be used as a guide for determining anacceptable thickening time:




Thickening time = time to mix cement slurry +time to launch wiper plug +time to pump spacer/wash behind +time to displace plug +time to break-off cementing head +time to pull pipe clear of plug +safety factor

In general, a safety factor of one hour should be more than adequate.

Do not over-retard the slurry to extend thickening time. Over-retardedslurries will only increase the amount of time required to generateearly and ultimate compressive strength, and may result in prematuredrill-out of a good plug.

For all thickening time tests, the elapsed time to 80 and 100 Beardenunits of consistency (Bc) is to be measured in hours and minutes, withthe 100 Bc figure taken as the measured thickening time. Thedifference between the 100 Bc and 80 Bc times is to be used as anindication of the time period during which the cement slurry changesfrom a pumpable to an unpumpable condition. Both the 80 Bc and 100Bc measurements are to be reported on all thickening time tests.

5. Slurries must be formulated to develop high early and ultimatecompressive strength. For applications below a static bottom-holetemperature of 230 degrees F, neat slurries (without sand, lostcirculation materials, etc.) should be used. Above 230 degrees F, theslurry formulation must include 35% by weight of silica flour or silicasand. Silica flour ground to 325 mesh is to be used for slurry densitiesup to 16.0 ppg. For higher density slurries, silica sand ground to 200mesh is to be used.

6. API fluid loss should be controlled to be in the range of 200 - 250ml/30 minutes at 1000 psi differential pressure. For slurries that mustbe set across highly permeable intervals, the fluid loss is to be reducedto less than 50 ml/30 minutes. This is to prevent dehydration of thecement, which could result in annular bridging and sticking of thework string. In all cases the free water (both vertical and inclined) isto be less than 1.0 percent.

7. The cement slurry should be designed to be in turbulent flow at theplanned displacement rate. In addition, the slurry should beviscous, and gel rapidly once pumping has stopped.




8. Sufficient cement volume is to be pumped to produce a plug height of300 - 500 feet once the work string is removed. For kick-off plugs setin hard formations, the plug length requirement will be greater than forplugs set in softer formations. This is due to the amount of cementplug that will have to be drilled to establish the kick-off.

9. The plug is to be spotted in a section of gauge hole with minimumwashouts. If necessary, a caliper log is to be run to ensure anacceptable plug setting interval. If plug spotting in a washed outsection cannot be avoided, then allowance should be made for excesscement volume.

10. The cement slurry is to be separated from the drilling fluid by a spacerthat is compatible with the mud and cement. When using low density(9.5 - 10.5 ppg) drilling muds, a water base wash is recommended.For higher density muds, a conventional weighted spacer is to be used. Spacer density is to be specified to be a minimum of 0.5 - 1.0 ppgheavier than the drilling fluid density. If spotting the plug in oil basemud, the spacer must contain a water wetting surfactant to water wetthe formation face ahead of the cement slurry.

11. To ensure best results, particularly in oil base drilling fluids, thespacer should be sized to produce 500' - 800' of height in theannulus ahead of the cement slurry. When using wash spacers, itmust be ensured that the annular height of the wash does not reducethe hydrostatic pressure in the well sufficiently to cause the well toflow.

12. All plugs are to be spotted in a hydrostatically balanced condition. Thismeans that the height of spacer and cement on the outside of the workstring must be equivalent to the height of spacer and cement inside thework string. This will require accurate calculation of the spacer andslurry volumes as well as the volume of mud pumped to spot the plugin position.

13. The drill string should be rotated at 20-30 rpm throughout thecementing operation. This should also be performed as the mud iscirculated and conditioned prior to mixing and pumping the cementslurry. In addition, once +/- 5 bbls of cement has rounded the end ofthe work string, pick-up 2'-3' to avoid cement contamination frommud in the rathole.




B. Abandonment Plugs

Abandonment plugs are to be formulated and spotted largely in accordancewith the guidelines given above for kick-off plugs. However, there are a fewexceptions, and these are given below.

1. For cement plugs that are not to be drilled out, a minimum pluglength of 250' should be used. This holds true for open hole as wellas cased hole plugs.

2. For cement plugs set inside casing, the need for fluid loss control canbe eliminated. However, free water content must still be maintainedat less than 1%.

