cementing best practices

Occidental Oil and Gas Corporation

Global Drilling CommunityGlobal Cementing Best

Practices

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Approved By: G. BushEndorsed By: K. O’DonnellLast Review Date:

April 5, 2007

Effective Date: April 5, 2007

Section Page

1.0 Introduction 6

2.0 Primary Cementing Engineering 7

2.1 Mud Remova l 7

2.1.1 Mud Conditioning 7

2.1.2 Pipe Movement 9

2.1.3 Centralization 9

2.1.4 Displacement Pump Rate 10

2.1.5 Spacers 11

2.1.6 Mechanical Aids 13

2.2 Cement Lab Testing 13

2.2.1 Definitions 13

2.2.2 Cement Lab Audit 16

2.2.3 Pilot Testing 16

2.2.4 Blend Testing 20

2.2.5 Onsite QC 21

2.3 Cement Slurry Design 22

2.3.1 Cement Slurry Properties 22

2.3.2 High Temperature Slurry Design 25

____________________________________________________________________________________Cementing Best Practices 1 04/17/2023 Revision 1



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2.4 Special Cementing Challenges 26

2.4.1 Annular Gas Flow 26

2.4.2 Lost Circulation 27

2.4.3 Liner Cementing 28

2.4.4 Salt Sections 31

2.4.5 Reactive Shales 32

2.4.6 Long Ratholes 32

2.4.7 Steam Injection 32

2.4.8 Foam Cement 32

2.4.9 Corrosive Environments 33

3.0 Primary Cementing Operations 34

3.1 Mixing and Pumping Cement 34

3.1.1 Pre-job Procedures 34

3.1.2 Job Procedures 36

3.1.3 Pressure Test Lines 38

3.1.4 Density Control 38

3.1.5 Pump Rate 39

3.1.6 Data Acquisition 39




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3.1.7 Displacement 39

3.1.8 Pump Casing Out of Hole 40

3.2 Float Equipment 41

3.3 Cement Wiper Plugs 41

3.4 Post Job Operations 42

3.4.1 Wait-On-Cement 42

3.4.2 Nippling Down BOPs 43

3.4.3 Pressure Test Casing 43

3.4.4 Shoe Tests 44

3.5 Cement Sheath Evaluation 45

3.5.1 Cement Evaluation Log 45

3.5.2 Temperature Log 47

3.5.3 Tracer Survey 47

3.6 Problem Jobs – “Cemented Up” Casing 47

4.0 Plug Cementing 50

4.1 Plug Setting Techniques 51

4.1.1 Balanced Plug Method 51

4.1.2 Unbalanced Plug Method 52

4.2 Achieving a Stable Cement Plug 53




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4.2.1 Stabilizing the Wellbore 53

4.2.2 Providing a Base 53

4.2.3 Drillpipe, Stinger, and Diverter 54

4.2.4 Centralizers 54

4.2.5 Pulling Drillpipe Out of the Plug 55

4.3 Wellbore Preparation for Setting Cement Plug 55

4.4 Cement Slurry Design – Plug Cementing 55

4.4.1 Slurry Density 554.4.2 Thickening Time 56

4.4.3 Compressive Strength 56

4.4.4 Fluid Loss 56

4.4.5 Free Water 57

4.4.6 Rheological Properties 57

4.4.7 Spacers for Plug Cementing 57

4.5 Plug Cementing Displacement 58

4.5.1 Ball Catcher 58

4.5.2 Wiper Balls 58

4.5.3 Drillpipe Caliper 58 4.6 WOC and Cement Plug Drillout 58




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4.7 Abandonment Cement Plugs 58

5.0 Health, Safety, and Environment 59

6.0 Tracking Results 60

6.1 Key Performance Indicators 60

6.2 Cementing Scorecards 62

7.0 Contractor Requirements 62

7.1 Cementing Proposal 62

7.2 Cement Testing 63

7.3 Pricing and Invoicing 64

7.4 Contract Specifications 64




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1.0 Introduction

The purpose of this document is to outline and promote a “Best Practices” philosophy throughout the Oxy Global Drilling Community. This document provides direction for general planning and executing primary and plug cementing operations on a global basis. It is understood that in many well situations, the preferred “best practice” may not achieve the optimum result. Every cement job should be designed individually dependent on its specific wellbore characteristics to achieve the desired cementing objectives.

Promoting ‘Best Practices’ is an ongoing effort throughout Oxy drilling operations. Given the wide variety of cementing operations performed throughout the Oxy Drilling Community, a collective sharing of cementing practices and technologies will help all areas obtain competent and economical cement jobs. To help achieve this, a Global Cementing Network or ‘Community of Practice’ (COP) has been formed. Visit the Oxy Cementing Network site on the Global Drilling Community Website to view the network’s charter, goals, and members’ names and contact information. In addition, the Oxy Cementing Network site includes:

o Engineering toolso New cementing technologieso Performance data – KPIso Cementing technical paperso Reference materialso Cementing presentationso Job exampleso Rigorous technical specifications for cementing contractso Squeeze cementing documentso Cementing Contractor Information

o Contactso Technical Informationo Lab Audits




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o Cementing Scorecardso Best Practice Updates and Notices

2.0 Primary Cementing Engineering

The first step in successfully engineering the cementing process is to clearly define the objectives of each operation. The wellbore conditions and casing design must then be evaluated to determine cement placement, hydrostatic constraints, and volumes. The cementing contractor must be fully involved in this stage.

2.1 Mud Removal

The top priority in achieving a successful cement job is to displace all of the drilling mud from the annular section to be cemented, that is, to achieve a high displacement efficiency. Displacement efficiency is defined as the percentage of annular area at any given cross-section that is filled with cement. There are several proven best practices that can be used together to help achieve a nearly 100 % displacement efficiency, including mud conditioning, pipe movement, centralization, spacers, and mechanical aids.

2.1.1 Mud Conditioning

1. Mud Properties

Drilling muds are designed to help efficiently drill and transport cuttings to the surface, but are not always conducive to good mud displacement during cementing operations. Therefore, prior to running the casing and cementing, the drilling fluid should be conditioned to exhibit “easy-to-remove” properties including low fluid loss, thin rheological properties, and a flat gel profile. General recommended production casing/liner values for these properties are listed below, although significant variations can occur




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based on mud type and weight.

o API Water Loss < 10 cc/30 min

o Yield Point < 15 (straight holes)< 20 (hole angle > 30 degrees)

o 10 m gel strength < 25 or 10s/10m gel strengths < 2/3

o 30 m gel strength < 30 or 10m/30m gel strengths < 2/3

Additionally, if there is a concern for mud losses while running casing or cementing, a LCM pill should be spotted on bottom prior to POOH with drillstring.

Note: If there is to be excessive rathole during cementing, it is not necessary to spot a heavy mud pill on bottom prior to POOH with BHA. It is more problematic to have a heavy, more viscous mud around the casing shoe prior to cementing, than any slight risk that cement may fall into the rathole after placement.

2. Conditioning Volume

With casing at casing point, circulate hole clean of formation cuttings and gas, and condition mud for cementing. The mud is to be free of cuttings and of uniform density. It is recommended to circulate at least 2 1/2 hole volumes (See Figure 1).

Figure 1




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3. Conditioning Rate

Stage pump rate to the maximum rate planned during the cementing operation. Monitor well for whole mud losses. If mud circulation is lost and cannot be regained, stop circulating and prepare to cement the well.

4. Static Time After Conditioning

After the casing has been landed, and the drilling mud conditioned, cementing should begin as soon as possible, preferably within 15 minutes. Increased static times may cause the mud to gel significantly and make it difficult to remove from the annulus.

Note: For many cementing operations, it is a good practice to break circulation every +- 3000 ft while running casing. This will break mud gel strengths and remove cuttings/filter cake from centralizers or other casing attachments.

2.1.2 Pipe Movement




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While conditioning and cementing, the casing should be rotated or reciprocated throughout the mud conditioning and cementing process. Pipe movement will both physically scrape mud from the wellbore, as well as keep fluid moving around all portions of the hole.

Reciprocation = 15 – 20 foot stroke length @ 1 stroke per minute Rotation = 15 - 30 rpm

Note: Be aware of casing connection torque and strength limitations when moving the casing

2.1.3 Centralization

Casing stand-off through critical sections should be a minimum of 70%. Standoff is defined as NAC/(HR-CR), where NAC = the Narrowest Annular Clearance between the casing and the wellbore, HR = hole radius, and CR = casing radius (CR). Standoff can range from 0 % (casing against the hole wall) to 100 % (casing perfectly centered in the hole). Centralizer placement to achieve at least 70 % stand-off can be determined using computer modeling or the techniques outlined in API Specification 10D, Specification for Casing Centralizers, however, please note the following general rules-of-thumb.

Deviation < 45 degrees = 1 centralizer per 30 ft jointDeviation > 45 degrees = 2 centralizers per 30 ft joint (For tight radius bends and severe doglegs, adding 2 centralizers per joint may increase the rigidity of the casing string such that running in the hole may be more difficult.)

Use rigid, semi-rigid (double bow spring) or positive stand-off centralizers in open hole sections if possible. Bow spring centralizers are recommended for liner laps, casing-in-casing scenarios, and in washed out hole sections.

In addition to centralization, hole size versus casing size should be planned to provide enough clearance not to restrict flow through the annulus. The effective diameter of the annulus should be at least 1.5 inches (7” in 8 ½” e.g.).




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2.1.4 Displacement Pump Rate

Displacement rates should be specified based on the maximum pumping rate that can be obtained without exerting sufficient annulus pressure (due to increased ECDs) to break-down the formation and lose returns. Computer modeling of allowable pump rates should be performed as part of the planning process to enable accurate specification of cement rheological properties. To optimize mud removal, the annular fluid velocity during displacement should exceed 70 m/min or 200 ft/min – Figure 2. Slow the rate to bump the plug.

