Well Control Planning for Casing Drilling (CwD) Wells ...

University of Miskolc

Faculty of Earth Science and

Engineering Petroleum and Natural

Gas Institute Petroleum Engineering

Department

Well Control Planning for Casing

Drilling (CwD) Wells Compared to

Conventional Drilling

Author's name: Ayzatulin Raid

Instructor's name: Gabriella Federer-Kovacs

Miskolc, 6th May 2021

Proof Sheet for thesis submission for Petroleum Engineering MSc students

Name of student: Ayzatulin Raid Neptune code: CBEJP8 Title of Thesis: Well control planning for CwD wells

Declaration of Originality:

I hereby certify that I am the sole author of this thesis and that no part of this thesis has been published or submitted for publication. I certify that, to the best of my knowledge, my thesis does not infringe upon anyone’s copyright nor violate any proprietary rights and that any ideas, techniques, quotations, or any other material from the work of other people included in my thesis, published or otherwise, are fully acknowledged in accordance with standard referencing practices.

6 May 2021

Signature of the student

Statement of the Department Advisor:

Undersigned PhD Gabriella Federer-Kovacs, I agree/ do not agree to the

submission of this Thesis. 6 May 2021

Signature of Department

Advisor

The thesis has been submitted:

Administrator of Petroleum and Natural Gas Institute

MISKOLC 2021.

Thesis assignment for

Ayzatulin Raid Petroleum Engineering, MSc student

Title of the thesis work: Well Control Planning for Casing Drilling (CwD) Wells Compared to Conventional Drilling 1) Explain the different types of drilling techniques based on domestic and internationalliterature.2) Describe the special operations in case of CwD operations.3) Explain the special tools that a CwD operation requires compared to conventional.4) Make a theoretical case regarding a well control scenario for two different depth andcalculate the MAASP and the necessary shut-in times for CwD and conventional.5) Summarize your findings and decide whether the planned CwD operation is feasible orsome changes in the original planning is needed.

Department supervisor: Dr. Gabriella Kovácsné Federer Assistant professor

Industry supervisor: ----

Dr. Zoltán Turzó University Professor, Head of Department

Miskolc, 2021.02.25.

MISKOLCI EGYETEM

Műszaki Földtudományi Kar

UNIVERSITY OF MISKOLC

Faculty of Earth Science & Engineering

H3515 Miskolc, Egyetemváros, HUNGARY Tel: (36) 46 565 078

[email protected] www.kfgi.uni-miskolc.hu

ACKNOWLEDGMENT

As the author of this thesis work, I would like to convey my special thanks to my professor

and department advisor from university Gabriella Federer-Kovacs, whose expertise was

invaluable in formulating the research questions and methodology. Your insightful feedback

pushed me to sharpen my thinking and brought my work to a higher level.

Also, I would like to express my gratitude to my mother, without whom none of this would

be possible. You are always there for me. Finally, I could not have completed this dissertation

without the support of my friends, who provided stimulating discussions as well as happy

distractions to rest my mind outside of my research.

ABSTRACT The technique of drilling a wellbore by using casing instead of drill pipe (Casing while Drilling-

CwD) is gaining in relevance within the Oil & Gas sector since its implementation in the last

decades. The performance of this technique has drastically improved over last 30 years. This

technique, aside from the evident reduction in drilling time and costs observed when applied is

convenient to minder the effects of certain while-drilling issues as those arising while drilling

unstable formations. The focus of concern in this work will be the geometry-related aspects of

Casing Drilling influencing not only the drilling operation itself but its particular well control

needs as well; this latter will be explained in detail. Also kick tolerance calculations will be

shown, which will display the influence of well geometry to the well performance in terms of

well control along with some other aspects like maximum allowable well shut-in time and etc.