7.3 Casing Installation and Cementing

The material contained in this section is intended to provide general operating guidelines andpractices for casing installation and cementing. Under certain operating conditions it may benecessary to supplement these guidelines. In all cases, the casing and cementing section ofthe Drilling Program is to be consulted for well specific requirements.

7.3.1 Hole Conditioning

Prior to running a particular string of casing, the following operations are to beperformed:

A. Once casing setting depth has been reached, the hole is to be circulated cleanof formation cuttings. Any mud conditioning for cementing should beperformed as the hole is being drilled to casing point.

B. Prior to logging operations or installation of casing, the bit is to be shorttripped to the previous casing shoe and then run back to bottom to be certainthe well will remain open. If necessary for hole stability, the drilling fluiddensity is to be increased. Additional short trips are to be performed until thewellbore is confirmed to be stable.

C. Following completion of open-hole logging, the drilling assembly is to be runback to bottom and the drilling fluid circulated and conditioned for cementing;although this requirement can be relaxed in the case of short logging runs (+/-12 hours) provided hole condition during logging has been acceptable.

7.3.2 Pre-Job Checks




Planning for a safe and successful casing operation is just as important as actuallyperforming the work. Thorough planning will usually lead to identification of someequipment or material deficiency which would have seriously impacted jobperformance. It is the responsibility of the drilling supervisor to ensure that all pre-jobchecks have been performed.

Prior to installation of the casing, the following pre-job inspections and operations areto be preformed.

A. Complete the Casing and Cementing Check List contained in Part 7.4 at theend of this section.

B. The drill string (i.e., drill pipe and bottom-hole assembly) is to be strappedwith a steel derrick tape on the last trip out of the hole prior to logging. If anydiscrepancies occur, then strap out again on the conditioning trip followinglogging. Pipe measurements are to be taken from the tool joint seal face atthe top of each stand, to the seal face on the pin end at the bottom of eachstand. The pipe is not to be measured using average stand lengths, previouslymeasured BHA component lengths, finger board height plus pipe stick-up, orany other measurement technique.

C. All tubulars are to be visually inspected for thread and/or body damage, drifted(Refer to General Topics for API drift specifications), and tallied prior tobeing installed in a well. ALL PIPE TALLIES SHOULD BE CHECKEDBY AT LEAST TWO RESPONSIBLE PERSONS. Any discrepancies inthe joint count, when compared to the cargo manifest, are to be reported.

Thread protectors are to be removed, and the threads cleaned of threadcompound and grease using varsol, or other suitable solvent. The threads arethen to be cleaned with a high pressure jet washing system, followed by highpressure air to remove residual water.

Once the threads are thoroughly clean, a suitable thread compound is to beapplied to both the box and pin ends. If it is necessary to re-install any threadprotectors prior to running the pipe, the thread protectors are to bethoroughly cleaned before use. Any pipe not passing wellsite inspection is tobe set to one side and appropriately labeled. Refer to Section V, Part 2.7 forlabeling requirements of damaged pipe.

D. For casing strings requiring the use of mandrel type casing hangers andassociated running tools, the casing hanger and running tool assembly is to bemade-up and racked back in the derrick prior to running the casing. Duringthis operation the hanger and running tool are to be inspected for damage andthen function tested.




E. The cementing head and cementing plugs are to be carefully inspected toensure compatibility with the casing string to be run. Be certain the plugs aredesigned to pass through the heaviest weight of casing being run.

F. The positioning of cementing aids, including float equipment and centralizers,is to be determined prior to running the casing. Centralizers to be held inposition using stop collars, and positive stand-off centralizers, are to beinstalled on the pipe deck prior to running casing.

G. The float shoe and float collar joints are to be visually inspected by the DrillingSupervisor or Drilling Engineer to ensure that the float shoe and float collarhave been installed using thread locking compound. In addition, it must beensured that all thread locked couplings have both end of the coupling threadlocked even if it is necessary to remove the coupling with the casing joint seton slips in the rotary table. If a casing coupling is removed in the rotary,be certain to install a safety clamp on the casing before attempting toback-off the coupling.