Note: Do not shut down and perform a hesitation squeeze on the casing shoe at the end of a job. Field results have generally shown no benefit when attempting to use the “hesitation method”.

Figure 2




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2.1.5 Spacers

1. General

Spacers are pumped to separate mud and cement. They are designed to:

Keep all fluids compatible in the wellbore Help remove mud from the annulus Leave the casing in a water wet condition for better bonding Maintain adequate hydraulic pressure while cementing

The best spacer to use for cementing operations is water with surfactants, chemical additives, or salinity added as needed. Even if a weighted spacer is required to maintain adequate downhole overbalance pressures, it is recommended to precede the weighted spacer with +- 20 bbls of base fluid (water or oil preflush) to provide turbulent flow properties and to dilute mud filter cake. When adding a light preflush, the hydrostatics must be sufficient at every point during the job to prevent formation fluid influx.

2. Spacer Density

Weighted spacer densities should be designed at the midpoint density between mud and cement slurry densities. Weighted spacers should be at least 0.5 ppg higher than the mud weight, and at least 0.5 ppg lower than the cement slurry density.

3. Spacer Volume

The spacer volume should be designed to produce a minimum of 10 minutes annular surface contact time through intervals of critical cement bonding. This requirement is critically important and should not be under-designed. Example: If displacing at 10 bpm, a total of 100 bbls of spacer should be employed, for a total contact time of 10 minutes.

In addition to the requirement of contact time, the spacer volume should be sufficient to yield a minimum fluid height of 500 feet in the casing annulus.




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4. Spacer Flow Regime

Spacers should be designed to be in turbulent flow in the annulus at the planned displacement rate for a particular cement job. If turbulent flow is not achievable, high laminar flow rate is preferred. A cement job should never be designed for plug flow conditions.

5. Spacer Salinity

The salinity of a water based spacer should match the salinity of the cement slurry.

6. Spacer Wettability

When cementing in oil or synthetic based muds, a surfactant package should be added to the spacer to help water wet the casing and formation, and to prevent thick emulsions at the spacer/mud interface. Wettability testing can be performed by the cementing service company to optimize the surfactant loading.

2.1.6 Mechanical Aids

The following items may be employed to help remove mud from the wellbore during cementing.

Upjet Float Shoe – Holes in the float shoe circumferentially direct approximately 60 % of the fluid rate upward and around the shoe joint.

Wall Scratchers – Either rotating or reciprocating scratchers mechanically remove filter cake/solids while moving the casing.

Turbulator centralizers – contain fins or angled blades to cause turbulence near the centralizer. Turbulators can affect mud removal +- 5-10 feet from the centralizer location.

2.2 Cement Lab Testing




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2.2.1 Definitions

Placement Time – The amount of time elapsed between the start of cement mixing to final placement of the cement in the annulus.

Thickening Time - The amount of time for a cement slurry to become “too thick to pump”. Thickening time is measured in an HPHT consistometer at BHCT and BHP. A slurry is considered “too thick to pump” when it reaches a cement consistency of 70 Bc (Bearden Units)- See Figure 3.

Note: API defines thickening time as time to reach 100 Bc, but for Oxy best practices, the 70 Bc should be considered to be the maximum pumpable consistency.

Figure 3 – Thickening Time and Transition Time

100----------------------------------------------------------------- Thickening Time

Consistency 70 (Bc)

40 --------------------------------------TransitionTime

0Time

Transition Time – The time for a cement slurry to transition from a liquid to a gel. It can be measured dynamically in an HPHT consistometer, or in static conditions in a Static Gel Strength Tester. While conducting a thickening time test, the dynamic transition time is the difference in time between the 40 Bc to 100 Bc consistency reading (See Figure 3). For a static gel strength test, the slurry transition time is the elapsed time for cement to progress from 100 lb/100 ft2 to 500 lb/100 ft2 gel strength.




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Right Angle Set – The term used to describe a cement slurry that has a very quick transition time, i.e. the slurry consistency moves from 40 Bc to 100 Bc rapidly.

Compressive Strength – The compressional force per unit area when set cement fails. It can be measured by physically crushing a cement cube or cylinder, or through non-destructive means with an Ultrasonic Cement Analyzer (UCA).

Wait on Cement (WOC) - For operations, WOC is the waiting time required after cementing in order to safely remove well control equipment with the annulus open or casing/liner fluid underbalanced. For a cement slurry, WOC is the time necessary for the cement to set and attain a compressive strength of 500 psi. This is most efficiently determined through lab testing with the UCA, which plots strength development over time.

Set Time (or Initial Set) – Set time is the time it takes for the cement to gain 50 psi compressive strength, becoming a hard solid. Early set time is one of the most important properties in an oilwell cement.

Fluid Loss – The amount of water pressed from a cement slurry under a differential pressure. In the lab, it is measured at BHCT by pressurizing the cement across a 325 mesh screen at 1000 psi differential for 30 minutes.

Free Water –The amount of clear fluid that separates from a cement slurry in a static condition. It is measured in the lab by filling a 250 ml graduated cylinder with cement and observing it for 2 hrs. For deviated wells, the graduated cylinder is usually placed at a 45 degree angle. A basic free water test is performed by conditioning the cement slurry for 20 mins at BHCT and then pouring the slurry into a 250 ml graduated cylinder at room temperature. An operating free water test is also conditioned but poured into a 250 ml graduated cylinder sitting in a water bath at BHCT. The operating free water test is a more severe and accurate test. For HPHT (> 190o F) perform the free water test at 190o F or perform a high temperature density segregation test.




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Density Segregation – The amount of density variation in a column of cement after it has set. It is physically measured in the lab after the cement has set for 24 hrs at BHST and BHP.

Shear Bond Strength – The force per unit surface area required to shear cement from a metal casing surface. It can be measured in the lab using a shear bond mold.

Tensile Strength – The force per unit area for a cement to fail in tensile. It is measured by physically pulling a “dogbone” shape cement specimen apart.

Cement Expansion – The linear or radial growth of cement during and/or after set. This property can be physically measured in the lab. Note that conventional cement slurries will normally shrink while setting due to hydration reduction. Expansion additives help cement expand 0 – 2 % linearly.

Gel Strength – Gel strength is the yield point of a cement slurry at varying times. Normally in the lab the gel strength is measured with a viscometer at 10 second and 10 minute intervals.

2.2.2 Cement Lab Audit

An annual cement lab audit should be conducted for the cementing contractors used by Oxy. The audit should be performed by Oxy using Oxy specifications and scoring from the Oxy Cementing Lab Audit Form.

2.2.3 Pilot Testing

Pilot tests are cement slurry tests that use lab stock cement and additives prior to actual bulk blending. A pilot test should be conducted for each cementing operation. If possible, it is recommended to perform pilot tests with the cement batch sample and additive lot numbers that will be used for the actual job. Pilot tests are performed to determine the actual slurry design for the job. It may require several pilot tests to perfect a cement slurry design. A pilot test should consist of the seven (7) items listed below.




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1. Thickening Time

Thickening time tests should be performed at the maximum anticipated bottom-hole circulating temperature for the hole depth under consideration. If field measurement of bottom-hole circulating temperature is not possible, then this figure is to be estimated using the API circulating temperature tables given in API Specification RP 10B. It should be noted that these tables are only an approximation based on compilation of a considerable amount of field data. Therefore, it may be appropriate in critical situations to consult with offset operators or the cementing contractor to determine if more accurate downhole temperature data is available.

Thickening time charts should be attached to all lab reports. Proper slurry design should be employed to avoid gelation while the cement is being pumped (See Figure 4).

Figure 4

70 Unacceptable

Gelation Spike

40 ------------------------------------------------------------------Consistency (Bc)

0 Time

For liner slurries, the thickening time test should include a 20 minute hesitation time (static time) after placement time has been reached. This simulates a 20 minute shutdown to release the drillpipe from the liner top.




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For batch mixed slurries, the thickening time test should include a simulated surface retention time on the HPHT consistometer prior to increasing pressure and temperature to downhole conditions.

2. Density

The density of cement slurries is usually determined in the lab by mass balance calculations. For slurries containing microspheres (hollow spheres), the density should be verified using a pressurized mud balance after proper mixing.

3. Compressive Strength

Compressive strength tests should be conducted as per API RP 10B procedures. In some cases it may be beneficial to precondition cement slurries at BHCT prior to the compressive strength test. This should be noted on the lab report.

a. Ultrasonic Cement Analyzer (UCA)

The UCA chart should be attached to all lab reports.

b. Crush TestThe crush test may be performed using cube molds as per API RP 10B procedures. Another option is to use the UCA cylindrical sample. When removed from the UCA cell, it may be crushed to confirm the UCA compressive strength value.

4. Fluid Loss

Fluid loss tests below 190o F should not be performed according to current API RP 10B procedures. Instead, the cell should be preheated to BHCT, filled with conditioned cement slurry, 1000 psi pressure applied from the top, and fluid loss measured for 30 minutes. For tests above 190o F, a high temperature cell should be used and tests performed according to current API RP 10B procedures. The 325 mesh screens used in fluid loss testing should be thoroughly cleaned. The screens should be thrown away after they are used when testing cement slurries containing latex or




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“pseudo-latex” (poly vinyl acetate) additive.

5. Free Water

Follow API RP 10B Section 15, with the following exceptions:

Conditioning in an atmospheric consistometer is acceptable.

Time to temperature of 6 minutes is not required.

Conduct the operating free water test with a heated static period at BHCT or 194o F, whichever is lower. For deviated wells, place the graduated cylinder at 45o angle in the water bath.

6. Rheological Properties

Rheologies and 10 s / 10 m gel strengths should be measured using a Fann viscometer as per current API RP 10B proceduresIt is important to use a heated cup at BHCT when measuring the rheological properties.

7. Mixability

Mix slurry as per current API RP 10B procedures 4000 rpm for 15 seconds and 12,000 rpm for 35 seconds). If the slurry contains microspheres, the 12,000 rpm may be replaced by 4000 rpm.