Table of Contents 1. Introduction to Directional Drilling and Casing while Drilling. .......................................................... 1

1.1 Principles of Directional Drilling. .................................................................................................. 2

1.2 Reasons for Directional Drilling. ................................................................................................... 2

2. Casing while Drilling (CwD). .............................................................................................................. 4

2.1 DCwD Surveying systems. ............................................................................................................ 4

2.2 CwD and DCwD. ........................................................................................................................... 5

2.3 Objectives of Casing while Drilling. .............................................................................................. 7

2.3.1 Depleted or Low-Pressure Zones. ........................................................................................... 8

2.3.2 Subsalt Formations. ................................................................................................................. 8

2.3.3 Tar Zones............................................................................................................................... 10

2.4 Equipment. ................................................................................................................................... 11

2.4.1 Casing drive system. ............................................................................................................. 11

2.4.2 Powered catwalk. .................................................................................................................. 13

2.4.3 Non-retrievable BHA. ........................................................................................................... 13

2.4.4 Retrievable BHA. .................................................................................................................. 15

2.5 Benefits of CwD. .......................................................................................................................... 19

2.5.1 Plastering effect. .................................................................................................................... 19

2.5.2 Wellbore cleaning ................................................................................................................. 21

2.5.3 Wellbore stability. ................................................................................................................. 22

2.5.4 Losses while drilling. ............................................................................................................ 23

2.6 Challenges and Limitations of CwD (DCwD) ............................................................................. 24

3.Well Control. ....................................................................................................................................... 26

3.1 Hydrostatic Pressure. .................................................................................................................... 26

3.2 Formation Pressure. ...................................................................................................................... 27

3.3 Pressure Balance. ......................................................................................................................... 27

3.3.1 Mud weight used less than formation pressure. .................................................................... 28

3.3.2 Swabbing occurred while tripping operations. ...................................................................... 28

3.3.3 Lost circulation. ..................................................................................................................... 29

3.3.4 Failure to keep the hole full of mud while tripping. .............................................................. 29

3.4 Well Control Procedures. ............................................................................................................. 29

3.4.1 Kill Sheet Calculations. ......................................................................................................... 31

3.4.2 Well Kill Methods. ................................................................................................................ 32

3.4.2.1 Driller’s Method. ............................................................................................................ 32

3.4.2.2 Wait and Weight Method. .............................................................................................. 33

4. Practical part. ...................................................................................................................................... 35

4.1 Kick tolerance calculations. ......................................................................................................... 35

4.1.1 Kick tolerance calculations for 1st kick depth scenarios........................................................ 35

4.1.1.1 CwD calculations. .......................................................................................................... 36

4.1.1.2 Conventional drilling calculations. ................................................................................. 41

4.1.2 Kick tolerance calculations for 2nd kick depth scenarios. ...................................................... 43

4.1.2.1 CwD calculations. .......................................................................................................... 43

4.1.2.2 Conventional drilling calculations. ................................................................................. 46

4.2 Influx inflow rate and available well shut-in time calculations. .................................................. 49

4.3 Summary of example well calculations........................................................................................ 51

5. Conclusion. ......................................................................................................................................... 54

6. References .......................................................................................................................................... 55

1

1. Introduction to Directional Drilling and Casing while Drilling.

Formerly, the introduction of fundamental wellbore surveying methods initiated the use of

directional drilling. By using these techniques, drillers realized that wells intended to be totally

vertical are uncontrollably curving to undesirable directions. To avoid this deviation, drillers

developed various methods to keep the well path in upright trajectory. After some time, the very

same methods were used to knowingly deflect the well path. They were applied in order to

intersect reservoirs that are not achievable or unprofitable in a commercial sense and

environmentally unviable to reach with the application of conventional vertical drilling. In the

modern world, directional drilling involves three major disciplines: extended-reach drilling,

multilateral drilling and short radius drilling.

Figure 1. Self-made picture showing multilateral, extended-reach and short radius drilling.