H. A schedule of anticipated hook load as a function of casing footage run shouldbe prepared and posted on the drill floor. If drill pipe is to be used as alanding string, it must be ensured that the anticipated drill pipe loading doesnot exceed 80 percent of the drill pipe tensile rating. Anticipated drill pipeloading is to be calculated as follows:

Drill pipe loading = Buoyed weight of casing @ setting depth(Maximum)

+ Pick-up drag force

+ 100,000 lbf over-pull allowance

I. The casing handling tools are to be carefully inspected for signs of wear. Slipinsert dies should be new and tightly retained within the slip wedges. Forheavy duty spider assemblies, be certain the split bushing retaining pin can beeasily removed to enable spider assembly installation when required. Removeany hardware that must be removed to install the spider around the casing. Check functioning and fit of single joint pick-up elevators on a joint of casing. Be certain the elevator latch is fitted with a safety pin.

J. All lifting appliances required during casing installation are to be furnishedwith valid load certificates. Load certificates are to be inspected by thedrilling supervisor to be certain they are current. Items which require a loadcertificate include:

1. All elevators, slips and spider assemblies




2. Single joint pick-up elevators and handling slings

3. All casing handling slings

4. Wire rope slings used as snubbing lines

5. Load cells used in conjunction with power tongs

K. The operational status of the cementing unit is to be checked well in advanceof the job start time. This is to be done even if the unit was serviced followingthe previous cement job. Pressure test all lines and valves on the unit, as wellas the cementing line to the drill floor, including any high pressure flexiblecementing hoses. Consideration should be given to mixing a trial batch ofcement to test the mixing system if capabilities are in doubt.

L. Check to be certain the drill floor has been made ready for running the casing.The following equipment and materials should be available at the start of thejob.

1. Mud fill-up line. This should be a permanent fixture, complete witha swiveled arm and down-spout to enable casing fill-up betweenjoints. The line should be equipped with a valve positioned near theend of the swiveled arm to permit operation by the casing crew.

2. Elevated work platform. The platform should be constructed toenable the casing crew to work at a comfortable elevation above theheavy duty spider assembly.

3. Casing dope and brushes. Use only API modified casing dope and anew dope brush.

4. Five gallon bucket of barite and a wire brush. To be used to clean anddry threads prior to applying thread locking compound.

5. Length of 1" - 1½" diameter rope (depending on pipe size) to restraincasing as it enters the V-door.

6. Restraining line to hold power tong out of the way when not in use.

7. Fully operational stabbing board equipped with safety harness andemergency braking system.




7.3.3 Casing Installation

Casing installation operations are to be closely supervised by the drilling supervisor,particularly during initial rig up, and while running casing equipped with cementingaids (float equipment, centralizers, etc.).

The operating procedures and practices outline below are to be closely followed whileinstalling casing.

A. If the casing is being run on a floating rig, be certain the rotary table ispositioned over the wellhead prior to running casing. In addition, oncethe casing hanger has been picked up and is in a position above the BOPstack, space out the landing string such that the casing hanger can be runthrough the BOP stack and landed in the wellhead in one motion. Do notallow the casing hanger to be suspended in the BOP stack under anycircumstances.

B. Rotary slips and side door collar type elevators may be used at the beginningof each casing job. 30" casing is usually run using pad-eyes. These tools maybe used for string weights up to 60% of the load rating of the side door collartype elevators. Once this limit has been reached, use a slip type elevator andspider.

C. A safety clamp is to be installed on the casing while making connections untilsufficient casing weight is available to ensure the slips are biting and the casingwill not fall. This should occur when +/- 20,000 lbf of casing weight has beenrun.

D. Apply thread locking compound to bottom casing joints as specified in theDrilling Program. If the bottom joints of casing have not been furnished withone end of coupling already thread locked, remove casing couplings asrequired to apply thread locking compound. Be certain to install safety clampto pipe body prior to removing coupling.

E. The power tongs are to be installed in a position that will allow easymovement from make-up to set-back position. In addition, the snub line is tobe secured such that the angle between the snub line and the tong arm is at 90degrees and level when the tong is in the make-up position. This will ensurecorrect make-up torque readings for torque gauges equipped with load cellsattached to the snub line.




F. Pipe running speeds are to be controlled to avoid breaking down the casingshoe or other weak formation. If a maximum safe running speed is notspecified in the Drilling Program, limit pipe running speed to 20 seconds perjoint. Monitor mud returns from the well to ensure that the correct volumeof fluid is being returned for the volume of casing that has been run.