Cement is added to the mixing water during the first 15 seconds of mixing. The “time required to add cement to the mixing water” should not exceed 15 seconds. The mixability or “time required to add cement to the mixing water” should be recorded on all lab reports.

8. Compatibility

Compatibility tests should conducted by mixing varying percentages of cement/spacer or spacer/mud and conditioning at atmospheric temperature for 20 minutes. Rheological testing is then performed at room temperature and at BHCT in a heated cup. The percentages of




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cement/spacer or spacer/mud should be conducted at 100/0, 95/5, 75/25, 50/50, 25/75, 5/95, and 0/100, respectively. If the calculated PV/YP of any of the mixtures is 1.5x greater or less than the 100/0 or 0/100 values, then the fluids are deemed incompatible. For high temperature applications above 190 oF, the compatibility tests should be conducted at 190 oF.

9. Special Tests

a. Transition Time

For all production casing cement slurries, the transition time (dynamic transition time determined from the thickening time test) should be reported on the lab report. Short transition times (< 30 minutes) may be beneficial to help prevent formation fluid influx into the wellbore.

b. Density Segregation

For higher temperature cementing (> 200 F), the “BP Settling Test” should be performed to determine if density segregation is a problem.

c. Shear Bond

The cementing contractor should have available shear bond molds to perform shear bond testing for critical production casing cement testing.

d. Expansion

When expansive additives are being used in a cement design, expansion tests should be conducted using linear molds. The linear expansion of a cement slurry should never be more than 1.5 %.

e. Microsphere testing




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For density, free water, and rheological testing, microsphere slurries should be prepared as follows;

Mix slurry at 4000 rpm – do not mix at 12,000 rpm Place cement slurry in plastic bag and tie off Place plastic bag in autoclave or HPHT consistometer and

pressurize to estimated maximum ECD pressure Remove bag from autoclave Measure density with pressurized mud balance Condition slurries in atmospheric consistometer for 20 minutes

at BHCT Perform rheological and free water testing

2.2.4 Blend Testing

1. Plant Blend

A proper plant blend sample is a composite of all cement loaded for a specific cement job. In-line bulk samples from each load are collected and then mixed to form a plant blend composite sample. Plant blends should be performed for all cement jobs deemed critical, i.e. long placement times, higher temperatures, complex blends, unconventional densities, new or variable cements, etc.

If a plant blend test fails, then the cement should be dumped, or liquid additives used to properly adjust the cement design to the required performance properties.

An improper plant blend is a small (50 – 100 sk) blended cement that is taken prior to loading all of the cement. This type of plant blend test only tests that the first 50-100 sacks that are loaded. Even if this test passes, it leaves the remaining cement to be loaded untested. This plant blend test is not therefore not representative of the entire cement blend that will be pumped.

2. Mix Water




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For plant blend testing, the location mix water and location liquid additives should be used.

2.2.5 Onsite QC

1. Dry Cement Sampling

A total of three (3) 1-gallon samples of dry cement blend should be collected in a plastic sample bag from the bulk cement supply lines or surge tank after cementing, and stored in a dry area on location for the remainder of the well in case there are job issues that arise.

2. Cement Slurry Sampling

Cement slurry density should be measured at regular intervals during cement slurry mixing. Catch at least 2 cup samples from each planned slurry density. Place samples as far away from noise and mechanical vibrations as possible, to prevent major free water separation.

Note: Set times of the surface samples may not be accurate due to lack of bottomhole temperature, and also evaporation due to atmospheric exposure.

2. Mix Water Testing

In areas where water hardness and composition varies, the location mix water should be tested with a mix water kit including chlorides and sulfate content, pH, and specific gravity. In cases where the mix water is suspect and may contain organic materials that would retard the cement, the location water should be sent to the lab for cement slurry tests.

2.3 Cement Slurry Design

2.3.1 Cement Slurry Properties




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There are six (6) major slurry performance properties that are tested for each cement design. These include slurry density, thickening time, compressive strength, fluid loss, free water, and rheology.

The slurry property recommendations in Table 1 are generally accepted values that should be considered on a global basis.

Table 1 – Recommended Slurry Properties

Casing StringThickening Time Test

(TTT)

Transition Time

Compressive Strength1

Free Water1

Fluid Loss

Yield Point

Shear Bond

Initial SetAt

Drillout24 hr

72 hr

(hr:min) (hr:min) (hr:min) (psi) (psi) (psi) (%) (ml/30min)(lb/100

ft2)(psi)

Surface Lead PT2+ 1 hr NR3< TTT + 4

hrs50 > 250 NR 2.0 NR NR NR

Surface Tail PT+ 1 hr NR< TTT + 4

hrs500 > 800 1200 2.0 NR NR NR

Intermediate Lead PT+ 1 hr NR< TTT + 3

hrs50 > 250 NR 1.0 NR < 15 NR

Intermediate PT+ 1 hr NR< TTT + 3

hrs500 NR 1200 1.0 NR < 15 NR

Drilling Liner PT+ 1 hr NR< TTT + 3

hrs500 > 1500 NR 0.0 < 150 < 15 NR

Production Casing PT+ 1 hr < 30 min< TTT + 2

hrsNR > 1500 NR 0.0 < 100 < 15

> 300 psi

Production Liner PT+ 1 hr < 30 min< TTT + 2

hrsNR > 1500 NR 0.0 < 70 < 15

> 300 psi

Note: For a lner Thickening Time Test, hesitate for 20 mins after placement time and restart the consistometer

1 Local regulatory requirements supercede chart recommendations

2 PT = Placement Time 3 NR = No Requirement

1. Slurry Density

The cement slurry density should be specified to be as high as possible throughout the cemented interval without causing formation breakdown during placement. In general, the cement density should be a minimum of 1.0 ppg heavier than the drilling fluid density in the hole at the time of cementing. Slurry density also may be varied in order to achieve optimum cement slurry properties.




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Use cementing simulation software provided by the cementing contractor to determine optimum density, rheologies, and pumping rate to successfully achieve the desired Top-Of-Cement (TOC).

2. Thickening Time

For all thickening time tests, the elapsed time to 40 Bc, 70 Bc, and 100 Bc should be measured in hours and minutes, with the 70 Bc figure taken as the measured thickening time. The difference between the 100 Bc and 40 Bc times should be used as an indication of rate at which the cement slurry changes from a pumpable to an unpumpable condition, and is noted as the transition time. The 40 Bc,70 Bc, and 100 Bc measurements should be reported on all thickening time tests.

Thickening time is to be specified to allow for mixing and placement of slurries, plus an allowance for possible equipment failure and downtime. In general, slurry mix rates of 5-8 bbl/min should be allowed for in design calculations. If the cement density is +/- 14 ppg or higher, then use 5.0 bbl/min. For lighter weight slurries in the +/-12.0 ppg range, use 8.0 bbl/min. These rates are based on maximum pumping rates that can be reasonably achieved in the field with a conventional re-circulating mixer, while still maintaining uniform slurry density. On this basis, thickening time requirements are to be calculated as the sum of the following:

Lead Thickening Time = Lead slurry mixing time + Tail slurry mixing time + Time to launch top plug + Displacement time + Safety Factor

Tail Thickening Time = Total tail slurry mixing time + Time to launch top plug + Displacement time + Safety Factor

As a rule of thumb, 15 minutes should be allowed to launch the top cementing plug, and one hour should be allowed for equipment breakdown safety factor. The other time elements will have to be calculated based on the fluid volumes to be pumped and the planned pumping rates.

Use synthetic retarders instead of lignin retarders when they are required




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to help control thickening time at higher temperatures.

3. Compressive Strength

Cement slurries placed in the annulus should set as soon as possible. The recommended compressive strength values are shown in Table 1. Note that a properly designed slurry will have an initial set time (time to gain 50 psi compressive strength) only slightly longer than the thickening time value.

Although ultimate compressive strength is not the most important cement slurry parameter, it should be noted that a cement with more compressive strength would promote a stronger shear bond with the casing and formation.

4. Fluid Loss

For most wells drilled, the cement filtrate loss is controlled by the mud filter cake that is deposited during drilling. However, for slurries that will contact producing formations, slurry design should include the addition of fluid loss additive as a precautionary measure. For the applications described below, API fluid loss determined at 1000 psi differential pressure should be as follows:

For production liners, specify 70 ml/30 minutes, or less

For primary cementing of casing through productive intervals, specify 100 ml/30 minutes, or less

For drilling liners, specify 150 ml/30 minutes, or less

For primary cementing of casing through non-productive intervals, there is no recommended requirement.

For air drilled hole sections through non-productive intervals, specify at least 350 ml/30 minutes, or less




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5. Free Water

The API free water content of all slurry designs shall be specified as shown in Table 1, less than 2.0 % for surface casings, less than 1.0 % for intermediate casings, and 0 % for drilling liners, production liners, and production casings. This applies to vertical as well as inclined free water tests.

6. Rheological Properties

Rheological properties of the cement are to be specified to ensure that the slurry is as thin as possible without violating free water requirements. The recommended low YPs given in Table 1 will help ensure low ECDs, ease in mixing, and turbulent or high laminar flow regimes. The cement slurry should never be designed to pump in plug flow.

2.3.2 High Temperature Slurry Design

For wells with anticipated bottom-hole static temperatures of 230o F or above, the cement slurry must be designed to prevent cement strength retrogression. This can be accomplished through the addition of 15–40 % by weight of silica sand or silica flour. In general, silica flour ground to 325 mesh is to be used at temperatures between 230o F and 350o F. Coarser silica (200 mesh / 100 mesh) is to be used at temperatures above 350 F. However, combinations of varying mesh sizes have also been used together effectively. In all cases, compressive strength performance should be tested at static bottomhole conditions over a minimum period of 7 days to determine if retrogression will occur.

