UNIVERSITY OF MISKOLC

FACULTY OF EARTH SCIENCE AND ENGINEERING

PETROLEUM AND NATURAL GAS INSTITUTE

PETROLEUM ENGINEERING DEPARTMENT

CEMENTING OPERTIONS AND TESTS UNDER THERMAL WELL CONDITIONS OF

ANGOLA

BSc. THESIS

YOLANDA VERONICA RAMOS BAU

DEPARTMENT SUPERVISOR: KOVÁCSNÉ FEDERER GABRIELLA

EXTERNAL SUPERVISOR: MARIA LUCAS

PETROLEUM ENGINEER

MISKOLC, DATE: 22.11.2017

CEMENTING OPERTIONS AND TESTS UNDER THERMAL WELL CONDITIONS OF

ANGOLA

2017

YOLANDA BAU

Institutional verification paper for thesis submit For BSc students in specialization oil and natural gas

Student name: Yolanda Bau Neptun - code: Zrzwfg Title of thesis: Cementing operations and tests under thermal well conditions of Angola Originality statement I, Yolanda Bau hereby declare and certify with my signature under my criminal and disciplinary responsibility as the student of the Faculty of Earth Science and Engineering at the University of Miskolc that this thesis was my own work. I complied with the regulations of the Act LXXVI of 1999 on copyrights and with the requirements of thesis writing in the University. In the thesis only the references listed in the literature were used. Literal or reworded quotations have clearly been marked as references. I declare that the electronically uploaded and paper-based documents are concurrent. By signing this declaration, I acknowledge that the University of Miskolc refuses to accept the thesis and may initiate a disciplinary procedure against me if I am not the sole creator or an infringement of copyright in the thesis can be proved. Refusing to accept a thesis and initiating a disciplinary procedure is without prejudice to any other (civil, legal, criminal, legal) consequences of copyright infringement. Miskolc, Date: 22.11.2017

student signature Statement of the Department Supervisor I, the undersigned: Kovácsné Gabriella, agree / disagree with the submitting of the thesis. Date: 23.11.2017

signature of the Supervisor Statement of the Industrial Advisor

I, the undersigned Maria Lucas, agree / disagree with the submitting of the thesis. Date: 23.11.2017

signature of the Industrial Advisor

The thesis is submitted Miskolc, Date: 27.11.2017

Administration of the Petroleum and Natural Gas Institute

MISKOLCI EGYETEM UNIVERSITY OF MISKOLC

Műszaki Földtudományi Kar Faculty of Earth Science & Engineering

KŐOLAJ ÉS FÖLDGÁZ INTÉZET PETROLEUM AND NATURAL GAS INSTITUTE

—————————————————————————————————————————————————————————————————————————————————————————— : H-3515 Miskolc-Egyetemváros, Hungary : (36) (46) 565 078 e-mail: turzoz@kfgi.uni-miskolc.hu

BS Thesis Assignment

for

MS. Yolanda Bau Title of Thesis:

Cementing operations and tests under thermal well conditions of Angola Main Tasks: Based on literature survey and outside investigations, I will introduce the generally used wells

structure, the required cementing operations used during the field, the lab experiments with usable

equipment and shortly explain the casing design cement with depth of different rock layers in a

gas and oil reservoir.

Introduce the preparation of cement slurry by using fresh water with no additional additives in

order to explain the under thermal well conditions of different wells in Angola by examining the

effect of temperature and aging during the experiment by leaving fifteen days of cement slurry

under water in an off oven and after taking more twenty days by doing differential experiment with

the dry cement, and as summary draw an appropriate conclusions from the results and present

recommendations on the operating parameters.

Faculty Advisor: Dr. Gabriella Federer Kovácsné, univ. lecturer

Field Advisor: Maria Lucas, petroleum engineer

Deadline of submission: 27 November 2017. Zoltan Turzó, PhD Head of Institute Miskolc, 1 June 2017.

TABLE OF CONTENTS

1. INTRODUCTION……….…………………………………………………………………………...1

2. CASING DESIGN…. ………………………………………………………………………………...2

2.1 INTRODUCTION ……………………………………………………………………..............2

2.1.1 CASING FUNCTION………………………………………………………………………….2

2.2 TYPE OF CASING………….……………………………………………………………………3

2.2.1 RISER PIPE……..……..………………………………………………………………………4

2.2.2 CONDUCTOR PIPE………..…………………………………………………………………4

2.2.3 SURFACE PIPE…………………..……………………………………………………………5

2.2.4 INTERMEDIATE PIPE …………………………………………………………………..……5

2.2.5 PRODUCTION PIPE…………………………………………………………………………6

2.2.6 LINERS…………………………..……………………………………………………………6

2.2.7 LINER TIEBACK STRING……….……………………………………………………………7

3. CEMENTING OPERATION……………………………………………………………………… 8

3.1 INTRODUCTION ……………………………………………………………………………….. 8

3.2 FUNCTION OF CEMENT …………….…………………………………………………………8

3.3 PORTLAND CEMENT ………………….……………………………………………………. 9

3.3.1 API CEMENT CLASSIFICATION ……………..……………………………………………10

4. TYPES OF CEMENTING ………………………………………………………………….. 11

4.1 PRIMARY CEMENTING …………………………..…………………………………………..11

4.2 PRIMARY CEMENTING TECHNIQUES……………………………………………………. 12

4.2.1 STAGE CEMENTING OPERATION…………………………………………………13

4.2.2 SINGLE STAGE CEMETING …………….………………….. ....…………………13

4.2.3 TWO STAGE CEMENTING……………………...………………………………………15

4.2.4 STAB-IN CEMENTING ………………………….………………………………………16

4.3 REMEDIAL CEMENTING ……………………………….. ………………………………….17

4.4 SQUEZE CEMENT TECHNIQUES …………………………………….……………...…...18

4.4.1 Placement………………………………………………………………………………..……19

4.4.2 Pumping ………………………………………………………………………………………19

4.4.3 Application ……………………………………………………………………………………20

4.5 PLUGS CEMENTING…………………………………………………………………………..20

5. CEMENT ADDITIVES ……………………………………………….…………………………22

5.1 INTRODUCTION……………………. …………………..……….……………………………22

5.2 TYPE OF CEMENT ADITIVES …………………………..………………………………22

5.2.1 ACCELERATORS………………………………………….……………………………….22

5.2.2 RETARDER …………………………………………………………………………………23

5.2.3 EXTENDERS……………………………………………….………………………………23

5.2.4 WEIGHTING AGENTS …………………………………….………………………………23

5.2.5 DISPERSANTS …………………………………………..………………………………24

5.2.6 FLUID LOSS CONTROL AGENTS…………………………..…………………………24

5.2.7 LOST CIRCULATION CONTROL AGENTS………………………….……………………24

6. CEMENTING EQUIPMENTS ………………………...............................................................26

6.1 FIRST STAGE CEMENTING EQUIPMENTS………………………………………………26

6.2 CASING HARDWARE ………………………………. ….……………………………26

6.3 FLOAT EQUIPMENT CONSIDERATION ………………………………………………26

6.4 GUIDE OR FLOAT SHOE …………. ……………………………………………………27

6.5 FLOAT OR LANDING COLLARS ….. ………………………………………………….28

6.6 CENTRALIZERS…………………….…………………………………………………………28

6.7 WIPPER PLUGS ……….……………………………………………………………………29

6.7.1 BOTTOM PLUG ……………………………………………………………………………29

6.7.2 TOP PLUG ………………….………………………………………………………………30

6.8 MULTI STAGE CEMENTING EQUIPMENT…………………………………………………31

6.8.1 RUNNING PLUG……………………………………………………………………………..31

6.8.2OPENING PLUG……………………………………………………………………………..31

6.8.3 CLOSING PLUG…………………………………………………………….. ……………... 32

7. CEMENT LABORATORY TESTING OPERATION …………………………………………33

7.1 OBJECTIVE OF THE TESTS …………………..…….……………………………………33

7.2 JET MIXING BLENDER……………..…………………………………………………….......34

7.2.1 PREPARATION OF SLURRY ……………………………………………………………... 34

7.3 LABORATORY MIXING QUANTITIES CALCULATION……………………………………34

7.4 CEMENT SAMPLE MOULDS………………………………………………………………… 36

7.5 SAMPLE POROSITY CALCULATION………………...………………………………..….39

7.6 CEMENT SAMPLE AFTER THREE WEEKS UNDER-WATER EXPERIMENT………….40

7.7 TEMPERATURE EFFECT ON CEMENT SHEATH…………………….………………….. 41

7.8 POROSITY AND WATER PERMEABILITY TEST …………...……..………………………41

7.8.1 LIQUID PERMEABILITY…………………………………………………………………..42

7.9. FIRST WEEK POROSITY TEST RESULTS………………………………………………42

7.9.1 FIRST WEEK PERMEABILITY TEST RESULTS…………………………………………43

7.9.2 SECOND WEEK POROSITY TEST RESULTS…………………………………………..43

7.9.3 SECOND WEEK PERMEABILITY TEST RESULTS……………………………………..43

7.9.4 THIRD WEEK POROSITY TEST RESULTS………………………………………………44

7.9.5 THIRD WEEK PERMEABILITY TEST RESULTS…………………………………………44

7.10 BASIC API RP 10B LABORATORY TETS…………………………………………………45

7.10.1 MUD BALANCE ………..………..……………………..…………………………………..45

7.10.2 RHEOMETER – RHEOLOGY…………………………………………………………46

7.10.3 FLUID LOSS –STATIC FLUID LOSS ……………………………………………………47

7.10.4 THICKENING TIME (TT) ……………………………………………………………….…48

8. CEMENTING LABORATORY TEST REPORT…………………………………………………50

8.1 CEMENT TAIL SLURRY TEST REPORT…………………………………………………50

8.2 LEAD SLURRY LAB REPORT ……………………………………………………………….53

8.3THICKENING TIME CHART REPORT ………………………………..…..………………….55

8.4 UCA CHART REPORT…………………………………………………………………………56

9. CASING CEMENT JOBS DESIGN………………………………………………………..…… 57

9.1 JOB DESIGN FOR 20 TO 10 "CSG ………………………………………………………….57

9.2 JOB DESIGN FOR (2) 9 7/8 IN AND 9 5/8 IN ………………………………………………..58

9.2.2 CASING AND HARDWARE TOOLS INFORMATION…………………………………….59

10. SUMMARY AND CONCLUSION………………………………………………………………….61

11. REFERENCES…………………………………………………………………………………...... 62

12. APPENDICES………………………………………………………………………….………….. 64

1

1. INTRODUCTION

Oil well cementing is a vital operation for wellbore completion. Which involves placing cement

slurry from the surface to several thousands of feet below the surface of the earth. Cement is

used to hold casing in place and to prevent fluid migration between subsurface formations. The

cement slurry used, consists mainly of cement, water and appropriate additives. Depending on

how the cement slurry is made or used, we can have two types of its quality, high quality of cement

slurry and the low quality. Usually the high quality of cement slurry serves the production of oil

economically and safely over the well’s lifetime. It ensures the long-term durability of wellbore by

providing a high-quality casing. Whereas poor quality of cement slurry may lead to remedial

cementing and will increase the time and cost of cementing operation.