G. The casing is to be filled with mud at regular intervals to avoid excessivecollapse loading. If the mud fill-up line is positioned correctly, mud can beadded between connections without loss of rig time. For casing stringsequipped with auto-fill float equipment, the float valves are to be tripped atthe casing shoe prior to running out into open-hole.

H. Once the casing has been landed, circulate and condition mud, pumping thegreater of either casing capacity or annular capacity. Pump at the maximumrate planned for during the cementing operation. Monitor well for whole mudlosses.

I. While running casing, any spacer fluids that will be required during thecementing operation are to be prepared in an isolated mud pit. If weightingmaterial is required in the formulation, this material should be added close tothe time when the spacer is required in order to avoid material settling in themixing pit.

7.3.4 Casing Cementing

Primary cementing operations can be performed in a routine manner if adequateplanning and equipment checks have been performed. Since primary cementing offersthe greatest opportunity for obtaining overall job success, the following guidelines areto be followed closely.

A. Check that the liquid additive system is functioning properly and that theadditive fluid levels indicated on the metering tanks are correct for the plannedslurry formulation.

B. Check the functioning of the bulk cement transfer system. Be certain allshipping lines are clear. To avoid bridging, "Fluff" the cement prior toinitiating bulk cement transfer through the shipping lines. Be prepared toswitch shipping lines in the event the primary shipping line plugs-off.

C. Be certain to avoid over filling the bulk cement tanks in order to preventsubsequent difficulties that may be experienced "fluffing" the cement.




D. Have sufficient sample containers on hand to catch at least two dry cementsamples and two blended cement samples from the lead and tail cement.

While mixing and pumping cement, slurry density checks are to beperformed at least once every five minutes. The slurry density should bemeasured with a pressurized mud balance using a sample recovered from thebottom of the mixing tub. Atmospheric mud balances are too inaccurate forcementing operations and should not be used.

E. It is imperative that the drilling supervisor monitors the volume of cementslurry mixed and pumped. This is to be done by maintaining a record of mixwater consumption at the cementing unit. In addition, a job record should bemaintained including the following data: time, slurry density, pump rate, pumppressure, mud return rate and current operation.

F. For most 30" and 20" casing and all liner cementing, displacement of thecement slurry is to be performed using the cementing unit. Accurateplacement of these slurries requires that displacement volumes be measuredusing the cementing unit displacement tanks. For all other casing strings, thetop cementing plug is to be displaced to the float collar using the rig's mudpumps. On conventional surface drop cement wiper plugs, if the plugdropping indicator showed the plug left the plug dropping head, continuepumping until the plug bumps. On liner and stage cementing plugs, do notpump more than the calculated displacement. On liner and stage cementingjobs, it is much easier to drill up a small volume of cement left inside thecasing, than to repair a poorly cemented casing shoe due to over-displacementof cement.

Calculation of the total mud pump strokes to displace the top plug to thefloat collar should be based on the contractor's record of pumpdisplacement efficiencies measured during previous cement jobs. It mustbe remembered that displacement efficiency will be a function of liner size,pump rate, and pumping pressure. If the displacement efficiency is notknown, assume an efficiency of 97% as a first approximation. If the plug doesnot bump at the calculated number of strokes, on liner and stage cementingjobs do not over-displace the cement. The actual displacement efficiency canbe checked when the drill out assembly is run and tags the top plug.




G. For cementing programs requiring the use of a two plug system, the bottomplug is to be released once the lead spacer has been pumped. The bottomplug is to be followed by the lead and tail cement slurries. Prior todisplacement of the tail slurry from the cementing lines to the rig floor, the topplug is to be released. The volume of cement remaining inside the cementinglines is then to be displaced on top of the top cementing plug. The cement leftabove the top cementing plug may aid in drilling the top plugs.

H. If mud returns are being taken to surface while cementing, a constant recordof mud return volume is to be maintained by the mud loggers and checkedagainst the theoretical volume of mud returns. Remember, when the casingis on a vacuum, the volume of mud returned to the surface will exceed thetheoretical volume of mud returns (based on the actual volume of cement andmud pumped at surface). When the cement U-tube balances, the mud returnrate may go to zero as the displacement fluid catches up with the cement. Thisphenomenon may produce a complete loss of mud returns; however, it shouldnot be confused with whole mud losses to the formation.