For steam injection wells, 35 % - 60 % by weight of silica sand or silica flour should be added to the cement.

2.4 Special Cementing Challenges

2.4.1 Annular Gas Flow




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Annular gas flow can occur by flowing through the cement sheath (See Figure 5) or can be the result of leakage at the cement/casing or cement/formation interface.

Figure 5 – Gas channel

When cementing across troublesome gas producing intervals, apply the following recommendations to prevent gas flow through the unset cement.

Use foam cement or a gas-generating additive (alumina) to give the cement compressibility to prevent gas influx.

Use low fluid loss cement (< 70 cc/30 min)

Use fast setting cements and right angle set cements For liners, set a liner top packer after cementing

Use expanding cements (gas generating additives will also cause cement expansion)

Do not mechanically disturb the casing (nipple up BOPs or cut casing, e.g.) until the cement has set (50 psi compressive strength)

When cementing across troublesome gas producing intervals, the following ____________________________________________________________________________________Cementing Best Practices 27 04/17/2023 Revision 1



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recommendations should be considered to prevent gas leakage along the set cement interfaces.

Use a post set expanding agent such as magnesium oxide additive

Sandblast the casing to increase shear bond

Displace the cement job with a lighter fluid so that a microannulus will not be formed during completions operations

Use a fast setting cement

2.4.2 Lost Circulation

The greatest challenge in cementing wells is preventing lost circulation before or during cementing operations. The following bullets outline potential solutions to this common problem.

Prevent losses before running casing – It is important to have full returns before beginning cementing operations. It is very difficult to regain circulation during cementing if losses are occurring while circulating mud. To prevent losses while drilling, running casing, and conditioning the well, refer to Drilling Fluids Best Practices (Section 2.1.10).

Spot LCM Pill – For severe losses, spot an LCM pill prior to POOH with drillpipe. Refer to Drilling Fluids Best Practices(Section 2.1.10).

Running casing - Based on the anticipated drilling fluid rheology while running casing, maximum casing running speeds should be specified that will avoid formation break-down and/or loss of whole mud to weak zones. Consider surge reduction float equipment.

Thin mud – To help prevent losses during cementing, consider pumping a large volume (150 – 250 bbls, e.g.) of sufficient density thin mud (YP < 10) ahead of the spacer and cement.




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Thin Cement – Design cement slurries for YPs < 10, if possible, to reduce

ECDs while cementing.

Reactive cross-linked spacers – A gelled sodium metasilicate spacer has been successful in regaining losses while cementing in severe loss situations, especially when used in conjunction with spotting LCM pill before POOH with drilling assembly.

Foam Cement – Foam cement (foam density 8 – 12 ppg) has been successful in gaining full cement returns to surface.

Hollow Spheres – Microspheres or glass beads can be used with foam cement to reduce cement density to as low as 4 ppg to achieve full cement returns in severe loss situations.

Simulate ECDs / Pump Rate – Use cementing contractor simulation software to model ECDs and remain below fracturing gradient of weak formations. Control ECD’s with cement slurry density, rheology, and pump rate.

Stage Tools – A two stage cement job employing cementing stage tools (with or without integral external casing packers) can be performed to achieve full returns when a full column of cement cannot be obtained with one stage.

2.4.3 Liner Cementing

The following pre-cement job circulating recommendations are given for cementing liners:

1. Cuttings should be removed from the wellbore prior to running or setting liner hanger as per Drilling Fluids Best Practice (Section 2.1.2).

2. After setting the liner hanger, begin circulating mud at low rate (1-2 BPM) and slowly increase to cementing rate.




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3. Maintain a constant circulating rate and pressure before pumping spacer

or cement.

4. If pressures are abnormally high or erratic while circulating mud, the liner hanger may be packing off. Review situation.

5. If there is any concern about packoff while circulating, reduce the amount of spacer to 10 bbls and reduce the cement volume excess.

6. If losses occur when circulating, proceed with cement job.

The following items are key issues that are critical to successful conventional liner cementing. These key items are intended to be the basics, but are not intended to be ALL of the issues that are involved in designing and executing successful liner cementing jobs. Each item represents a key issue that should be addressed AFTER the liner size has already been chosen.

Conventional Liner Cementing Best Practices

Liner should be run to provide a minimum of 300 feet of overlap with previous existing casing. Run a float collar and float shoe.

Bow spring centralizers should be used in the lap region and achieve a minimum standoff off of 70%.

Cementing simulation software should be utilized to design the maximum cementing rate to be used while maintaining a safe ECD. Liner hanger clearances and casing collar information should be included to achieve accurate predictions.

A weighted spacer system should be used that is compatible with the drilling fluid. The weighted spacer should be 0.5 ppg heavier than the drilling fluid weight (or half way between drilling fluid weight and cement slurry weight). Enough spacer should be pumped to provide a minimum of 500 ft. of annular fill or 10 minute contact time. Run an additional 5 bbls of spacer behind the bottom wiper plug.




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The cement volume should be calculated based on caliper readings plus

10% – 15% excess cement, and should include 300 feet of cement fill on top of liner.

The height of cement above the top of liner should be recalculated using actual calculated job volumes of cement to be pumped (as above) but assume gauge open hole. (Note that the reason for this second calculation is to ensure that it is clearly understood where the top of cement will be in relation to top of liner if the open hole is in gauge).

Circulation should be established while the liner is still inside the deepest existing casing and before the liner is run into the open hole. Circulate the well a total of at least one hole volume to break the static gel strength of the drilling fluid system. The ECD applied to the formation will be less at this point as annular clearance will normally be greater at this point in time than when the liner is on bottom.

In most cases it is recommended to hang the liner prior to commencing cementing operations, and use pipe rotation to achieve a successful cementation. Setting the liner hanger first will help eliminate the risk of excessive time hanging the liner while cement is on the backside of the drill pipe, which can result in a stuck drillstring. If a rotating liner is not available, the liner should be reciprocated while cementing, and the liner hanger set after the cement slurry is placed

Maintain Displacement pump rates should be constant while launching liner plugs.. Slowing the rate down to launch a liner plug can cause the dart to “wobble” and bypass displacement fluid.

When the liner wiper plug is encountered, the volume pumped should be noted and recordedas referenced by displacement tanks (and barrel counter).

Prior to landing the plug, the pump rate should be dropped to approximately 3 bpm.




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All drill pipe should be immediately pulled from the well after checking the

floats at the end of displacement of the primary cement. If the floats do not hold, shut in, set liner top packer, and pull DP out of hole. If there is no liner top packer used, shut in well, wait 15 minutes, and pull drillpipe out of hole.

Drill pipe removal speed should be controlled to prevent swab/surge pressures that can negatively affect the cement left in the well below the top of the liner.

Should the drill pipe become stuck and fail to pull completely out of the well, immediately start pumping the short way at the maximum rate possible to help remove any restriction in the annulus between the drill pipe and the casing.

Note: The short way in most cases involves pumping down the annulus between the drill pipe and the casing with returns to surface through the drill pipe. Calculate the displacement volumes required each way before the job commences (i.e. before starting pumping operations).

Determine the maximum pumping rate possible that will help erode and remove the restriction in the annulus while minimizing negative effects, such as excessive ECD’s (equivalent circulating densities) on the top of the lap, and potential bridging by solids settling in the drill pipe and casing annulus.

Continue pumping the short way until a) the drill pipe is free to pull completely out of the well, or b) the maximum safe pressure limit is reached.

2.4.4 Salt Sections

For cements to be used across massive salt sections, slurry formulations incorporating 18 % - 31% salt by weight of cement (bwoc) should be used. Spacer salinity should match that of the cement slurry.




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For plastic salt sections capable of moving and collapsing casing, 5 % KCL slurries with fast setting properties should be used in conjunction with heavy walled casing.

2.4.5 Reactive Shales

When cementing across reactive shales, especially at the casing point, consider using 18 % salt or 7 % KCL bwoc in the spacer and cement design to inhibit deteoration of the cement/formation bond.

2.4.6 Long Ratholes

It should not be necessary to spot a weighted pill when cementing off-bottom. It is a very low risk that cement will fall into the rathole after cementing. Spotting a viscous/heavy pill prior to running the casing can be detrimental to the quality of the cement job (i.e. mud removal may be more difficult).

2.4.7 Steam Injection

Steam injection or producing wells should use at least 40 % silica flour or silica sand in the cement design. To help long term integrity under steam cycling, the cement should be designed with an expansion additive to achieve 0.5 – 1.5 % linear post-set expansion. Expansion should be measured at both pre and post steam temperatures. Additionally, long term compressive strength testing should be performed to ensure that the cement design could withstand the high temperatures. In some cases, a calcium aluminate cement must be used instead of conventional Portland cement.

2.4.8 Foam Cement

Foam cement is an effective cementing composition due to its low density, compressibility, high strength-to-density ratio, and its long term ductility.




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Foam Cement Safety

Nitrogen Lines should be tested 2000 psi +- higher than the cement lines. Often, cement lines are tested to 5000 psi and nitrogen lines to 7000 psi. Even though the cement slurry line pressure may be 3000 psi, the nitrogen line pressure may be 5000 psi.

Nitrogen is stored at an extremely cold temperature, pumped through a heat exchanger and is placed downhole as a gas. Cryogenics and energized fluids must be handled with extreme caution.

If there is any chance of foam cement being circulated to surface during the job, annular returns must controlled (shut in, divert, etc.).

In rare occurrences, when drilling up a foamed cement shoe or liner top, nitrogen gas has been released and this “kick” must be identified and circulated out. This can also occur if an unset foam cement becomes unstable.

2.4.9 Corrosive Environments

Set cement is susceptible to chemical attack by formation fluids and completion fluids throughout the life of the well. In CO2 or H2S environments mixed with water, carbonic acid and sulfuric acid can be formed respectively. Additionally, HCl or HF acid jobs may be performed when completing the well, and these acids may contact the cement.