My thesis include the introduction of cementing operation techniques used either in laboratory

and oil field, with a purpose of determining the effect of temperature and aging after leaving a

cement slurry under water for fifteen days .

To obtain really good results of aging and strength behavior of dry cement it is usually necessary

a twenty one days of curing of cement slurry under water before starting the aging test. But

according to a time that I had for the conclusion of this work I could only make it for fifteen days,

but it does not change much in the results obtained since cement develops 90% of its strength in

the first 14 days of its curing.

In this work, I will first start with a small introduction of the type of casing design that is in relation

with cement plugs and floats materials. Not forgetting the cement type and differential cement

chemical additives. Afterward I will focus on cement slurry operation during laboratory tests, the

mixing materials, explaining the effect of temperature difference during the dry cement

experiment, its aging results and the strength resistivity. And to finish, two diferential job designs

will be shown in order to give an example of how the Angolan wells are cemented partially and

the differential staging of cementing.

2

2. CASING DESIGN

2.1 INTRODUCTION

Casing is the major structural component of a well during the whole operation process starting

from the drilling until the production of the well. Casing is needed to maintain borehole stability,

prevent contamination of water sands, isolate water from producing formations, and control well

pressures during drilling and production operations. Casing provides locations for the installation

of blowout preventers, wellhead equipment, production packers, and production tubing.

The cost of casing is a major part of the overall well cost, so selection of casing size, grade,

connectors, and setting depth is a primary engineering and economic consideration .Casing which

mostly made of still pipes, are perfectly manufacture for rocks and layers of high resistivity as well

as for wells with high temperature and pressure.

2.1.1 FUNCTION OF CASING

Casing can be used for differential function such as:

• To keep the hole open and to provide a support for weak or fractured formations, in order

to avoid the sands or aquifers that can infiltrate during the well operation.

• To isolate porous media with different fluids and pressure regimes from contaminating the

pay zone. Which usually is basically achieved through the combination of cement and

casing itself, which allows the production from the specific zones.

• Cemented casings are also used to prevent contamination of near surface fresh water

zone.

• And as well as to provide a passage for hydrocarbon fluids, which mostly the production

operations fluids are carried out through special tubing which are run inside the casing.

• Last but not least casings are used to provide a suitable connection for the wellhead

equipment (e.g. The Christmas tree) nevertheless casing also serves to connect the

blowout preventer equipment called (BOP) which is used to control the well while drilling.

Found in Literature [6]

3

2.2 CASING STRINGS TYPE

There six basic different type of casing strings for different function and drilling conditions, as

followed bellow:

• Riser pipe

• Conductor Casing

• Surface Casing

• Intermediate Casing

• Production Casing

• Liners

Figure1: Casing types structure

Source: http://www.ebicoilfield.com/drill-string/casing.

4

2.2.1 RISER PIPE (25 IN TO 42 IN. OD)

• For offshore drilling only.

• Driven into the sea bed.

• It is tied back to the conductor or surface casing and usually does not carry any load.

• Prevents washouts of near surface unconsolidated formations.

• Ensures the stability of the ground surface upon which the rig is seated.

• And Serves as flow conduit for the drilling mud to the surface.[20]

2.2.2 CONDUCTOR CASING

Conductor casing is the first and the largest casing run in a hole. Its size ranges from 30 in. down

to 16 in. in diameter. Its primary purpose is to prevent washout under the rig, provide elevation

for the flow nipple to allow mud flow back to the rig tanks. It is seals -off shallow water zones and

shallow gas flow, providing a circulation system for the drilling mud and to ensure the stability of

the ground surface to protect the formation of the platforms if it’s “OFFSHORE”. One or more

BOPs are usually mounted on this casing or a diverter system if the setting depth of the conductor

pipe is shallow. [2] [4] [6]

Conductor casing is usually set at shallow depth, running from between 30 to 200 ft, with 100 ft

being the most common.

• Normal size is 30 " casing in 36 " hole or 20 "casing in 26’’ hole. In Angola a typical size

for a conductor casing pipe is either 26 inch (660.4 mm) to 32 inch (812.8 mm) for a deeper

wells, which also depends on the company standards, because each company has its

own standards for perforation.

• For shallow wells it is usually 21 inch (533.4 mm) to 25 inch (635 mm).

• Conductor casing can be either welded or threaded. Usually, the larger sizes (20 to 30 in.)

are welded, while the smaller sizes (16 to 20 in.) are threaded.

5

2.2.3 SURFACE CASING

Surface casing is set to provide blowout protection, isolate water sands, and prevent lost

circulation. It also often provides adequate shoe strength to drill into high-pressure transition

zones. In deviated wells, the surface casing may cover the build section to prevent key seating of

the formation during deeper drilling. This string is typically cemented to the surface or to the

mudline in offshore wells.

This type of casing, is usually set at in competent rocks such as hard limestone. Which may

ensure that the formation at the casing shoe will not fracture at high hydrostatic pressures. The

surface casing is also used to provide protection against shallow blowout as drilling progress,

while the BOP is connected to the top of this string.[2] [6] [7]

• Its setting depth varies from 300 ft. to 5000 ft.

• Normal is 16 “casing in 20" hole or 13 3/8 " in 17 ½ hole. In Angola a typical size of this

casing is usually from 161/8" (409.575 mm )

2.2.4 INTERMEDIATE CASING

Intermediate casing is set to isolate unstable hole sections, lost-circulation zones, low-pressure

zones, and production zones. It is often set in the transition zone from normal to abnormal

pressure. The casing cement top must isolate any hydrocarbon zones. Some wells require

multiple intermediate strings. Some intermediate strings may also be production strings if a liner

is run beneath them.

• The intermediate casing can be called as protective casing, which is purely a technical casing.

• The normal size for this casing is usually13 3/8” casing in 17 ½” hole or 9 5/8” casing in 12 ¼”

hole which In Angola the most common size of this casing is usually 9.625 inch. It is length varies

usually from 7000 ft. to 15000 ft.

6

2.2.5 PRODUCTION CASING (9-1/2 INCH TO 5 INCH OD.)

Production casing is used to isolate production zones and contain formation pressures in the

event of a tubing leak. It may also be exposed to injection pressures from fracture jobs, down

casing, gas lift, or the injection of inhibitor oil. A good primary cement job is very critical for this

string. [6] [11]

• Production casing is a protective set through the productive zones, as well as is designed

to hold the maximal shut-in pressure of the production formations.

• The 7 inch is the normal size for a production casing, which in Angola is also common

used. After followed by a small diameter of 3.5 inch for a tubing which is plugged inside

the production casing until the surface casing.

2.2.6 LINERS

Liner is a string of casing that does not reach the surface. Liners are hung on the intermediate

casing, by use of suitable arrangement of packer and slips called liner hanger. In liner completion

both the liner and the intermediate casing act as the production string. That is because a liner is

set at the bottom and hung from the intermediate casing, the major design criterion for a liner is

the ability to withstand the maximum collapse pressure.

Liners are used instead of full casing strings to reduce cost, improve hydraulic performance when

drilling deeper, allow the use of larger tubing above the liner top, and not represent a tension

limitation for a rig. Liners can be either an intermediate or a production string. Liners are typically

cemented over their entire length. Some of the big advantages of liners is that:

• The costs of the production string is cheaper or reduced where running and cementing

times are also reduced.

• The length of some diameters are reduced, which at some point allows the completion

with adequate sizes of production tubing. [4] [6] [7]

• And for its disadvantages are:

7

• Leakage of liquids can happen across a liner hanger, and

• Problems in obtaining a good primary cementation can happen, due the narrow annulus

between the liner and the hole.

2.2.7 TIEBACK STRING

Tieback string is a casing string that provides additional pressure integrity from the liner top to the

wellhead. An intermediate tieback is usually used to isolate a casing string that cannot support

possible pressure loads if drilling is continued, which usually happens because of the excessive

side wear. And similarly happens for production tieback that also isolates an intermediate string

from production loads. Tiebacks can be uncemented or partially cemented. [6]

8

3. CEMENTING OPERATIONS

3.1 INTRODUCTION

Zonal isolation is surely the most important of cement sheath. It is so critical that no shortchanging

in the quality of cement or even the cement casing and the formation bonds can ever be justified.

Therefore, the ability of the a well to achieve its potential production is highly influenced by the

degree of zonal isolation achieved during the completion, which may depend strongly on the

cementing operation .Cementing is one of the most critical operation in well completion, starts at

the beginning of the drilling until the production of the well.

Cementing is the process of mixing and placing a cement slurry in the annular space between a

string of casing and the open hole. The cement sets, bonding the casing to the wall of the wellbore

for additional stability. It fills and seals the annulus between the casing string and the drilled hole.

It has four general purpose: zona isolation and segregation, corrosion control, formation stability

and pipe strength improvement. Cement forms an extremely strong and nearly impermeable seal

from a thin slurry, which prevents unnecessary fluids from the formation interring into the well,

which at some point can affect the operation. On the other hand, the cement sheath, if not

controlled or performed appropriately, can cause formation fracturing, when its density get

strongly higher than the formation pressure.