7.3.5 Casing Pressure Testing

Casing pressure testing procedures and test pressures will be specified in the DrillingProgram for a specific well. However, it is the responsibility of the DrillingSupervisor to check the figures at the wellsite to ensure that the casing is not burst orcollapsed through negligence.

Casing and liner pressure testing is to be performed as outlined below. Do notpressure test the casing when the top plug bumps during cementing operations.

A. All casing strings are to be pressure tested in conjunction with pressure testingof the BOP stack blind/shear rams. This is to be performed as the lastpressure test during the BOP test sequence (except as noted in (B) below).Casing test pressures are not to exceed 80% of the internal yield pressureof the casing or 80% of the casing connector pressure rating, whicheveris lower. If the Drilling Program calls for use of a higher test pressure,consult with Drilling Superintendent, Engineer, or Manager to confirm testpressures.

B. If it is required to run a cement evaluation log (CBL or CET), then pressuretesting of the casing and blind/shear rams is to be performed followingcompletion of the logging run.

C. The casing pressure test is to be staged up in 500 psi increments, with eachsuccessive pressure increment held for a brief period to ensure no leaks. The




final holding period at test pressure is to be for a period not less than 15minutes.

D. Under no circumstances should the casing test pressure exceed the workingpressure rating of the ram preventers or the pressure rating of the wellheadspool section exposed to the test pressure, whichever is less.

E. With surface wellhead systems, the annulus outlet for the casing string beingtested should be opened and monitored for fluid leaking past the casinghanger pack-off element. If this is not possible, install a pressure gauge on thecasing annulus outlet and monitor for a pressure increase during the casingpressure test.

F. All casing test pressures are to be applied and removed slowly to avoidadverse dynamic loading.

G. All pressure tests must take account of the annulus fluid density relative to thefluid density inside the casing. The annulus fluid density should be assumedto be equivalent to drilling fluid down to the cement top, then sea water whenoffshore or formation water when on land from the cement top to the previouscasing shoe.

H. A chart recording pressure gauge must be used on all casing pressure tests.This gauge can be supplemented by a more accurate, conventional bourdontube pressure gauge, if required for operational reasons.

I. For all casing pressure tests, a record of applied pressure versus barrels ofmud pumped is to be maintained. This information is particularly usefulduring subsequent formation pressure testing. Figure 7.3 can be used todetermine the approximate volume of mud to be pumped to achieve aparticular test pressure. Alternatively, the equations below can be used.

For water base drilling fluids, use the following equation to estimate thevolume of fluid that must be pumped to achieve test pressure.




Figure 7.3: Volume of Fluid Required To Pressure Up Casing and Open Hole

Vm

=

P

x

Vc

x

(2.8 x 10-6 Fw + 0.2 x 10-6 Fs)

Where: Vm = volume of mud pumped, bblP = applied pressure, psiVc = volume of mud in casing, bblFw = volume fraction of water, dimensionless




Fs = volume fraction of solids, dimensionless

Similarly, for oil base drilling fluids, the following equation can be used toestimate the volume of fluid that must be pumped to achieve test pressure.

Vm = P x Vc x (2.8 x 10-6 + 5.0 x 10-6 Fo + 0.2 x 10-6 Fs)

Where: Vm = volume of mud pumped, bblP = applied pressure, psiVc = volume of mud in casing, bblFw = volume fraction of water, dimensionlessFo = volume fraction of oil, dimensionlessFs = volume fraction of solids, dimensionless

7.4 Casing and Cementing Checklist

The checklist given below is to be completed prior to and during all casing and cementingoperations.

7.4.1 Pre-Job Checks

A. Review Section V, Part 7.3 of Drilling Operations Manual.

B. Review Casing and Cementing section of Drilling Program.

C. Immediately after taking any casing at the rig site, count the number of jointsand compare with the number that should have been shipped based on thecargo manifest. Any discrepancies are to be recorded and reported to supplybase.

D. Lay out casing on pipe rack in the correct order for running, taking accountof different weights and grades and the required running order. Whenstacking pipe, be certain successive layers are supported by 2" x 4" woodensills spaced + 10' apart. Be certain sills remain aligned on successive layersto avoid pipe bending.