Another potential detriment to set cement is the presence of sulfates. Sulfates in the mixing water or in the formation waters can react with cement to expand the cement potentially causing it to crack and crumble.

For acidic environments, the cement design should include the following:

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seal microannuli and preventing acid from moving up the annulus, thus reducing exposure

Add a true liquid latex> 10 % by weight to the slurry design Do not use powdered “latex” in small concentrations. This will not

reduce the acid solubility

Another potential detriment to set cement is the presence of sulfates. Sulfates in the mixing water or in the formation waters can react with cement to expand the cement potentially causing it to crack and crumble.

For sulfate resistance, the cement design should include the following:

Use HSR cement (cements containing less than 3 % Tricalcium Aluminate)

Add 50 % Pozzoland bwoc to reduce sulfate reactivity

3.0 Primary Cementing Operations

3.1 Mixing and Pumping Cement

3.1.1 Pre-job Procedures

The cementer is responsible for execution of all on-location procedures prior to cementing operations, and should perform cementing duties as described below.

1. Prior to the cement job, obtain up-to-date information and cementing objectives from the OXY Drill Site Manager. This information should include:

o Hole size with caliper data or required excess factoro Casing length, size, and weighto Drill pipe length, size, and weighto Shoe track dimensionso Required length of tail cemento Liner hanger configurationo Any other pertinent information




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2. Confirm that sufficient equipment and material requirements (including mixing

water quantities) are on location for the job.

3. Review cement and spacer formulations with the Cementing Contractor Engineer.

4. Review laboratory blend test results, paying special attention to the thickening time and the required WOC.

5. Calculate cement volumes in units applicable to each Business Unit, including sacks of cement required for the lead and tail formulations. The calculations should also include a breakdown of these volumes showing cased hole, open hole, and shoe track capacities.

6. Calculate the mix water requirement, liquid additive requirements (if any), and the resultant mix fluid volume for both lead and tail cement slurries.

7. Calculate spacer volumes and material requirements, taking into account available mixing space.

8. Verify that suction rates required for the job can be achieved with both drilling fluid and water.

9. Calculate displacement volumes for the casing or liner and drillpipe as required.

10.Develop a pumping schedule based on the cement job simulator output.

11.Determine whether the available pumping time as indicated by the laboratory thickening time test result is sufficient for the planned job.

12.Prepare a job plan that includes the following;

Rig up procedure Safety concerns Pressure testing procedure Spacer type, density, and volumes to be pumped




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Wiper plugs, dart/ball dropping sequence and procedure Cement slurry formulation(s), densities, and volumes Conversion factors for calculating sacks per unit volume of slurry, and unit

volume of slurry per unit volume of mix water Pumping schedule indicating rates, volumes, and times for pumping a

displacing each fluid Total job time including time to drop plugs and flush lines Anticipated job pressures during pumping, shearing, or bumping of darts or

plugs In-hole hydrostatic pressures of each fluid after placement Personnel requirements for the job Contingency plans for the unexpected; liner top packer fails, float

equipment fails, loss of returns while going in the hole WOC criteria prior to rigging down any well-control devices

13. If supplying the wiper plugs and cementing head, verify that the correct equipment is on location and that the cementing head and associated connections match and have been pressure tested.

14.Load the wiper plugs in the presence of the OXY Drill Site Manager.

15.Review checklists, lab test results (available pumping time and WOC time) and job plan with the OXY Drill Site Manager.

16.Prepare spacer as required and check the weight with a pressurized mud balance.

3.1.2 Job Procedures

The Oxy Drill Site Manager and the Cementer should perform the job procedure that includes the following steps.

1. Hold a safety meeting on the rig floor to review the job procedures, assign support responsibilities, and address safety issues. Maintain an open line of communication to the rig floor throughout the job.




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2. Use a data acquisition system to record pressure, rate, density, and

volumes pumped during job.

3. Pump spacer to break circulation.

4. Pressure test all cement lines to a pressure 1000 psi above that which is expected during the cementing operation.

5. Pressurize the bulk cement tanks.

6. Pump the spacer.

7. Drop the bottom plug. The cementer is responsible for seeing that wiper plugs, darts, or balls are released at appropriate times. The Oxy Drill Site Manager should witness the loading of all plugs into the cement head.

8. Mix and pump lead cement.

9. Mix and pump tail cement. Be sure that the lead cement mix has completely cleared the mixing tub before increasing the density to the tail cement specifications. Make sure the final 10 bbls of cement slurry is high quality cement (0.1 – 0.2 ppg higher than designed density).

10. Count and record mix water volume.

11. Confirm cement densities with a pressurized mud scale and catch cup samples of cement slurry.

12. Close cementing head valve and open wash up line for critical cementing operations.

13. Close wash up line, open cement head valve, and drop top plug.

14. Displace job with cement unit or with rig pump. To avoid displacement volume error, do not switch from cement unit to rig pump, or vice versa, during displacement. When using the rig pump to displace, the pump efficiency should be known and applied to achieve accurate displacement.




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Dependent upon mud type, rig pump efficiencies may range from 93 – 98 %.

15. Slow pump rate before bumping plug.

16. If plug does not bump, pump theoretical displacement volume + ½ shoe track volume and shut down.

17. Check float equipment. If floats are leaking, shut in casing.

18. The cementing service company should manually record the following events during the job.

Pressure test, psi and time Start time for job Dropping of any plugs, darts, or balls Start and stop time for each fluid pumped Start of displacement Land or shearing of any plug or dart, and the observed pressure Mud returns and losses Cement returns Any unexpected pressure changes and any unscheduled

shutdowns Cement slurry lift pressure Top plug bumping pressure and whether or not floats held Cement in place

19. For surface wellhead systems, monitor casing annulus for pressure build-up while cement sets.

20. Take three separate one-gallon mix water samples from the displacement tank or tank truck, and 3 separate one-gallon dry cement samples from the surge tank or transfer line after the job. Label and retain samples for possible lab testing until the well is completed.

3.1.3 Pressure Test Lines




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Pressure test all cementing lines and the cementing manifold with water or spacer prior to pumping any fluid into the casing. Test pressure is to be at least 1000 psi above maximum anticipated pumping pressure during cementing operations.

3.1.4 Density Control

The cementing unit’s automatic density control should be utilized to maintain cement density at +- 0.2 ppg within planned density throughout mixing. For small volumes (< 100 bbl cement), consider batch mixing.

3.1.5 Pump Rate

Cement slurry density should not be sacrificed for pump rate. Mix cement at the maximum mixing rate where density can still be accurately controlled.

3.1.6 Data Acquisition

Fluid densities, pump rate, pressure, and volumes pumped should be recorded and submitted to the Oxy Drill Site Manager in an excel spreadsheet. If the rig pumps are displacing the cement job, the cementing lines should be opened and configured to allow the cement unit to record displacement pressures.

3.1.7 Displacement

1. Volume

Actual displacement should not be more than theoretical displacement + ½ shoe track volume.

Selected joints of casing and drillpipe should be callipered to achieve correct volume capacity and an accurate displacement volume.




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When using a cement unit to displace, the cementer should fill the displacement tanks high, and empty the displacement tanks completely, i.e. “fill high, suck low”.

When using the rig pumps to displace, calculation of the total mud pump strokes to displace the top plug to the float collar should be based on the contractor's record of pump displacement efficiencies measured during previous cement jobs. It must be remembered that displacement efficiency will be a function of liner size, pump rate, and pumping pressure. If the displacement efficiency is not known, assume an efficiency of 97% (WBM) and 95 % (OBM) as a first approximation. If rig pump efficiency is unknown, utilize the cement pumps as the first option.

2. U-Tube

If mud returns are being taken to surface while cementing, a constant record of mud return volume should be maintained by the mud loggers and checked against the theoretical volume of mud returns.

Recognize displacement U-Tube effects. When the casing is on a vacuum, the volume of mud returned to the surface will exceed the theoretical volume of mud returns (based on the actual volume of cement and mud pumped at surface). When the cement U-tube balances, the mud return rate may go to zero as the displacement fluid catches up with the cement. This phenomenon may produce a complete loss of mud returns; however, it should not be confused with whole mud losses to the formation.

3. Bumping the Plug

The pump rate should be reduced before bumping the plug. Bump the plug to 500 psi over final circulating pressure.




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3.1.8 Pumping Casing Out of Hole

For large diameter casing strings, the force exerted on the bottom of the casing due to hydrostatic pressure and annular pressure losses should be determined to help ensure that the casing will not be pumped out of the hole during cementing operations. If it is possible for the casing to be pumped off bottom, then cement slurry density and/or displacement rates will have to be adjusted to ensure the casing remains on bottom.

3.2 Float Equipment

Casing float equipment should be specified to ensure the success of primary cementing operations. In general, the following float equipment specifications are to be followed:

For 30" and 20" diameter casing, a positive acting, single valve float shoe assembly should be used. A float collar will not be required unless dictated by well specific conditions. Inner string cementing may be used as appropriate, however the potential for casing collapse should be determined.

For 16” and smaller diameter casing, a positive acting, single valve float shoe and a positive acting, single valve float collar spaced two pipe lengths apart should be used.

For 7" and 5" liners, a double valve, positive acting float shoe and a conventional liner wiper plug landing collar complete with a profile to accept a latchdown wiper plug, should be used. Float shoe and float collar should be positioned at least two pipe lengths apart.

The float shoe and float collar joints should be visually inspected by the Drill Site Manager or Drilling Engineer to ensure that the float shoe, shoe track joint, and float collar have been installed using thread locking compound.

Float collars and plug landing collars should be compatible with the cement wiper plugs to ensure proper sealing of the plug on the landing area.




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3.3 Cement Wiper Plugs

Use top and bottom wiper plugs. The bottom plug is used to separate the spacer and cement in the casing, and wipe the mud film off of the casing prior to the passing of cement and the top plug. The top plug separates the cement from the displacement fluid and provides a positive pressure indication when it lands on the float collar or landing baffle. If the cement slurry contains lost circulation material (LCM), the bottom plug should have a full opening bypass so that LCM does not bridge in the bottom plug.