Therefore, in this chapter, I will be focusing on describing the primary operational function of

cement, its types and classification based on API standards and finishing by describing chemical

composition with the usages of additives.

3.2 FUNCTION OF CEMENT

Depending on the type and classification of the cement they all have these basic function, which

are described as:

• It provides zonal isolation = Primary barrier between formations

• Supports axial load of casing strings and strings to be run later

• Provide casing support and protection from corrosion by sulfate-rich formation waters.

9

• Support the borehole or wellbore primary well control in order to prevent collapse of

formations (Hydrostatic pressure > Formation pressure) in the weak and unconsolidated

formations the cement sheath must establish and maintain the stress loading to prevent

the inflow of sand grains with the produced fluids.[6]

3.3 PORTLAND CEMENT

Most cement used in the oil and gas industry are Portland cement. The name Portland was taken

from an English Channel island with a limestone quarry that was used as a source of stone for

development of Portland cement. The Portland cement is usually produced from limestone or

either clay or shale rock by roasting at 2500 to 3000 degree Fahrenheit.

Cement includes: C3A-tricalcium aluminate, MgO-magnesium oxide and CaO-free lime also

known as calcium oxide.

As a definition, Portland cement is a result of heating a mixture of limestone and clay or similar

materials to a temperature of 1500 degree Celsius and grinding it with gypsum to form cement.

Can also be described as hydraulic cement that reacts with water to develop compressive

strength. Not all the cements even those that are made from the same components, will react in

the same manner when mixed with water. Basically the difference are in the fineness of the grind

of each of the cement, which impurities in the water and some minor additives added during the

cement manufacturing process can affect the cement itself. According to the API (American

Petroleum Institute) there nine different classes of cements and three based on the ASTM

(America Society for testing and Materials) standard. [14] [15]

10

3.3.1 API CEMENT CLASSIFICATION

According to the API, they have set basic standards and classifications for oil and gas well

cements.

• Class A: Which are used from the surface to 6000 ft (1830 m) depth, no special proprieties

required, similar to construction cement, with low resistance to sulfates. Similar to class I

cement from ASTM type.

• Class B: Similar to class A, but only differ on the proprieties, Class B are used to moderate

the high sulfate resistance. Similar to class II of ASTM.

• Class C: Used from surface to 6000 ft. (1830 m) as class A and B but in small particle

sizes, low, medium and high sulfate resistance (HSR). Similar to class III from ASTM type.

• Class D: Used from 6000 to 10,000 ft. depth (1830 m to 3050 m), under conditions of high

temperatures and pressure.

• Class F: Used from 10,000 to 16,000 ft. depth (3050 m to 4880 m), under conditions of

extremely high temperature and pressures, also moderate sulfate resistance.

• Class G: For use of basic cement from surface to 8,000 ft. depth (2440 m) to be used with

additives like accelerators and retarders with moderate to high sulfate resistance, usually

with high resistance to sulfate (HSR).

• Class H: As similar as class G in depths usage and its proprieties.

• Class J: It’s used from 12,000 ft. to 16,000 ft. depths (3600 m to 4880m). Under extremely

high temperature and pressures conditions. It can also be use with some additives as

accelerators and retarders to cover a range of well depths and temperature.

• As discussed above, different cement are made for different downhole conditions, but only

two of these cements are the most commonly used classes, which are Cement G and H.

[15]

11

4. TYPES OF CEMENTING

INTRODUCTION

According to the cementing classification and operation, it can be dived into two basic cementing

type operation: Primary cementing, and Remedial cementing. Primary cementing used mostly to

provide a zonal isolation. And remedial cementing is done or use to correct mistakes that was

done during the primary cementing job. And the two principal function of the cementing process

is not only to provide a zonal isolation but to restrict fluid movements between the formations, to

bond and support the casing.

4.1 PRIMARY CEMENTING

Primary cementing is the placement of a cement slurry into the annulus between the casing and

the formation exposed to the wellbore (open hole) or previous casing.

The most important objective of primary cementing is to provide zonal isolation (that is, to prevent

communications between the different zones in a well). In addition, the cement provides support

for the several casing strings run in a well.

Another objective for primary cementing is to protect the casing from plastic formations or

corrosive formation fluids (e.g.: waters containing sodium, calcium, magnesium, or dissolved

CO2). Without cement for support, the plastic formation will deform, or creep, and may collapse

or shear the casing. Also, underground corrosive waters can destroy the integrity of the steel of

the casing in a few years, which results in unwanted fluid migration during production, or, worse,

premature loss of the well.

Finally, primary cementing is done to protect the borehole from collapsing (otherwise known as

caving in), especially across plastic, water-sensitive, or unconsolidated formations.

During primary operation when pumping down the slurry to the casing and up to the annulus,

differential techniques are applied for special situation. In case of stage cementing, are applied

for well with critical fracture gradients. Inner-string and multi-string cementing for large and small

diameter pipe, annuls cementing for surface pipe or large casing. Reverse cementing for critical

formation. [1]

12

The placement of cement slurries into the annulus between casing and open hole or previous

casing in order to provide zonal isolation, provide casing support and protection and as well it

support the borehole as it mention above . And when these parameters are not well settled, it can

lead to a bad zonal isolation and as another consequence, can cause blowout, which is why

setting a good cement job is a primary condition for the whole operation.

4.2 PRIMARY CEMENTING TECHNIQUES

In order to accomplish a primary cementing job successfully, it is important to obtain necessary

data before performing the operation, where such information should include the following details:

Information about the pore pressure and formation fracture gradient and any special well

problem as lost circulation, kicks, and salt sections. Minimum compressive strength and

permeability requirements.

The type of job (surface, long-string, liner), casing sizes, grades, weights, and threads.

Casing depths, and deviation data as well as the hole size and caliper if possible. Bottom

hole static and circulating temperatures, type of mud, its density and rheology.

And the operating company name with well name and location (LSD) where the job is

been performed and specific operating company cementing procedures.

Once the data is obtained it is recommended to run computer simulations for critical cement jobs.

Most cementing companies use primary cementing simulation software, and it is usually all long-

strings and liners. And if the job is in a new area or if there are problems like lost circulation or

gas migration it is required a simulation test run on surface and intermediate casing strings.

After performing these preliminary operations, pumping begins by establishing circulation from

the cementing equipment. First pumping preflushes, washes, and spacers, launching plugs as a

necessary tool between the different fluid Casings is usually rotating in order to improve mud

removal efficiently.

Afterwards entire lead slurry and subsequent slurries are mixed as per design densities and rates,

and the well is checked for returns during the entire cementing process. And if there is a difference

between “full” returns and “partial” returns, it would indicate losses.

13

It is always important to check the slurry density, because if the slurry density is not controlled

within accepted limits, the pump rate gets slower and the job gets longer and thickening time may

need to be made. Therefore when the slurry density cannot be maintained, it is important to stop

mixing at a reduced slurry volume and dispose of the remaining cement. The lead slurry is

pumped first, because it is light and easier to change its composition. The tail slurry is pumped

following the lead, in other to avoid fracturing. [21]

4.2.1 STAGE CEMETING OPERATION

Stage cementing is used to provide appropriate fill and seal in the annulus in those intervals where

a continue single stage, lead and tail or others lightweight cementing application cannot be

performed. If it’s done successfully it may reduce the mud contamination as well the high

possibility of fluid loss, which can be caused by high hydrostatic pressure. Therefore performing

stage cementing other differential valve and tools are used, they are used to cement multiple

section along the casing string in other to avoid or reduce the lost circulation or in order to

segregate several different zones. To maintain an appropriate sequence of the tools and valves

that are used they must be installed at specific points in the casing string.

There are two differential stages cementing but most of them set in the same procedures as been

followed:

4.2.2 SINGLE STAGE CEMENTING

In single stage cementing, cement slurry is placed in the annulus in one stage, where, it uses two

plugs to prevent intermixing of cement with others fluids in the operation. The two plugs that are

used is usually the bottom and top plug, where bottom cement plug is run first, then followed by

the cement slurry and after is placed the top plug.

The slurry and wash, prevents unnecessary contamination due to the density differential effect.

Therefore when top plug reaches the landing collar, it indicates a pressure increase at the surface

and displacement is terminated and the process is completed.

14

The key parameters for single stage is that casing should land at the desired depth, and after

proceed with the pumping of the calculated volume of slurry into the casing., When the casing

has been run into the hole, the first cement stage or bottom cement stage is pumped through the

tool until the end of the casing and up to the annulus. When it is completed, a shutoff or bypass

plug can be pumped in the casing to seal the stage tool. Therefore, a closing plug is used to

close the sliding sleeve over the side ports at the end of the second stage and serves as a check

valve to keep the cement from U-tubing above and back through the tool. [1] [9] [24]

A figure 2 indicates a basic process of a single stage cementing operations, with the all

equipments attached to it and placed in place.

Figure 2: Single stage cementing operation

Source: http:www.rigzone.com/training.

15

4.2.3 TWO STAGE CEMENTING

Multi-stage or two stage cementing is the process of completing two or more isolated cement jobs

on the same casing. Each stage has the same purpose as a single-stage cement job, for example

the placement of a cement slurry in the annulus to ensure zonal isolation. Theoretically, there is

no limitation to the number of stages used to cement a casing. However, for technical reasons

only two, or sometimes three, stages are used on a multi-stage cement job.

The Figure 3 represent a two-stage cement job configuration, where the first stage in a two-

stage cement job which is the same as a single-stage cement job using a float shoe and float

collar. The second and all subsequent stages use a stage collar tool at the lowest point of

cementing. And to perform a multi-stage cement job, specific casing hardware and equipment is

used, such as: Stage collar tool, bypass plug, First-stage plug, Opening bomb, closing plug. [8]

Figure 3 Two stage cementing job

Source: Schlumberger stage cementations

16

Therefore the importance or reason of performing a two stage cementing job, is not only because

it completes the cementing operation but also reduces the hydrostatic pressure on the formation,

as well as cement widely separated intervals, it’s also reasonable on thickening time, reduction

costs and depending on the clients as well they may request some special needs. It is important

to mention that in case of a two or more stage operation, the need of hardware tools equipment

is higher comparing to a normal single stage operation.