E. Position casing pup joints in casing string as specified in Drilling Program. Thesame holds true for any radioactive marker beads that may be required.

F. For casing run with mixed threads, be certain at least two crossovers areavailable for each crossover point. Check dimensions of crossovers to ensurecompatibility with casing dimensions.




G. Check condition of single joint pick-up elevators. Latch elevators on a jointof casing and check fit. Be certain elevator latch is fitted with a safety pin.Check condition of lifting sling and shackles.

H. Review casing make-up procedure with casing crew. Check Drilling Programfor optimum make-up torque and acceptable minimum and maximum torques.

Make up of Buttress Casing

Proper make up of a buttress connection will give a gas tight seal. A triangleis stamped on the pin end of the buttress casing. Allowing for tolerances inthe cutting of the threads in the pin and box, correct make up is when the endof the coupling is between the base and the apex (i.e., top) of the triangle.The procedure to make up buttress casing is as follows:

1. Make up the bottom joints requiring thread lock to 1/2 way betweenthe base and the apex of the triangle stamp on the pin.

2. After threadlock connections are made up and run, make up 4 or 5connections with the required thread compound (i.e., pipe dope) to1/2 way between the base and apex of the triangle. Count the turnsand torque to make up these joints.

Note: A click will be heard from the power tongs at the same pointon each revolution.

3. Use the average of the turns and torque recorded in number 2 aboveto make up the rest of the string.

Note:a. If the weight/foot of the casing varies in the string,

repeat steps 2 and 3 for each casing weight/footchange.

b. The common practice of making up buttress casing tothe bottom of the triangle can lead to joints withinsufficient make up. This would be true if pin threadcrests on the low end of tolerance and box threadcrests on the low end of the tolerance.

I. Check with drilling contractor on anticipated mud pump displacementefficiency even if it is planned to displace the cement with the cementing unit.




This will enable switching to an alternate pump in the event of an equipmentbreak-down.

J. Discuss casing installation and cementing procedures with drillers,toolpushers, mud engineer, cementer, casing crew, and any other personneldirectly involved in the operation.

K. Assign personnel to perform the following tasks:

1. Cement sample catching during cementing operation.

2. Cement slurry density measurement while mixing cement.

3. Mud volume gain/loss monitoring during cementing.

7.4.2 Hole Conditioning Prior to Cementing

A. At casing point, circulate hole clean of formation cuttings and gas andcondition mud for cementing. The mud is to be free of cuttings and ofuniform density.

B. Short trip bit to previous casing shoe, reaming any tight spots as required.

C. If hole remained open during short trip and is hydrostatically stable, strap outof hole with drill string. Compare pipe tally with drillers tally and correctdrilled depth as required. Following logging run, compare drillers depth withloggers depth. If a significant discrepancy exists, strap out again followingconditioning trip.

7.4.3 Tripping Out To Run Casing

A. Closely monitor hole fill-up volume on last trip out of hole prior to runningcasing. Hole must be completely stable and taking correct fill-up volume.

B. Check work areas affected during casing installation to be sure they are clearof all non-essential equipment, debris, etc.

C. Re-fuel diesel powered hydraulic power units.




D. Conduct final briefing with casing crew. Check that planned coupling make-up procedure is correct, including make-up torque schedule.

E. PULL WEAR BUSHING

7.4.4 Cementing Casing

A. Witness the loading of all cementing plugs. Under no circumstances is thebottom wiper plug to be slit with a knife because of doubt that it willrupture when bumping the float collar.

B. Pressure test all cementing lines and the cementing manifold with water priorto pumping any fluid into the casing. Test pressure is to be at least 1000 psiabove maximum anticipated pumping pressure during cementing operations.

C. While cementing, perform the following:

1. Check cement slurry density at 5 minute intervals.

2. Periodically check actual mud returns vs. anticipated mud returns.

3. Continuously monitor surface pumping pressure.

4. Catch samples of dry cement, mixed cement, and mix water, asrequired.

5. Check position of tattletale on cementing head once top cementingplug has been released.

D. For surface wellhead systems, monitor casing annulus for pressure build-upwhile cement sets.

Documents

36734159 CSG and Cementing Operations