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

Check the order of loading. The bottom plug is red or yellow and is hollow, and is loaded first. The top plug is black and is loaded second, on top of the bottom plug. The bottom plug contains a rubber diaphragm (or plastic burst disk) that ruptures at +- 300 psi. Do not slit diaphragm or shatter disk prior to loading.

Cement wiper plugs should be used with casing sizes 16" and smaller according to the following schedule:

Casings: If cementing conventionally with full bore landing string to surface, use a top and bottom non-rotating plug system. Under certain circumstances it may be advisable to use more than one bottom plug to ensure segregation of spacers and/or flushes. This requirement is to be reviewed based on well specific requirements. If using subsea cementing system, only run a top plug

Liners: A single liner wiper plug complete with latch down facility for landing/latching in landing collar should be run. For casing sizes requiring the use of two cementing plugs, the bottom plug should be launched following the spacer and/or pre-flush. The top plug should be launched behind the tail slurry with allowance for +/- 2.0 bbls of cement on top of the plug. For 5 ½” production liners and smaller, wash lines clean after




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pumping cement before displacing so that no cement is placed on top of the plug.Note: Two plug liner systems are now available, and are recommended if available.

3.4 Post Cement Job Operations

3.4.1 Wait on Cement (WOC)

For operations, WOC is the waiting time required after cementing in order to safely remove well control equipment or to allow the well to be underbalanced. For this operation, cement compressive strength should be 50 psi.

For drilling out the shoe track, the cement compressive strength should attain a compressive strength of 500 psi. This will provide the bond strength needed to support the shoe track as it is being drilled. The time to 500 psi is most efficiently determined through lab testing with the UCA, which plots strength development over time.

3.4.2 Nippling Down BOPs

For development wells with trusted offset information showing no gas flow history, it is advisable to nipple down BOPS immediately after confirming that there is no flow after cementing. The more time the cement gels, the more chance of gas influx.

For exploration wells, or for development wells with offset information showing gas flow history, do not nipple down BOPs until the cement has reached 50 psi compressive strength. It is advisable to use a lead cement with fast setting characteristics, such that the cement has 50 psi compressive strength in 6-8 hours.

3.4.3 Pressure Test Casing

Casing pressure testing procedures and test pressures will be specified in the ____________________________________________________________________________________Cementing Best Practices 44 04/17/2023 Revision 1



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drilling program for a specific well. However, it should be the responsibility of the drilling supervisor to check the figures at the wellsite to ensure that the casing is not burst or collapsed through negligence. Casing and liner pressure testing should be performed as outlined below..

1. All casing strings should be pressure tested in conjunction with pressure testing of the BOP stack blind/shear rams. This is to be performed as the last pressure test during the BOP test sequence (except as noted in Point 2 below). Casing test pressures should not exceed 80% of the internal yield pressure of the casing or 80% of the casing connector pressure rating, whichever is lower. If the Drilling Program calls for use of a higher test pressure, consult with Drilling Superintendent, Engineer, or Manager to confirm test pressures.

2. If it is required to run a cement evaluation log (CBL or Ultrasonic), then pressure testing of the casing and blind/shear rams should be performed following completion of the logging run. Another option is to perform the casing pressure test immediately after bumping the plug at the end of a cement job for 30 minutes. Ensure that the float equipment is rated to withstand the pressure test loads.

3. The casing pressure test is to be staged up in several increments, with each successive 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 30 minutes.

4. Under no circumstances should the casing test pressure exceed the working pressure rating of the ram preventers or the pressure rating of the wellhead spool section exposed to the test pressure, whichever is less.

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

6. All casing test pressures should be applied and removed slowly to avoid




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adverse dynamic loading.

7. All pressure tests should take account of the annulus fluid density relative to the fluid density inside the casing. The annulus fluid density should be assumed to be equivalent to drilling fluid down to the cement top, then sea water when offshore, or formation water when on land, from the cement top to the previous casing shoe.

8. A chart recording pressure gauge should be used on all casing pressure tests. This gauge can be supplemented by a more accurate, conventional bourdon tube pressure gauge, if required for operational reasons.

9. For all casing pressure tests, a record of applied pressure versus barrels of mud pumped should be maintained. This information is particularly useful during subsequent formation pressure testing.

3.4.4 Shoe Tests

A shoe test is usually conducted after drilling out a casing shoe and a small section of new formation (usually 10 ft of new formation). Shoe tests are performed to determine the strength of the new formation as well as the competency of the cement sheath.

1. Formation Integrity Test (FIT)

An FIT is a shoe test where the pressure is kept below the leakoff or fracturing pressure of the rock. FITs may also be performed over long openhole intervals while drilling.

2. Pressure Integrity Test (PIT)

A PIT is the general term related to pressure testing casing or formation in the wellbore, where the test pressure is kept below leakoff or fracturing pressure.




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3. Leakoff Test (LOT)

An LOT is a shoe test where pressure is increased until the formation fractures and leakoff is initiated. The test is usually stopped when leakoff pressures/gradients are obtained.

Refer to Oxy’s FIT and LOT standards to properly perform and analyze shoe tests.

3.5 Cement Sheath Evaluation

Sonic and ultrasonic logs are the most common ways to evaluate the quality of a cement job. In addition, temperature surveys can determine the location of top-of-cement, and tracer surveys can determine if hydraulic isolation has been attained.

3.5.1 Cement Evaluation Log

Cement evaluation logging tools emit sound waves (sonic and/or ultrasonic waves) to help determine the bonding and presence of set cement in the annulus.

Cement Bond Log (CBL) – is a sonic tool that sends and receives sound waves omni-directionally. The CBL can indicate the general quality of cement/casing and cement/formation bond.

Segmented Bond Tool (SBT)– is a sonic tool that measures attenuation (sound dampening) between points around the casing. Although not as accurate as an ultrasonic tool, the SBL can give a rough estimate of cement channeling.

Ultrasonic Log – is an ultrasonic tool that measures the impedance value of cement directionally around the annulus. It can be used to detect channels in the cement.

Recommended Bond Logging Procedure:




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Run CBL and ultrasonic combination log. Do not pressure test the casing before running a bond log. Run the log with 0 psi If possible log a section of free pipe. If bonding is poor, repeat log with 1000 - 2000 psi pressure If bonding is still poor, evaluate the potential causes of the poor bond log

representation

Be cautious to perform remedial cementing on a well based solely on the bond log representation. Consider if there were any problems during the cement job before squeezing. Follow the rule of thumb, “Do not squeeze because of the bond log, but use the bond log if you determine you must squeeze.”

Sometimes a good cement job is not properly represented as such by the logging tool. The following items may negatively affect the bond log representation, and show poor cement.

Casings larger than 9 5/8” or heavy walled casing New casing or varnished casing Pressure testing before running a bond log (creating a microannulus) Exchanging heavier displacement fluid with lighter completion fluids before

logging (creating a microannulus) Lightweight cement (compressive strengths < 1500 psi) Thin cement sheaths (< ¾” clearance) Logging across sandstones Uncalibrated or eccentered logging tools

To overcome the negative affects from the above items, it is important to increase shear bond to enhance the bond log representation. The following procedures will help increase shear bond.

Sandblast critical sections of casing (See Figure 6) Use expansion additives in the production cement slurry Do not pressure test casing before running a bond log Pressure the casing during logging to eliminate microannlus When using OBMs, run ample spacer with surfactant to water wet casing




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Figure 6 – Sandblasted Pipe Giving Excellent Bond

Refer to the “Oxy Cementing Bond Log Best Practice” document for more details on running bond logs.

3.5.2 Temperature Log

Temperature logs are used to identify TOC. The temperature log should be run 6–12 hrs after the cement’s initial set, when most heat is being generated by the exothermic reaction of cement hydration. A sharp temperature change of 10 – 400

F should be noticed at the TOC.

For development wells where excellent bond logs are common, consider running a temperature log for TOC determination and eliminating the bond log run.

3.5.3 Tracer Survey

Radioactive tracers may be placed in stimulation fluids to help determine if the cement sheath is providing hydraulic isolation.

3.6 Problem Jobs - “Cemented Up” Casings ____________________________________________________________________________________Cementing Best Practices 49 04/17/2023 Revision 1

Sandblasted section of casing



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One of most costly failures in cementing occurs when maximum pressure limits are reached before displacement is complete, resulting in a “cemented up” casing or liner. Premature shutdowns and “cemented up” casings unfortunately occur on a regular basis across the industry, and the cause is sometimes difficult to determine. In general, however, these catastrophic failures fall into one of the following categories.

Shutdown while PumpingMany catastrophic cementing failures occur immediately after “shutting down” and allowing the cement to remain static for a period of time. These shutdowns may be planned such as stopping to pull drillpipe from a cement plug, or unplanned, such as stopping to fix an equipment failure. Cement slurries may gel excessively during a shutdown to the point where they cannot be moved by pump pressure.

Mechanical BridgeMechanical blockages such as those listed below may cause sudden excessive pressures during the cementing operation.

o LCM, cuttings, or debris blocking float equipmento Cuttings packing off at liner hanger (However, pressures may be

increased to break down formation)o Bottom plug does not bypass fluido Liner dart does not launch liner plugo Surface equipment / manifolding plugged with cement or debris

Cement Design – Cement Flash Set Cement designs rarely “flash set”. When flash setting occurs, it usually is due to one of the following;

o Wrong cement blend sent to locationo Wrong concentration of additives in the cement blendo Contaminated cement o Certain retarders (high temp lignosulfonate retarders, e.g.) may

exhibit a threshold effect. With slight variation in retarder




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concentration or temperature, the thickening time may be reduced significantly

o Cement mixed at wrong density (This is especially critical when switching from lead cement and tail cement. Lead cement blend and additives mixed with tail cement water requirements can yield a thick “flash setting” slurry.