Table 1. Hardware tools equipments for stage operations

Single stage tools Two stage tools

Casing Casing

Float shoe,

Float collar

Float equipment’s

Centralizers Centralizer

Top plug

Bottom plug

Plugs

Wiper plug or shut off plug

Seal off plate

Bypass plug

Opening plug or free fall opening device

4.2.4 STAB IN CEMETING

Method commonly used on conductor pipe with larger casing sizes of 13 3/8 in OD. Stab in or

sometimes referred as through-drill pipe or tubing, its applied whenever we want avoid slurry

contamination inside the casing or even in the annulus. This procedure reduces the cementing

time and the volume of cement required to pump the plug. Therefore, there are three important

17

reasons for choosing and using the through-drill pipe, or stab-in method of cementing. It greatly

reduces contamination and channeling of the cement while traveling down within the casing. Thus

displacement volumes and, therefore, job time are reduced. For example: 400 ft of 26-in. casing

would require 223 bbl, while 400 ft of 5-in. drill pipe would require only 7 bbl. And as addition we

can continue mixing and pumping until we have well cement at the surface, ensuring a good

cement job at the end of displacement.

4.3 REMEDIAL CEMENTING

Remedial cementing also referred as squeeze cementing, it’s applied when wellbore condition

are unknown or it is out of control. It is used as a correction process that is only applied in extreme

cases. Remedial cementing covers different techniques of slurry placement, repair and/or

complete a previous cement job, plug and seal casing leaks, seal depleted or non-productive

zones.

Remedial cementing is often called squeeze cementing because of the manner in which the

cement is placed into the wellbore. Before remedial cementing is done, the possible benefits and

harm to a company, the client, and the well must be considered.

Squeeze cementing is the process of forcing a cement slurry under pressure into a set of

perforations, casing leak, and channels behind a casing, in simple terms, is the process of placing

plugging material into a void space, which exists in a well-bore annulus. So, when the slurry is

forced against the permeable formation, the solid particles filter out on the formation face while

the aqueous phase (cement filtrate) enters into the formation matrix. Therefore, a properly

designed squeeze job causes the resulting cement filter cake to fill the openings between the

formation and the casing. The slurry placement may be done either above or below the fracture

pressure of the zone, depending on the type of job.

Thus, before using a squeeze, some decision must be taken in analyses, such as Identify the

problem and design an appropriate treatment starting by obtaining an accurate well diagram.

Review logs when available. Because squeeze cementing it is a dehydration process and cement

slurry is prepare and pumped down a wellbore to the squeeze target or the wellbore area that has

problem .where the area is isolated and pressure is applied from the surface to effectively force

the slurry into all voids area. [10]

18

Figure 4: Remedial slurry into formation

Source: Schlumberger well cementing

Figure 4, shows the placement of a remedial cement slurry into a set of two casing perforations.

The perforations are filled up with cement slurry, and the slurry dehydrates and hardens, resulting

in plugged perforations.

4.4 SQUEZE CEMENT TECHNIQUES

Remedial cementing are mainly divided into two categories:

Squeeze cementing

Plug cementing

As mentioned above, one of the most important reason for a remedial cement job is to repair an

ineffective primary cement job, which on the other hands it has similar availability of a primary

cementing operation, as provide zonal isolation, seal abandoned zones, repair casing leaks, and

cure losses. Thus, to be successful in either operation, the squeeze pressure must remain below

the fracture pressure in order to prevent damage to permeable intervals.

A poor zonal isolation can be the result of insufficient mud removal which can cause several

damages, as mud channeling, micro annulus formation and cement contamination.

The squeeze can be group by three forms: placement, pumping, applications. [16] [17]

19

4.4.1 Placement

Placement techniques refer to how the slurry is placed in the zone of interest, and this can be

done at either low or high pressure.

At Low-pressure squeeze fill the voids, channels, or perforation cavities with dehydrated

cement. Where the volume of the cement is generally small, because no slurry is actually pumped

into the formation. And an accurate control of the bottom hole pressure (hydrostatic pressure),

plus applied surface pressure is essential. Low-pressure squeeze has a higher success rate than

the high-pressure squeeze therefore is the preferred method.

High-pressure squeeze, it’s one of the technique that is used when low-pressure squeeze does

not accomplish the job objectives, which is mainly used in cases of isolated channels behind the

casing that is not directly connected to the perforations, small cracks or micro annulus that may

allow the flow of gas but do not allow the passage of a cement slurry. In high-pressure squeezing,

slurry volumes are usually relatively high because the created fractures have to be filled with

cement slurry.

4.4.2 Pumping

Pumping techniques refer to how squeeze pressure is attained, and tis can be done: Continuously

called a running squeeze, and intermittently called a hesitation squeeze.

Running squeeze is any squeeze operation in which continuous pumping is used to force the

cement into the squeeze interval. Where sometimes referred to as a "walking squeeze" when low

pump rates and minimal graduating pressure is used. Although the running squeeze is easier to

design and apply, it is probably the most difficult to control because the rate of pressure increase

and final squeeze pressure are difficult to determine.

Hesitation squeeze is one of the technique that is often used when a squeeze pressure cannot

be obtained using a running technique because of the size of the void, lack of filtrate control, or

when the squeeze must be performed below a critical wellbore pressure. It involves a much

smaller slurry volume than a running squeeze, not only but also depends on the type of formation.

20

4.4.3 Application

Application techniques refer to how the squeeze pressure is applied and it can be achieved by

using either the blowout preventers (BOP) or downhole packers, and two techniques are used:

Packer/Retainer Squeeze, when squeeze tools are often used to isolate the squeeze interval

and place the cement as close to the squeeze target as possible before applying pressure.

Packer can be run into the wellbore and set above the squeeze interval, it allow circulation of the

wellbore until the cement slurry is pumped. Cement volumes, squeeze pressures, and squeeze

targets can be more accurately determined and controlled using squeeze tools.

The Braden head squeeze technique, this is one of the techniques, that is applied when the

problem occurs during drilling (lost circulation) or when there are open perforations below the

zone, and it is necessary to protect these perforations. In similar words is normally used during

low-pressure squeezes when there are no doubts concerning the capability of the wellhead and

casing to withstand the squeeze pressure. This is not recommended for old casing, especially

when it is corroded or damaged, because it may crack or break under pressure.

4.5 PLUG CEMENTING

In oil-gas-well construction, a plug must prevent fluid flow in a wellbore, either between formations

or between a formation and the surface. As such, a competent plug must provide a hydraulic and

mechanical seal. Each plugging operation presents a common problem in that a relatively small

volume of plugging material, usually a cement slurry, is placed in a large volume of wellbore fluid.

And wellbore fluids can contaminate the cement, and even after a reasonable (waiting on cement)

WOC time, the result is a weak, diluted, no uniform or unset plug. Somehow, Cement plugs can

be used for a variety of purposes, including: Sidetrack above a fish or initiate directional drilling,

Plug back a well, solve a lost circulation problem during the drilling phase, protect a low-pressure

zone during a workover treatment and provide an anchor for open hole tests.

Cement plugs are remedial cementing treatments. The first logical step when it come to this

operation is to determine the actual problem to solve, what is the purpose of setting a cement

plug and then run to the second step that is to understand the criteria of evaluation as positive

pressure test, negative test, and so on . Both of these steps allow for the proper selection of slurry

21

specification and job placement technique. Thus, performing a plug operation may lead to

different causes in the well, such as: lost circulation, abandonment, zonal isolation and well control

whenever it is necessary.[22]

22

5. CEMENT ADDITIVES

5.1 INTRODUCTION

According to American Petroleum Institute Recommended Practice 10B, additives are materials

added to cement slurry to modify or enhance desired property. Cement additives selected for

cementing operations are an integral part of sound well design, construction as well as well

integrity. Additives are available to enhance the properties of oil well slurries and achieve

successful placement between the casing and the geological formation, rapid compressive

strength development and adequate zonal isolation during the lifetime of the well. According to

Cowan and Eoff, additives are commonly added to cement formulations to; disperse cement

particles, modify the setting time under temperature and pressure conditions in the well, control

filtration losses of the liquid from the cement slurry during and after placement, compensate for

shrinkage of the cement as it sets and hardens, improve interfacial bonding between cement and

casing, and control influx and migration of formation fluids into the cement column during setting.

There are different types of cement additives that have been developed to allow the use of

Portland cement in many different oil and gas well applications. Each major type has different

types of additives that have been developed to perform almost the same function during cement

slurry design. However, there are some additives under each major type that are commonly used

in cement slurry design for oil and gas well cementing operations, and those are the one which I

am going to describe here.

5.2 TYPES OF ADDITIVES

5.2.1 ACCELERATORS

Accelerator is a chemical additive used to speed up the normal rate of reaction between cement

and water which shortens the thickening time of the cement, increase the early strength of cement,

and saves expensive rig time. Cement slurries used in shallow wells where temperatures are low

requires accelerators to shorten the time for “Waiting on Cement (WOC)” before drilling operation

can be resumed.

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5.2.2 RETARDER

Retarders are chemical additives used to decrease the speed of cement hydration. Retarders

inhibit hydration and delay setting, allowing sufficient time for slurry placement in deep and hot

well.

The most common retarders are natural lignosulfonates, cellulose and sugars derivatives. The

chemical nature of the retarder to be used is dependent on the cement phase. Lignosulfonate and

hydroxycarboxylic acids are retarders that are believed to perform well for oil well cements with

low C3A contents. Some admixtures act as retarders when used in small amounts but behave as

accelerators when used in large amounts.

5.2.3 EXTENDERS

Many formations will not support long cement columns of high density slurries, these slurries

weights need to be reduced to protect formations that have low fracture gradient or for economics

purposes. To reduce the weight of cement slurries, extenders are used.

Extenders also reduce the amount of cement needed for cementing operation and because they

are less expensive than cement, they bring considerable savings.

The more water that can be added to the slurry, the greater its volume or yield and the lower the

slurry’s density. Normally a sack of cement (94 lb) will give about 1 ft3 of slurry. Adding extra

water can increase the volume to 3.0 ft3/sk.

5.2.4 WEIGHTING AGENTS

The main purpose of heavy weight additives is to restrain high formation pressures. The main

requirements for weighting agents are that, they have specific gravity greater than the cement,

consistent particle size distribution and low water requirement. To Lake and Mitchell, heavy weight

agents are normally required at densities greater than 17 lb/gal where dispersants or silica is no

longer effective. The most common weighting agents are Hematite (Fe2O3), Ilmenite (FeO TiO2)

and Barite (BaSO4).

24

5.2.5 DISPERSANT

Dispersants also known as friction reducing additives that are added to improve upon the flow

properties of cement slurry. In particular, they are used to offset overly-high viscosity and some

slurries tendency to gel. Dispersants assist in providing fluid loss control for high density slurries.

Polynapthalene Sulfonates (PNS) are the most widely used materials for dispersing cement

particles in slurries. It is available as a calcium or sodium salt, and can be obtained in both solid

and liquid form whenever it is necessary.

5.2.6 FLUID LOSS CONTROL AGENTS

Fluid loss agents, also known as permeability plugging additive. Fluid loss additives are commonly

employed in field cementing operations to reduce the rate at which water from cement is forced

into permeable formations when a positive differential pressure exits into the permeable

formation. Fluid loss additives are normally polymers such as:

• Cellulose, polyvinyl alcohol,

• Polyalcanolamines,

• Polymers of polyacrylamides, and

• Liquid latex such as styrene butadiene latex. These materials are classified as water-

insoluble and water-soluble FLAs.

5.2.7 LOST CIRCULATION CONTROL AGENTS

Lost circulation additive, also known as macro plugging materials. These agents are used to plug

zones that have a tendency to draw in fluid because they are unconsolidated or weak. Large

particulates can be placed in the cement slurry to prevent fracturing or to bridge existing fractures.

Some of the major consequences of lost circulation include increased cost resulting from:

• Poor or no removal of cuttings, requiring additional wiper trips

25

• Stuck drill pipe

• Excessive mud lost

• Remedial work to cure losses

• Rig time required to cure losses.

• Reservoir damage and loss of well are also possible as a result of

• Lack of zonal isolation caused by poor cement coverage

• Formation damage resulting from mud losses and

• Blowout after a drop in hydrostatic pressure.

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6. CEMENTING EQUIPMENTS

6.1 FIRST STAGE CEMENTING EQUIPMENTS

6.2 CASING HARDWARE

Casing hardware are downhole equipment which are a combination of all equipment that are

attached to the string, which at the same time are run together with the casing string by the

centralizers and tubing that are used to obtain a satisfactory zonal isolation. The floats tubes,

collar and float valves are used for preventing the back flow after the cement slurry has been

pumped into place. And they can stated in different parts such as: Guide or float shoe, float collar,

centralizer, shoe track, top and bottom plugs. In some cases we can find more specialized

hardware that may include stage cementing collars and differential fill up equipment’s that helps

achieving a successful placement and cementation of the casing string. [17] [19].

Figure 5: Casing hardware tools.

Source: Schlumberger glossary oil field.

6.3 FLOAT EQUIPMENTS CONSIDERATIONS

There are some primary and essential consideration that must be taken into account for floats

equipment during the cementing operations.

27

Prevent a heavier cement in the annulus to “U Tube”, which happens when the pumped cement

slurry is backing into the casing, due to great density of the cement.

Float equipment should always act as one way valve during the operation to avoid formation

fracture, as well as they must support or withstand the heat and pressure during the cementing

curing process.

They also should be able to support the back pressure which is the “upward force “that comes

from the superficies, the “Downhole force” mention as Bump pressure from the formation and the

tensile force. And some other small factor as temperature stability, chemical resistivity “H2S”.

6.4 GUIDE OR FLOAT SHOE

As the name says, a Float shoe or Guide shoe, is used to guide the casing or liner into the

wellbore. Guide shoe is a rounded material that is attached to the downhole end of a casing string,

where an integral check valve in the float shoe prevents the flow of fluids into the casing during

the running process or even the reverse flow of cement slurry from the annulus to the casing.

The outer part of the float is usually made of steel which my generally matches the casing size

and the threads. And the inside of it is generally made of cement or thermoplastic.

Figures 6: cement Nose Guide shoe

Source: oil Field equipment.

Float and stage equipment

28

6.5 FLOAT OR LANDING COLLAR

The float collar provides two important functions during a cementing operation, the first one is

when the cementing plug is landed on the float collar and positive indication is obtained at surface

that the cement slurry has been properly displaced. And the second one is when the

pump pressure is drain or open and a check-valve assembly in the float collar closes to prevent

the backflow of cement into the casing string.

The float collar is usually installed near the bottom of the casing string in which cement plug land

during the primary cementing operation. Typically consist of a short length of casing fitted with a

check valve .This check valve which is fixed within the collar, it prevents flow back of the cement

slurry, when the pumping process is stopped .And without the collars ,the cement slutty placed in

annulus can “U Tube” or reverse.

Figure 7: cement float collar

Source: oil Field equipment,

Float and stage equipment

6.6 CENTRALIZERS

During the cementing operation different equipment are used to sustain and maintain the

wellbore, therefore imaging a casing without a centralizer could be hard work and stressful

operation because holes are rarely straight and casings can curve in deep well places or even

folded to the wall of the wellbore .[12]

29

Centralizers are used mainly in cement operation to ensure that they can obtain an adequate

placement of cement slurry around the casing string, not only, centralizers prevent drag while pipe

is running into the hole, minimizing differential sticking. Centralizer is one of the effective tool of

primary cementing, which are designed by the API 10D.

There different type of centralizers, blow spring, rigid, steel spiral solid and an integral centralizer.

Figure 8. Blow spring centralizer Figure 8.1: Rigid centralizer

Source: Schlumberger cementing equipmnets Source: Cementing Equipment.

6.7 CEMENT WIPER PLUGS

The cementing plug is a key component for the successful placement of

uncontaminated cement slurry. Two types of cementing plugs are typically used during a

cementing operation. The bottom and the top plug.

6.7.1 BOTTOM PLUG

Bottom plugs is the first plug to be pumped down inside the casing, where its wipe the mud as it

moves down to the pipe, until it reaches the float collar, and differential pressure that leads to

diaphragm ruptures on the top of the plug, which allows the cement slurry to flow through the plug

and floating equipment’s and then up to the annular space, which is the difference between the

casing and the hole. [13]

30

Figure 9: Conventional Bottom Cementing Plug Sizes ranging from 4-1/2" to 20"

Source: Schlumberger.

The Bottom Cementing Plug is designed to exert continuous pressure on the casing wall. The

core is usually made of special materials such as Plastic, Aluminum or Phenolic depending on

the application and well conditions.

6.7.2 TOP PLUG

The top plug is usually pumped behind the cement slurry to shutoff on the float collar, meaning

that whenever the top plug is released, the displacement fluids begin to flow. Pressure increases

at the surface when the top plug reaches the bottom plug leading to a received signal that cement

has been displaced.

The fins and tail section of top cementing plug, provide positive wiping action, which also serve

as a seal while cementing.

Figures 9.1: on Rotating Top Cementing Plug

Size ranging from 4-1/2in to 20 in

31

6.8 TWO STAGE CEMENTING EQUPMENTS

As mentioned before in stage cementing operation, for each of operation, differential or added

equipment’s are used, as in two stage cement operation the need of using different equipment

are required. In a two-stage cement job, bypass and wiper plugs are used in place of conventional

bottom and top plugs for the first stage. The seal-off plate is necessary to provide a tight seal for

the wiper plug.

6.8.1 RUNNING POSITION

In the running position, the ports in the stage collar tool are closed by the lower sleeve and fluid

cannot exit the stage collar. In this configuration the casing string is exactly the same as a single-

stage casing string, and the first-stage cement job can be performed as on the single job, two

plugs can be used:

The bypass plug – used as the first-stage bottom plug (a bypass plug is not always utilized)

The wiper plug – used as the first-stage top plug to isolate the cement slurry from the

displacement fluid.

OD and shape (flexible wings) of both plugs are designed to allow them to go through the stage

collar tool without operating any of the two sleeves. The wiper plug eventually lands on the seal-

off plate. When pressure increases the first-stage displacement ends. [17]

6.8.2 OPENING PLUG

After the pressure is released at the end of the first-stage cement job, the opening plug is

launched. Time must be allowed for the opening plug to reach the stage collar tool. Normally, 5

min/1,000 ft for vertical wells is sufficient time. However, extra time must be allowed for deviated

wells. When the opening plug reaches the stage collar tool, it catches the smaller ID of the lower

sleeve. The pressure required to shear the pins on the lower sleeve and open the stage collar

tool is between 1,000 and 1,500 psi.

The second-stage cement job is performed once the stage collar tool is open and circulation is

started to assure that the upper section of the annulus is free. [22]

32

Figure 9.2: Opening plug

Source: Schlumberger

6.8.3 CLOSING PLUG

The two functions of the closing plug are

• Isolation of the cement slurry from the displacement fluid to prevent contamination

• Operation of the upper sleeve to close the stage collar tool.

And, at the end of the displacement, the closing plug catches on the inside diameter of the upper

sleeve. The surface pressure increases, of at least 1,500 psi at the surface, which is required to

shear the pins on the upper sleeve and to close the stage collar tool. [22]

Figure 9.3: Closing Plug

Source: Schlumberger

33

7. CEMENT LABORATORY TESTING OPERATION

7.1 OBJECTIVES OF THE TESTS

• Describe the basics laboratory testing equipment’s used for cement testing,

• Describe the cement integrity,

• Describe the cement water permeability,

• Describe the cement porosity, and

• Identify the effects of temperature on cement slurry.

Before starting the cement testing, I first prepared all the cement material that was needed for

this testing. Such as the slurry mixer, the weighted dry cement with a weighted water volume,

specimen molding, aging, porosity and water permeability test.