. Cement Contamination on Surface

Cement may be contaminated on surface by drilling mud or mixing water. If reactive spacers or other strong accelerators are being used, they should be kept separated from the cement slurry by fresh water spacers.

Cement Contamination DownholeCement slurries and drilling fluids, especially synthetic or oil based muds, are usually not compatible with cement, and can form a “non-pumpable” mass when mixed.

Plugged Surface Equipment

When cementing operations are shut down due to excessive pressures, the event should be investigated thoroughly. The following steps should be part of this thorough investigation.

1. Review the events that precede and follow the premature shutdown.a. Pressures and ratesb. Cement density variationsc. Was the cement static?

2. Determine the position of fluids and plugs when anomalous pressures occur.a. Were darts or bottom plugs landing ?b. Were spacer and cement interfaces at critical points in the well?

3. If shutdown occurs when darts or plugs landed, re-examine plug type and clearances. During drillout, examine returns to determine the location and type of plug cuttings.




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4. Check bulk callout sheets to ensure proper cement was delivered to location.

5. Interview cementer to check if any unusual events were observed during the cement job.

6. Test dry cement samples using location mix watera. Test thickening time at BHCT, BHCT plus15o F, and BHCT minus

15o F.b. Compare rheologies to original cement tests.

7. Perform cement contamination testing.a. Are the cement and mud compatible?b. Does 10 % spacer contamination accelerate the cement slurry?

8.Write a final report and submit learnings to the Oxy Cementing Communityof Practice representative.

The following general recommendations should be followed to prevent premature cementing shutdowns.

Condition the wellbore properly to remove cuttings before cementing

Do not run auto-float with narrow clearances in high LCM muds

Pump adequate volumes of spacers to separate mud and cement

When using reactive spacers, pump 10 – 15 bbls of fresh water between the spacer and cement to prevent flash setting

Minimize shutdowns while cementing

Design cement slurries to exhibit low gel strengths

Cement slurries and spacers should have the same salinity content

Do not use lignosulfonate retarders when cementing above 180o F BHCT




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Gather location samples of cement and mixing water as per Best Practices

(Sec 2.2.5)

Perform compatibility testing as per Best Practices (Sec 2.2.3 – Pt. 8)

Caliper plugs and observe loading of plugs in cementing head as per Best Practices (Sec 3.3)

4.0 Plug Cementing

As with all cementing operations, thorough planning and close adherence to good operating practices are necessary to ensure job success on the first attempt to set a Kickoff Plug. The common 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 plug on the first attempt can be traced to poor placement practices or incorrect slurry design. The guidelines outlined below should be closely reviewed prior to implementing these operations.

4.1 Plug Setting Techniques

The Balanced Plug Method and Unbalanced Plug Method are two legitimate plug setting techniques that may be used to set a kickoff plug.

4.1.1 Balanced Plug Method

Balanced Plug Method is the most popular technique to set a kickoff plug. A hydrostatically balanced plug is placed in the well, and the drillpipe is slowly removed from the balanced plug. A balanced kickoff plug is set as follows:

1. Ensure that there is a solid base on which to set the balanced plug (See “Establish Solid Base” guidelines in 4.2.2.B)

2. Run drillpipe/stinger to plug setting depth

3. Condition wellbore




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4. Pump spacer (recommended spacer length = 500 ft in annulus)

5. Drop ball to separate fluids, wipe drillpipe, and indicate cement location.

6. Pump densified cement slurry (recommended plug length = 500 – 1000 ft in openhole)

7. Drop 2nd ball.

8. Reciprocate drillpipe until cement enters the annulus

9. Pump sufficient amount of spacer to balance plug

10.Displace cement at maximum rate with drilling fluid

11.Pull drillpipe/stinger out of plug at 30 – 50 ft/min to TOC

12.Pull drillpipe an additional 1000 ft above top of cement plug (Pull at normal pull rate)

13.Circulate or reverse circulate bottoms up (Monitor returns for cement / spacer contamination) Warning concerning pressures.

14.POOH and WOC (Check lab tests for set time and compressive strength development)

15.RIH with drilling assembly – tag cement – time drill to kickoff

Note: For well depths greater than 12,000 ft , place a ball catcher in the drillstring at +- 200 ft above calculated TOC. The ball catcher will signal the location of the top of cement when the cement slurry is followed with a rubber wiper ball.

4.1.2 Unbalanced Plug Method




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The Unbalanced Plug Method is a legitimate technique that can be used to set a successful kickoff plug. The advantages of the unbalanced plug method include 1) Eliminating the difficulty of pulling wet with oil base or heavy mud in the well and 2) ease in placement since there are no balance calculations or ball catchers required. An unbalanced kickoff plug is set as follows:

1. Ensure that there is a solid base on which to set the balanced plug (See “Establish Solid Base” guidelines in 4.2.2)

2. Place IBOP in the drillstring at a depth below RKB which is equal to the theoretical height of the cement plug in the openhole. For a 1000 ft openhole plug, the IBOP would be placed at a depth of 1000 ft below RKB.

3. Run drillpipe/stinger to plug setting depth

4. Condition wellbore

5. Pump spacer (recommended spacer length = 500 ft in annulus)

6. Pump densified cement slurry (recommended plug length = 500 – 1000 ft in openhole)

7. Displace cement all the way to the bottom of the drillstring with drilling mud and a final volume of water. The water volume should equal the volume of drillpipe from surface to the IBOP.

8. Reciprocate drillpipe until cement enters the annulus

9. Displace cement at maximum rate with drilling fluid

10.Pull drillpipe WET out of plug at 30 – 50 ft/min to TOC

11.Remove IBOP

12.Pull remaining drillpipe DRY at normal pulling rates




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13.WOC (Check lab tests for set time and compressive strength development)

14.RIH with drilling assembly – tag cement - time drill to kickoff

4.2 Achieving a Stable Cement Plug

Most failed cement plugs occur because the cement plug is destabilized or contaminated during or after placement. The following best practices will help ensure a stable cement plug is achieved.

4.2.1 Stabilizing the Wellbore

Prior to setting the cement plug, cure lost circulation or formation fluid influx. Losses or flows will contaminate the cement plug. If losses or flows are occurring below the plug setting depth, run an inflatable openhole packer to stabilize the wellbore and also provide a base on which to set the plug.

4.2.2 Providing a Base

Perhaps the most important component of a successful kickoff plug is making sure that the cement is placed on a solid base. Cement plug slurries are usually more dense than the wellbore fluid and will easily fall down the wellbore if there is not a sufficient base to support the cement plug. The recommended ways to ensure a stable base include:

Set the cement plug on bottom (TD) when practical Cement on top of a previous undrilled cement plug Set a cement plug base tool (Parabow, Bottomhole Kickoff Assembly, e.g.) Set an inflatable bridge plug Spot sacrificial cement plug Spot densified mud Spot a 250 ft to 500 ft reactive sodium silicate pill – weighted if necessary *Spot a 250 ft viscous pill (funnel viscosity of 150 + sec/qt)




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* Setting viscous pills have failed many times in plug setting operations. Unless the pills are extremely viscous, they will not prevent cement slurry from falling down the well and destabilizing the plug.

4.2.3 Drillpipe, Stinger, and Diverter

For hole sizes less than 8 ½”, use a 2 7/8” or 2 3/8” tailpipe stinger on the bottom of the plug setting assembly. The stinger should be a minimum of 200 ft longer than the plug length.

For 8 ½” hole and larger, a tail pipe is not required. Use drill pipe.

A diverter sub with upward angled ports (Figure 7) should be used when cementing off-bottom.

Figure 74.2.4 Centralizers

Do not run centralizers on the plug setting string. The centralizers will serve to swab the cement plug when pulling out of the hole. Plug setting success rates near 100 % are achievable without using centralizers.

4.2.5 Pulling Drillpipe Out of the Plug

Pull drillpipe/stinger slowly out of the plug at 30 – 50 ft/min to prevent stringing the cement up the wellbore.

4.3 Wellbore Preparation for Setting Cement Plug

The wellbore should be prepared for plug cementing in the same way the wellbore is prepared for primary cementing. Recommended mud properties include:




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Yield Point - < 15 lb/100 ft2

Gel Strengths – 10 sec, 10 min, and 30 min, < 25 lb/100 ft2

Fluid Loss, API < 10 and HTHP< 15 Wash and rotate across plug interval from 200 ft above to bottom of

plug Pipe should be rotated and/or reciprocated during circulation 2 annular volumes should be circulated once pipe is on bottom Greater than 230 ft/min annular velocity Mud balanced, density in = density out

The plug is to be spotted in a section of gauge hole with minimum washouts. If necessary, a caliper log is to be run to ensure an acceptable plug setting interval. If plug spotting in a washed out section cannot be avoided, then allowance should be made for excess cement volume.

Prior to setting open hole cement plugs in old wells (i.e., previously cased off interval), consider under-reaming the open hole interval that is to be cemented. This is done in order to remove the old mud ring that may prevent a competent cement plug from setting up in the entire wellbore.

4.4 Cement Slurry Design – Plug Cementing

4.4.1 Slurry Density

In general, the density of kick-off plugs is to be +/- 17.0 ppg or higher. For shallow plugs set in softer formations, standard cement densities (15.8 – 16.4 ppg) are adequate.

4.4.2 Thickening Time

Thickening time for plug cementing shall be performed at BHCT in similar manner as for casing jobs.

Plug Slurry Thickening Time = Total slurry mixing time + Time to drop ball* +




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Displacement time + Time to pull out of plug** + Safety Factor***

*Use 10 minutes for time to drop ball**Time to pull out of plug = 30 ft/min (= 30 minutes for 900 ft plug)***Safety factor = 1 hr

4.4.3 Compressive StrengthSlurries should be formulated to develop high early and ultimate compressive strength. The compressive strength of the cement should be greater than the compressive strength of the adjacent rock In general, the 12 hr compressive strength of a cement plug should be greater than 2000 psi. The 24 hr compressive strength of a cement plug should be 3000 psi or greater.