Figure 10: Mixer blender

34

7.2 JET MIXING BLENDER

7.2.1 Preparation of slurry

For the preparation of cement slurry, I weighted 792 g of API G class dry cement in PLT 2000-

3CM balance, and after measured 349 ml of water in a volumetric clear plastic beaker. Following,

the 349 ml of water was added in 4-litre mixer blender, as shown in 12.Figure. After, turned the

blender at 4000 rpm to allow the cement powder to be added , after added all the cement ,closed

the mixer with its lid and let it blend for about 30 seconds at 12000 rpm ,until the slurry particles

get smother.

The mixing speed are usually adjustable from 1000 to 28000 rpm. While for mixing the cement

slurry 4000 and 12000 rpm were selected according to API 10B-2.

Mixing ratios based on API 10A

Mix up bulk cement powder as much as possible to reduce effects of settling.

Fill blenders with specified weight of distilled water.

Measure temperature of water, which was about 25 degree Celsius.

Weight cement powder in a clean container.

Turn on blender at 4000 rpm.

Add dry cement in a uniform rate but in no more than 35 Seconds (API 10B-2 2013)

with the blender at 4000 rpm.

When all the materials have been added => cover with its lid => mix at 12000 rpm

(~200 r/s) for 45 s

7.3 LABORATORY MIXING QUANTITIES CALCULATION

Before the mixing of cement slurry, some calculations were done, in order to determine the exact

amount of cement and water to be use as the determination of slurry density. Thus was necessary

gathering information related with gas and water permeability as followed from table 2.

35

Table 2.

Table 3.

Mix amount in (mL) 1737.500

Estimated Slurry density (g/ml) G

1.87

Estimates Slurry weight(g) 3249.125

Liquid – gas Permeability

Number of specimen(aged) 5

Number of specimen(room temp) 3

Total Number 8

Diameter(in) 1.5

Diameter(cm) 3.81

Length(in) 3

Length(cm) 7.62

Volume(mL) 86.8750

Volume of slurry(mL) 695.0000

Total Volume per cement class(mL) 1390.0000

Excess 25%

36

Standard mixing amounts

Table 4.

Blend Water(ml) Cement(g) M.slurry (g) Volume %BWOC

Class G and Thermal

G

349 792 1141 610 44

Amount of Materials needed for mix volume

Table 5.

Blend

Water(ml) Cement (g) Mass(g) Density(g/ml) Volume(ml) %BWOC

Class G and

Thermal G

993.82 2255.31 3249.12 1.87 1737.50 44

Avg. Density of powder cement 3.14SG 3.14g/ml

Table 6.

Vc(class G)=mc/pc 252 Ml

Vs(class G)=vc+vw 601 Ml

Ps(class G)=ms/vs 1.90 g/ml

7.4 CEMENT SAMPLE MOULDS

For creating the required specimen shape and size, I did use two plastic home moulds, to help

me adjusting the cement shape that is shown in Figure 11. The moulds are made of plastic and

each set was suitable for creating 8 to 9 cube cylinders. Each moulds require greasing for proper

sealing. The grease use was “fuchs renolit replex2”. Proper care was taken during greasing as

cement samples should not be contaminated by this materials, therefore was only placed in the

mating surfaces of the moulds.

Fill the moulds:

37

Ensure the moulds are clean and dry.

Pour the slurry into the moulds ( within 5 min after mixing) to one-half of the mould depth

Puddle with puddling rod 30 times.

Fill the mold to the top (until it overflows slightly).

Puddle the cement another 30 times.

Strike off the excess slurry.

Place the cover plate on top and secure.

The shape of the cement slurry using plastic moulds has two different shape as follow

below:

Figure 11: Cement slurry dried under water after two weeks experiment.

After the cement mixing operations, I place the cement slurry into two different plastic moulds of

about 150 mm , was cover by each plastic mould cover and after placed into a bigger steel pot

with water and followed placed into an oven with a temperature of about 250 ºF equivalent to

some Angola wells temperature. Afterwards the cement slurry was left under water in an oven for

about two weeks, equivalent to 15 days. After then, the sample were taken and drilled in small

cores and placed into a plastic and steel pot under water and put back to the over at the same

temperature of 250 ºF for a period of testing of about three weeks . This was done in order to

obtain the integrity of cement as well as determining the effect of temperature. Two different tests

were done, such as the water permeability and porosity of cement.

38

Figure 11.1: Core cements samples placed in Figure 11.2: cement samples drilled in small cores.

Plastic material before placed into the oven.

After placing the samples into the oven under water and during three weeks as mention above,

tests of water permeability were done as well as porosity, and during the period of three weeks it

could be seen the difference in each samples, according to their test results as well some

calculation made. Within one week of experiment under water and temperature, the samples were

still a bit dense and the resistivity was high as well. Thus for the porosity two samples were taken,

a left to dry separately to the others for twenty hours, and after weighted in order to calculate its

cylindrical volume .

Leave the cement sample for one day to dry

Measure the diameter and length of each samples being used

Find the average of each results obtained and calculate the cylindrical volume.

Measure the porosity.

V=d2*ᴫ*l/4

39

7.5 SAMPLE POROSITY CALCULATION

Table 7.

Sample ID Diameter in cm Length in cm Volume in cm3

YB-02-SP 3.766 4.576 50.972

YB-02-D 3.766 4.636 51.641

For sample YB-02-SP was measured its length and diameter using a scientific caliper where:

Length Diameter

First parte – 4.679 cm First part – 3.771 cm

Middle part – 4.642 cm Middle parte - 3.763 cm

End part – 4.587 cm End part – 3.764 cm

Average 4.636 cm Average 3.766 cm

Sample two: YB-02D

Length Diameter

First parte – 4.575 cm First part – 3.771 cm

Middle part – 4.603 cm Middle parte - 3.781 cm

End part – 4.551 cm End part – 3.747 cm

Average 4.576 cm Average 3.766 cm

40

Sum up and divided by three for each sample. And same procedures were done for similar

samples after second week of experiments, until getting the cylindrical volume.

Sample cylindrical shape used for volume calculation

7.6 CEMENT SAMPLE AFTER THREE WEEKS UNDER-WATER EXPERIMENT

During the experiment of leaving the cement slurry under water inside an oven of temperature of

250 deg F. It could be noted that after achieving the three weeks under-water experiment result

the cement slurry started to crack/ fracture, that because the high temperature effect on the

cement and also the effects of water pressure on cracked propagation. In another words, there

was an effect of fracturing, at which the combination of a rapid sediment compaction and thermal

fluid expansion causing the pore fluid pressure to exceed the pressure of the normal stress. Thus,

under those effects, the slurry or cement sample porosity can be highly affected by increasing its

porosity.

Figure 11.2: Cement sample after three weeks exp.

41

7.7 TEMPERATURE EFFECT ON CEMENT SHEATH

The porosity and pore size distribution of a hardened OWC slurry depends on a number of factors

such as the w/c ratio, degree of hydration, type of cement, mixing conditions, chemical admixtures

and mineral additives. High temperature has a drastic effect on the pore structure and

compressive strength of cement based materials. The total porosity is more than doubled when

the curing or casting temperature increases from 20°C to 1000°C .Based on experimental results,

argued that exposure to a temperature from 50°C to 120°C can be as detrimental to the residual

strength of a cement paste with a low water cement ratio as exposure to a temperature of 400-

500°C. [15]

7.8 POROSITY AND WATER PERMEABILITY TEST

Permeability is a property of porous media, and it is a measure of its ability to transmit fluids.

Therefore the reciprocal of this value represents the resistivity that the porous medium offers to

fluid flow. According to some studies and investigation, it was found that the water permeability

less than 0.1mD, is recommended to provide an adequate zonal isolation.(Nelson and Guillot

2006,Nelson and Eilers,1985).Thus the permeability of a cement sheath influences zonal isolation

as well as the well safety, which normally cement have a very low permeability. For example

0.1mD or even lower in case of water, therefore for a gas permeability is most of the time greater

than water permeability (Smith 1987). Under these conditions Zonal isolation maybe achieved,

and leakage rates are negligible.

For a permeability test measurement ,is always necessary to measured either the gas and liquid

permeability, but according to the small time that I had to measure the samples, I decided to do

liquid permeability only regarding the thermal aging test that was been performed in the cement

samples.

42

7.8.1 LIQUID PERMEABILITY

The liquid permeability of the set cement can be found from measured flow rate and differential

pressure through a sample and mostly calculated using Darcy’s law which is valid for steady-state

one-phase flow through a porous medium with an incompressible liquid and can be defined as:

Kw=14700*µw*Q*L/A∆p

Where:

Kw is permeability to water (mD)

A is cross-section of porous medium (cm2)

Qw is volumetric flow rate of water (mL/s)

L is the length in the direction of flow (cm)

∆p is the pressure difference along the porous media (pi-pₒ) (psi)

µw is the viscosity of the water (cP)

7.9 FIRST WEEK POROSITY TEST RESULTS

Table 8.

The results of porosity in one week under water experiment, did not affect the porosity in high

range, so the experiments continues for at least three weeks under water experiment and then

we check the differences between one to another.

YB-02-SP 3,78266 4,5883 11,23788 51,56278 90,58 102,93 23,95139

YB-02-D 3,7803 4,52133 11,22386 50,7468 89,9 101,78 23,41035

Samples d, cm l, cm A, cm2 Vt, cm3 Gsz, g Gw, g Φw, %

43

7.9.1 FIRST WEEK PERMEABILITY TEST RESULTS

Permeability measurement test were conduct according to API 10B-2.

Sample O2-D-YB, could not be measured in flow rate driven water permeability measurements.

A pulse decay water permeability measurement would have been necessary indicating that the

permeability is in the micro Darcy range.

Sample O2-D-YB After these, the permeability measured by Nitrogen gas was attempted with

no results at 7 bar p1 pressure. This indicates that the permeability of the samples considering

water is at the range below 0, 01 mD. Indicating an incompressible permeability of micro Darcy

range. Values about 10 Nano Darcy (0, 01 microD=0,00001mD) are present.

7.9.2SECOND WEEK POROSITY TEST RESULTS

Table 9.

Samples d, cm l, cm A, cm2 Vt, cm3 Gsz, g Gw, g Φw, %

YB_2_1 3.76 4.77 11.10365 52.96439 90.42 1051.1 27.71674

YB_2_2 3.773 4.772 11.18056 53.35362 89.78 104.2 27.02722

The Porosity test results has increased for about four points difference comparing to the first

sample experiments, meaning that under water high temperature may have an effect on the

porosity.

7.9.3 SECOND WEEK PERMEABILITY TEST RESULTS

Sample YB_2_1, the samples could not be measured in flow rate driven water permeability

measurements.

Sample YB_2_2, the permeability measured by Nitrogen gas was attempted with no results at 7

bar p1 pressure. Which indicates that the permeability of the samples considering water is at the

44

range below 0, 01 mD. Indicating an incompressible permeability of micro Darcy range. Values

are almost as identical to the previous samples about 10-100 nanoDarcy (0,01

microD=0,00001mD) are present.

7.9.4THIRD WEEK POROSITY TEST RESULTS

Table 10.

Samples d, cm l, cm A, cm2 Vt, cm3 Gsz, g Gw, g Φw, %

YB_3_1 3.782 4.776 11.23396 53.6534 89.06 104.8 29.33644

YB_3_2 3.785 4.772 11.25179 53.69355 88.19 106.08 33.31872

Final porosity results has shown an increase in comparison to the first two results obtained

therefore, the porosity of the samples that were used, changes in relation to time and temperature

effect.

7.9.5 THIRD WEEK PERMEABILITY TEST RESULTS

Sample YB_3_1 and YB_3_2. have been measured by the capillary tube flow volume based

measurement. Where with this method takes more than 12hours. Where for the final results, the

permeability results of the third party of sample, has shown an increase to comparing to the first

two mesurements. Meaning that the value obtained was below 0,01 mD indicating an

incompressible permeability of mostly micro Darcy range. Values are about 10-100 micro Darcy

in range.

Permeability test of samples after three weeks aging, results were quite similar with the first week

mesurements, which was below 0.01 mD, therefore according to range obtained, can be said that

G cement under high temperature effect , his permeability ranges does not affect his siling

proprieties, which somehow can be taken in consideration the usage of it whenever required.

45

7.10 BASISC API RB 10B LABORATORY TESTS

Cement specifications are most always stated in terms of API standard tests. The test equipment

needed to perform these tests includes:

• A mud balance for determining the slurry density,

• A filter press for determining the filtration rate of the slurry,

• A rotational viscometer for determining the rheological properties of the slurry,

• A consistometer for determining the thickening rate characteristics of the slurry,

• Specimen molds and strength testing machines for determining the tensile and

compressive strength of the cement.

7.10.1 MUD BALANCE

According to API RP 1OB and ISO 10426-2, the determination of slurry density can be measured

by using two differential mud balance, as; pressurized and non-pressurized mud balance.

Non-pressurized mud balance, it is a device designed for measuring density (weight), of most of

liquids, such for mud, cement slurry or other liquids.

For Pressurized fluid density or mud balance is used when pressure is applied during

measurement, to compress any trapped air or to eliminate the effect of gas bubbles in the liquid

as similar to a downhole condition. [7]

Figure 12: Pressurized mud balance

Source: oil filed equipment’s

46

7.10.2 RHEOMETER - RHEOLOGY

There are two main groups used for classification of rheology:

• Newtonian fluids groups and

• Non Newtonian fluids groups

Newtonian fluids are those where the viscosity of the fluid does not depend on the flow condition

as shear rate or strain rate and time, but depends on the effect of temperature and pressure,

where small group of this fluids exhibit a constant viscosity. In case of water or gasoline.

Non-Newtonian fluids are those where the viscosity depends on the applied shear rate and the

time during which the shear rate is applied. It means that the tested sample does not have a

constant viscosity. Thus, the viscosity of a non-Newtonian fluid is measured at a specified shear

rate and is called apparent viscosity. [7] [17]

Τ

Shear stress-shear rate Newtonian fluids Shear stress-shear rate

Bingham plastic fluid

47

Where τ shear stress, is proportional to γ shear rate, and the slope of the line is µ viscosity.

For the Newtonian fluids. Therefore, the rheological properties for an oil well cement (OWC)

slurry determines the quality of the final product and helps predicting its end use performance and

physical properties during and after processing.

Figure 13: Torque Rheometer

Rheological measurements can determine the flow properties of the cement slurry such as its

plastic viscosity, yield point, frictional properties, and gel strength. The slurry is sheared at a

constant rate between an inner bob and an outer rotating sleeve in a rotational viscometer at six

standard speeds. Using the measured data, the type of fluid and the rheological model of the fluid

can be determine.

7.10.3 FLUID LOSS - STATIC FLUID LOSS

Similar to other tests done in cement lab testing, fluid lost tests are designed to measure the slurry

dehydration during placement phase, simulating the amount of filtrate lost under pressure against

a permeable formation. The measurement of this characteristic is conducted by static filter press.

A filter press cell with API assembly, pressurized with a Nitrogen gas. The time required for the

duration of the fluid loss test is usually 30 minute.

48

According to API standard, the filter press has an area of mostly 45 cm2 and is operated at a

pressure of 100 psig (6.8 atm) where the filtrate volume collected in a 30-min time period is

reported as the standard water loss

. Figure 14: Static fluid loss set-up diagram

Source: Schlumberger

7.10.4 PRESSURIZED CONSISTOMETER - THICKENING TIME

It is a device used to determine the thickening time of cement slurries under simulated downhole

pressure and temperature conditions. The thickening time is a measurement of the time during

which cement slurry remain in a fluid state and is capable of being pumped. Thickening time is

49

assessed under simulated downhole conditions using a consistometer that plots the

consistency of a slurry over time at the anticipated temperature and pressure conditions. The end

of the thickening time is considered to be 50 or 70 BSc for most applications. [7]

The thickening time of a slurry under realistic conditions must be established to ensure adequate

pumping time for slurry placement.

Excessive thickening time must be avoided to prevent:

• Delays in resuming drilling operations

• Settling and separation of slurry components

• Formation of free-water pockets

• Loss of hydrostatic head and gas cutting

50

8. CEMENTING LABORATORY TEST REPORT

8.1 TAIL SLURRY REPORT

Based on my laboratory experiments, I summarized my results in a cement test report that is

based on an original cement report usually made by field engineers. However since the

department laboratory does not have a consistometer and the time was short, fluid loss and

thickening time could not be measured.

Laboratory Cement Test Report Tail 1.87 SG @ 22 degC

Signatures

Fluid No : Petroleum Inst. Client : Location / Rig : Lab Done by:

Yolanda Bau

Date : Nov-24-2017 Well Name : Field : Miskolc Reviewed by:

G. Federer

Job Type Casing Depth m TVD M

BHST 22 degC BHCT 22 degC BHP Psi

Composition

Slurry Density 1.87 SG Yield 0.79 m3/tonne Mix Fluid 470.35 mL/kg

Solid Vol. Fraction 44 % Porosity 23-24 % Slurry type Conventional

Code Concentration Sack Reference Component Blend

Density

G 6 kg of CEMENT Blend 3.20 SG

Water 470.35 mL/kg Base Fluid : Water

There were no additives in my cement mixture.

The following rheological parameters were measured by my former company on a 1.9 SG tail

cement. I am using the presented data with the permission of my former colleagues. Since the

slurry I used in my experiment is very similar the following tables give a good estimate on the

thickening time and compressive strength as well as fluid loss.

51

Rheology

Temperature 22 degC

(rpm) Up

(deg)

Down

(deg)

Average

(deg)

300 52.0 52.0 52.0

200 40.0 38.0 39.0

100 26.0 23.0 24.5

60 20.0 17.0 18.5

30 15.0 12.0 13.5

6 11.0 8.0 9.5

3 9.0 7.0 8.0

10 sec Gel 11 deg – 11.74 lbf/100ft2

10 min Gel 44 deg - 46.96 lbf/100ft2

Rheo. Calculation Viscosity : 43 Cp Yield Point : 9.64 lbf/100ft2

Thickening Time

Consistency Time

POD : 05:08 hr:mn

40 Bc 05:35 hr:mn

50 Bc 06:33 hr:mn

70 Bc 06:36 hr:mn

100 Bc 06:38 hr:mn

UCA Compressive Strength

Time CS

07:46 hr:mn 50 psi

12:00 hr:mn 412 psi

12:49 hr:mn 500 psi

24:00 hr:mn 1670 psi

Free Fluid

0.0 mL/250mL in 2 hrs

At 27 degC and 45 deg incl

Sedimentation : None

Fluid Loss

API Fluid Loss 66 Ml

In 30 min at 27 degC and 1000 psi

52

The following two charts represent the thickening time and UCA measurements for the mentioned

1.9 SG tail cement slurry. All these experiments were done according the well condition, which

most common in Angola Wells.

It can be seen based on the charts that a typical API G class tail slurry reaches its maximum

strength under 24 hours and needs about 7 hours thickening time.

Figure 15: Thickening time chart for tail slurry

Source: Schlumberger

53

Figure 16: UCA chart for tail slurry

Source: Schlumberger

8.2 LEAD SLURRY LAB REPORT

The following report is a real lead cement laboratory report that has been performed by me and

approved by my colleague. The report is published in this thesis with her special permission.