For temperatures below 230 degrees F, neat slurries (without sand, lost circulation materials, etc.) should be used and retarded with dispersant. Above 230 degrees F, the slurry formulation should include 15-35% by weight of silica flour or silica sand to prevent strength retrogression, and synthetic retarders should be utilized.

4.4.4 Fluid Loss

For plug cement slurries, fluid loss control is not necessary when setting a kickoff plug unless the plug is being set in an air-drilled hole where mud filter cake has not been deposited.

4.4.5 Free Water

Free water for a kickoff plug should be less than 1.0 %. For deviated wells (> 30 degree angle), the free water should be 0 %.

4.4.6 Rheological Properties

The plug cement slurry should be designed to mix easily with relatively low




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viscosities. This can be achieved with a 17.0 – 17.4 ppg cement slurry containing correct concentration of dispersants.

4.4.7 Spacers for Plug Cementing

Spacers should have the following characteristics:

Be compatible with the cement and drilling mud. Leave the wellbore in a water wet condition for better bonding Maintain adequate hydraulic pressure during and after plug setting Have a density at least 0.5 ppg higher than the mud weight, and at

least 0.5 ppg lower than the cement slurry density. Be designed for turbulent flow in the annulus at the planned

displacement rate for a particular cement job. Have a salinity that matches the salinity of the cement slurry. Note:

For plug setting in reactive shales, the spacer should contain at least 18 % salt, to help inhibit clays and prevent hole collapse.

The spacer volume for setting plugs should yield a minimum fluid height of 500 feet in the drillpipe annulus.

4.5 Plug Cement Displacement

4.5.1 Ball Catcher

For plug setting using the balanced plug method, an indicating ball catcher should be placed approximately 200 ft above the theoretical TOC of the cement plug, especially when setting plugs deeper than 12,000 ft.

4.5.2 Wiper Balls

For plug setting using the balanced plug method, wiper balls should used ahead and behind cement plug to give pressure indication of the cement position, and to clean the drillpipe. Using wiper balls will help prevent “cement rings” in tool joints that can cause severe problems later (such as debris in MWD tools). Check




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temperature limitations on balls and catchers.

4.5.3 Drillpipe Caliper

The drillpipe should be physically calipered to determine the accurate drillpipe capacity.

4.6 WOC and Cement Plug Drillout

Do not attempt to kick off the cement plug until the cement has 2000 psi compressive strength. The cement slurry can be designed to achieve this strength within 12 hrs.

If the cement plug drills soft, pull out of plug a safe distance, and wait-on-cement to gain more strength.

If the cement plug drills hard and soft, this is indication that the cement plug has become unstable or contaminated.

4.7 Abandonment Cement Plugs

Abandonment plugs are to be formulated and spotted largely in accordance with the guidelines given above for kick-off plugs.

For cement abandonment plugs that are not to be drilled out, a minimum plug length of 250' should be used, although local regulatory rules must be followed. This holds true for open hole as well as cased hole plugs.

For cement plugs set inside casing, expansive agent (magnesium oxide additive, e.g.) should be considered.

5.0 Health, Safety, and Environment




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Oxy HSE Standards and practices should be performed during each cementing operation. The following safety measures specifically related to cementing should also be observed.

NIOSH-approved dust masks and standard protective goggles should be worn on the cementing unit and in the vicinity of cement dusting areas.

Wear impervious gloves when handling mixed cement slurries and cementing chemicals. Understand the MSDS sheets and hazardous nature for all the cementing materials on location. Even the cement slurry itself is a base and is corrosive in nature.

Care should be taken if gaining a sample of cement slurry from the mixing tub. Hands should remain a safe distance from the tub agitators, and goggles should be worn for protection.

Perform a cementing pre-job safety meeting prior to start of cementing operations.

Ensure that cementing lines are clear of personnel during pressure testing and pumping operations.

Ensure that the rig floor below the cement head is clear of personnel when dropping plugs.

Safety areas and escape routes should be diagrammed relative to cementing lines prior to performing a cement job, especially when pumping foam energized fluids (See Sec 2.4.8 Foam Cement)

Restrict area while cementing to authorized personnel only.

6.0 Tracking Results

It is important to track cementing success to determine if the practices being employed are working. The Oxy Cementing Scorecard should be used to track




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the success of the cement job. Ultimately it is the success of the cementing operation that will confirm which are the best cementing practices.

6.1 Key Performance Indicators (KPIs)

The following KPIs should be accurately tracked for each primary cementing operation via the Oxy Cementing Scorecard.

1. Job Count – A running total of casing strings that are cemented.

2. Cementing Contractor – Which service company performed the cementing work?

3. Casing String – What type of casing string was cemented (Conductor, Surface, Intermediate, Drilling Liner, Production Casing, Production Liner)

4. Trouble Time - How many hours of trouble time was related to cementing ? (This may include waiting on service company, downtime, remedial work, Wait-On-Cement (WOC), unplanned events on the critical path, etc)

5. Cementing Cost – What is the cost per bbl of total cementing services and materials for the casing string? What was the planned cost versus the actual cost?

6. Safety - Was there a safety incident or near miss related to the cementing operation?

7. Liner Top Test – If the job was a liner, was the liner top test successful?

8. Bond Log - Was a bond log conducted ? If yes, was the bond log graded as a) poor, b) marginal, c) good, d) outstanding ?

9. Top-Of-Cement – Did the actual Top of Cement meet the requirements of the hole section? Was cement raised high enough to adequately satisfy all critical requirements?




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10.Remedial Work - Was any remedial work / squeeze job required to repair the primary cementation ? This may be a shoe squeeze or a production casing remedial job.

11.Lost Circulation - Were there mud losses while cementing? Indicate either a) No losses, b) Partial losses, or c) Total Losses.

Additional KPIs not contained in the Oxy Cementing Scorecard may still be tracked. These include: Casing Pressure Tests, Shoe Tests, Annular Flow Incidents, Top Jobs Required, Float Equipment Holding, and Bumping Plugs

6.2 Cementing Scorecards

Scorecards must be used to track and grade “on-location” cementing performance, end results, and other operational parameters. Cementing scorecards for general primary cementing are available on the Cementing CoP Portal. (Refer to the Contract Performance Management Standard)

7.0 Contractor Requirements

In addition to the responsibilities outlined in Section 3.1 – Mixing and Pumping Cement, the Cementing Contractor should also apply the following recommendations outlined in Sections 7.1 – 7.2.

7.1 Cementing Proposal

The Cementing Contractor Engineer should be responsible for preparing a Cementing Recommendation, as requested for upcoming wells, and communicating with the OXY Drilling Engineer as required to obtain all necessary information for preparation of this document.

The Cementing Contractor Engineer should be fully capable of running the cement job simulation software, analyzing the output data and making the




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appropriate job recommendations, and should use standardized software for generating this recommendation.

The Cementing Recommendation should contain the following:

Detailed objectives of the cement job(s) Cementing operational issues and detailed solutions Thickening time requirement for the cement slurry(s) Detail of well geometry, including hole, casing, and annular volumes, and pore

and fracture pressures Required cement slurry volumes BHST and BHCT with detail on the method of calculation Cement and spacer formulations including how the designs achieve the job

objectives; The designs should include;o Slurry densities, yield, and material requirements of the proposed

slurries and spacerso Spacer density and rheological propertieso “Pilot” laboratory test results for the cement slurry formulation(s)

Operational details, pump rates, for each fluid and shear or bumping pressures for wiper plugs

A computer-generated simulation of the cement job(s) that is based on the proposed cement slurries, well information and geometries, with clear and accurate inputs. The output should include:

o Centralization spacingo Flow regime of each fluido U-tube simulation for the cement job under dynamic conditionso Temperature simulation profile of cement slurry temperatureso Well security and control (Equivalent Circulating Densities at total depth

and other selected points, graphed against pore and fracture pressures)

Displacement volumes Tabular graph of fluids positions after placement Cost estimates for service and materials




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Presentation of this report should include a hard copy and an electronic file in either Microsoft Word or Excel format. Graphs may be generated to supplement the reports.

Prior to each cementing job, the Cementing Contractor Engineer should update the respective portion of the recommendation. Updates should be referenced to initial recommendation and pertinent lab testing.

7.2 Cement Testing

All “pilot testing” data should be clearly referenced to the appropriate cementing recommendation with a unique project or job number

All laboratory testing should be conducted in a timely and accurate manner Sufficient lead-time should be incorporated into the testing program so that

the designs are ready well in advance Testing should be conducted with the representative samples of materials that

will be used on the job (bulk plant or rig samples) as appropriate. Contingency planning should be incorporated into the testing program, taking

into account variations in well parameters that may require adjustments in density or thickening time

Whenever possible, the cement job should be designed to achieve turbulent flow of the spacer in the open hole

Note: No cement slurry should be considered “approved and finalized” until the OXY Drilling Superintendent or Drilling Engineer confirms it. Do not pump this slurry design without this approval.

7.3 Pricing and Invoicing

Cementing contractor pricing and invoicing should consider using a “cost plus” scheme, as opposed to a book price minus discount. This strategy makes line item auditing easier and more accurate, and allows Oxy to pay appropriate charges (service and materials) for each job. Oxy can evaluate the actual value of any particular job when the actual costs for that job are applied to the invoice.




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7.4 Contract Specifications

Cementing contracts should be written to contain rigorous specifications for personnel, services and equipment, goods and materials, HES, and commercial/pricing. The cementing contractor should perform confirmation lab testing to ensure that the submitted slurry designs meet Oxy requirements.


cementing best practices

Documents

cement testing

cement job

cement plug drillout

stable cement plug

foam cement

pumping cement

plug cementing displacement

cement slurry properties