Laboratory Cement Test Report - 20 CSG CRL- P14 Lead LiteFIL 1.30SG Signatures

Fluid No : LPU 16-11-07016 Client : TEPA Location / Rig : DS-8 Done by: Yolanda Bau

Date : Nov-30-2016 Well Name : CRL-P14 Field : B32 KAOMBO Reviewed by: Maria Lucas

Approved by:

Job Type 20" Casing Lead Depth 2229.0 m TVD 2226.6 m

BHST 27 degC BHCT 16 degC BHP 3218 psi

Starting Temp. 27 degC Time to Temp. See comments Heating Rate SLB Simulator

Starting Pressure 155 psi Time to Pressure See comments Schedule SLB Simulator

Composition Slurry Density 1.30 SG Yield 1290.41 L/tonne Mix Fluid 653.47 L/tonne

Solid Vol. Fraction 49.4 % Porosity 50.6 % Slurry type Extended

54

Code Concentration Sack Reference Component Blend Density Lot Number

Conventional 45 kg of BLEND Blend 1.57 SG Bulk Plant – 19-11

Sea water 602.37 L/tonne Base Fluid Lab sample – 27-10

D206 3.000 L/tonne Antifoam 8800009126

D208 0.015 %BWOB Viscosifier 4F0531W

D075 10.000 L/tonne Extender Bl30200686

D500 25.000 L/tonne GASBLOK LT CY60573020

D230 10.000 L/tonne Dispers. LT 300175759

D081 3.000 L/tonne Retarder CP140604

Rheology (R1B5F1) Temperature 27 degC 16 degC After Crush@16 degC

(rpm) Up

(deg)

Down

(deg)

Average

(deg)

Up

(deg)

Down

(deg)

Average

(deg)

Up

(deg)

Down

(deg)

Average

(deg)

300 40.0 40.0 40.0 53.0 53.0 53.0 89.0 89.0 89.0

200 30.0 28.0 29.0 42.0 40.0 41.0 68.0 64.0 66.0

100 19.0 16.0 17.5 25.0 22.0 23.5 42.0 38.0 40.0

60 14.0 11.0 12.5 18.0 15.0 16.5 32.0 26.0 29.0

30 10.0 8.0 9.0 13.0 10.0 11.5 25.0 18.0 21.5

6 6.0 5.0 5.5 8.0 6.0 7.0 15.0 11.0 13.0

3 5.0 4.0 4.5 7.0 5.0 6.0 12.0 9.0 10.5

10 sec Gel 5 deg - 5.94 lbf/100ft2 7 deg - 8.31 lbf/100ft2 9 deg - 10.69 lbf/100ft2

10 min Gel 12 deg - 14.25 lbf/100ft2 15 deg - 17.81 lbf/100ft2 23 deg - 27.32 lbf/100ft2

Rheo. computed Pv : 77 cP Ty : 5.80 lbf/100ft2 Pv : 106 cP Ty : 7.38 lbf/100ft2 Pv : 169.0 cP Ty : 14.72 lbf/100ft2

Thickening Time Consistency Time

POD : 09:41 hr:mn

40 Bc 10:01 hr:mn

50 Bc 10:27 hr:mn

70 Bc 10:51 hr:mn

100 Bc 11:37 hr:mn

UCA Compressive Strength Time CS

10:16 hr:mn 50 psi

12:00 hr:mn 112 psi

19:33 hr:mn 500 psi

24:00 hr:mn 645 psi

Free Fluid 0.0 mL/250mL in 2 hrs

At 27 degC and 45 deg incl

Sedimentation : None

Fluid Loss API Fluid Loss 71 Ml

In 16 min at 27 degC and 1000 psi

55

Report comment

Similar procedure was done with tail slurry test, as for a lead slurry. The difference between them,

is the slurry density, tail slurry density is higher than lead slurry which is why, during the casing

jobs, both of them are needed in other to avoid high pressure gradient (hydrostatic and friction ),

or to reduce the pressure effect on the formation. Therefore lead is pumped first and tail is

following, in order to underbalance the well.

8.4 THICKENING TIME CHART REPORT

Figure 17: Thickening time chart for lead slurry

Source: Schlumberger

56

8.5 UCA CHART REPORT

Figure 18: UCA chart for lead slurry

Source: Schlumberger.

Comparing the two tests for tail and for lead slurry, it is notable that, lead slurry density is lower

than the tail slurry, it can also be noticed from the thickening time tests and UCA tests, that the

time required to set a lead cement slurry is much longer (almost double the time) comparing to

the time need for a tail slurry. Meaning that in ways that tails density is higher it may starting

setting first and with small time required then a lead cement slurry. There is also a significant

difference between the compressive strength of the two types. After 24 hours tail slurry has a

1670 psi compressive strength while lead slurry has only 645 psi. According to ASTM standards

after high temperature can effect strength negatively.

57

9. CASINGING - CEMENTING JOB DESIGN

9.1 JOB DESIGN FOR 20 TO 10 "CSG

Figure 19: Casing job design cementing design stage

Source: Total reports

As shown in Figure 19, a complete casing design needs to contain specific information about the

cement applied. Also the preliminary planning has to have information regarding separate

production zones to help planning of plug cementing operation. The figure shows how a 225 m

thick oil producing zone at the deviated section is plug cemented in order to separate it from the

oil and gas producing zones in the mostly horizontal section.

58

9.2JOB DESIGN FOR (2) 9 7/8" AND 9 5/8"

9.2.1 PORE AND FRACTURE PRESSURE PROFILE

Figure 20: Casing job design - pore and fracture pressure profile.

Source: Schlumberger Cementing program.

Pore and fracture profile is important not only for drilling mud calculations and planning but also

for cementing. Cement slurry is usually higher in density than mud therefore a pressure design is

important not to fracture the formation.

59

9.2.2 CASING AND HARDWARE TOOLS INFORMATION

Table 11 and 12, Contains the casing and formation information of a typical offshore well in Angola

that I used as a base for my measurements and density calculations.

Table 11.

Prev

Casing

2091.0 36 12.0 726.9 32 X-65 5020 5440 HC

100/MT

2154.0 36 12.0 552.5 33 X-56 1063 2720 D-

90/MT

3251.4 20 13.4 129.3 18 3/4 X-56 1449 3063 S-

60/MT

3675.0 13 5/8 12.5 88.2 12 3/8 Q125HP 4800 10034 SLSF

4058.9 13 3/8 12.5 72.0

12.347 C-90 2780 6050 VAM

Top

Drill Pipe 2071.0 6 5/8 12.0 44.0 5.199 VM 140

DP

19000 19300

Tubulars and Casing

Hardware

MD m OD

in

Joint

m

Weight

lb/ft

ID in Grade Collapse

psi

Burst psi Thread

Riser 2071.0 21 12.2 0.0 19 1/4 0 0

Casing 3830.0 9 7/8 12.7 62.8 8 5/8 Q-125 11140 13840 HYD523

4880.0 9 5/8 12.8 53.5 8.535 P-

110HC

11180 12390 VAM

Top

Float Collar 4864 S/N : TBC

Float Shoe 4880 S/N : TBC

60

Table 12

Formation Data

MD

(m)

TVD (m)

Frac

(lb/gal)

Pore

(lb/gal)

4760.0 4759.7 13.51 9.00

4824.0 4823.7 13.61 8.90

4880.0 4879.7 13.71 8.90

61

10. SUMMARY AND CONCLUSION

The purpose of this work test was to determine mainly the relative degradation of class G cement,

for typical well temperatures in Angola and also for cases like long time abandoned wells or for

plug cements and wells that may have a high temperature effect. Therefore it was necessary to

determine the used G cement integrity and the strong effect that a high temperature may have on

the cement samples during the time of the experiments.

Based on the tests that were done for integrity and thermal effects of cement, I could conclude

that aging at 250 deg F (121.11 deg C), did not caused several deterioration in water permeability,

porosity stayed similar after aging the samples on high temperature. The water permeability for

each sample were below the theoretical limit (0.1mD) found in the literature [15].

Nevertheless, for such situation, where cement G is used in wells of high temperature, basic

points should be considered, which an engineer should remember when contemplating this

planning:

When static temperature exceed 230 deg F (110 deg C), which is in similar case for this

experiment, 30 to 40 percent of silica BWOC should be planned to be added to Portland cements.

Otherwise, strength retrogression may occur.

It is also important to mention that, extenders can also help in such situation for the fact that they

are compatible with thermal cements.

Based on my results it can be stated that API G class cement up to ~120 deg C keeps its integrity.

Since Class G is cheaper that special thermal cements (Thermal G), choosing G cement in zones

With temperature less than 120 deg C can contribute to cost reduction.

62

11. REFERENCES

[1] Alberta: Primary and Remedial cementing, schlumberger Guidelines, 1995.

[2] American Petroleum institute (API), twenty third Edition, Specification for cements and

Materials for well Cementing, 2002

[3] API Specification 10A, Specification for Well Cementing Materials, twenty third Edition, 2002.

[4] Anon, Workbook Baker Hughes: Casing and Cementing Drilling Engineering, 1995.

[5] Bett EK: Geothermal Well Cementing Materials and Placement techniques, 2010.

[6] Hussain Rabian: Well Engineering and Construction.

[7] Erik B. Nelson: Well Cementing, 1990

[8] Erik B. Neilson and Dominique Guillot, Second Edition, schlumberger, well cementing, 2006.

[9] Larry W. Lake: Petroleum Engineering Handbook.

[10] Goodwin, K.J.: Principles of squeeze Cementing, 1984

[11] http://petrowiki.org/PEH:Casing_Design Downloaded 20.09.2017

[12] http://www.glossary.oilfield.slb.com/ Downloaded 25.09.2017

[13] http://www.revataengineering.com/top-bottom-cementing-plugs.htm

Downloaded 25.09.2017

[14] Michaux M. Nelson EB: Chemistry and Characterization of Portland cement In Well

Cementing, 1990.

[15] Nelson, E and Eilers, L.: Cementing Steam flood and Fireflood wells-Slurry Design, 1985.

[16] Robert F. Mitchell, Volume II: Drilling Engineering, 2006.

[17] Schlumberger, well services, well integrity, cementing overview guideline.

63

[18] http://www.halliburton.com/en-US/ps/cementing/cementing-solutions/lost-circulation-

materials.page

[19] Schlumberger, Primary cementing, casing hardware, presentation guideline.

[20] https://www.slideshare.net/akincraig/petroleum-engineering-drilling-engineering-primary-

cementing

[21] Smith R.C.: Successful of Primary Cementing, 1982.

[22] Schlumberger, Plug cementing Overview guideline.

[23] http://gekengineering.com/Downloads/Free_Downloads/Cementing_Chapter_3.pdf

[24] Schlumberger, Stage cementing and Squeeze Cementing operation

64

12. APPENDICES

Figure A-1

Figure A2

65

Figure A-3

Figure A-4

66

Figure A-5