Extended-reach well is thought about as a well, which has horizontal section at least twice as

much of its vertical depth. The objectives of ERD are: a) to get to a larger area from one surface

2

exploration spot, as well as b) to maintain a well in a reservoir for a longer distance in order to

take full advantage of its productivity and also drainage capabilities. Multilateral drilling assists

to enhance wellbore exposure to zones producing hydrocarbons by branching several extensions

from a single borehole. This allows one well to produce from multiple reservoirs. Multilateral

wells are effective for complicated geology where drilling extra new wells to penetrate to those

reservoirs is not cost-effective. Short radius drilling aids to achieve wells with a curvature of

44m [144ft] radius or smaller. [1]

1.1 Principles of Directional Drilling.

Generally directional well starts off with the drilling of a vertical section till the

predetermined depth called as the kickoff point (KOP), the well path is sidetracked from vertical

by use of an inclination to start the build section. During the drilling procedure parameters like

inclination and azimuth acquired through consecutive surveys to stay informed about drill bit

position and toolface. These parameters are accurately tracked by the directional driller to

maintain well trajectory in the intended path and intersect the next target point with high

precision.

The traditional technique of deflecting well path is carried out by the positioning of stabilizers

in numerous points of the drill string. The method involves increasing, maintaining or

decreasing inclination by adjusting side forces acting upon the BHA as well as the bit.

During the well trajectory determination, dogleg severity (DLS) is among the aspects ought

to be carefully taken into consideration. DLS is a measure of the amount of the modification in

inclination and or azimuth of a borehole, and is defined in degrees per 30 meters of course

length. High DLS can be a cause of the numerous drilling problems such as higher possibility

of differential sticking and also failure of drill pipe as a result of the fatigue wear. Additionally,

it causes casing run obstacles by increasing the frictional force. In order to avoid issues

mentioned above DLS has to be kept to a minimum.

1.2 Reasons for Directional Drilling.

Directional drilling operations are necessary when vertical drilling is not feasible or is

inefficient in a commercial sense, as well as for the specific cases when the petrophysical

properties of a reservoir indicate that the productivity is higher in a given angle or even

3

horizontally. Main applications of it include drilling into hard-to-reach locations, drilling of

relief wells, sidetracking, salt dome drilling, getting to thin reservoirs, drilling several wells

from a single site and etc.

4

2. Casing while Drilling (CwD).

Casing while Drilling (CwD) is a process of utilization conventional oil field casing as a the

drillstring, therefore the well is concurrently drilled and cased. Either surface and downhole

tools and elements are needed to make this procedure possible. The connections between casing

pipes were not very durable and with time, drillpipe developed as more powerful and stronger

connection and therefore, casing was not utilized for drilling. In 1950's the concept of drilling

with casing re-emerged, while there certainly were many possible benefits of this method, it was

not commercially accepted because of the limitations in materials and cutting equipment that

were readily available at that times. However, the efforts to development assisted in the process

sufficiently, in order that it might end up being a successful commercial service in the future.

While a number of the functions and activities resemble the traditional drilling procedure, there

are some sufficient distinctions to necessitate special drilling consideration. The drillpipe as well

as drill collars are used and the logging, coring and perforating procedures are the same with

traditional. To satisfy the loading and bottom hole criteria, the modifications are performed in

surface lifting facility and bit.

A traditional drillstring should be tripped out of the hole every single time the bit or BHA

needs to be changed or the casing point is reached. After that casing is run into the well, being

a totally different process to provide permanent access to the well bore. CwD systems

incorporate the drilling and casing procedure to provide more efficient well construction system

by removing these drillstring trips and permitting the well to be all at once drilled and cased. [2]

2.1 DCwD Surveying systems.

Gyroscopes as well as magnetic MWD tools are two most commonly used wellbore

surveying tools in the contemporary oilfield. Currently, for figuring out the position of

directional wells, Magnetic MWD surveying can be considered as one of the most wide-spread

surveying methods. During the connection in the drilling process a set of downhole

measurements obtained composing an MWD survey. Under the most beneficial conditions, the

application of these measurements should not require any extra rig time, together with providing

directional driller with continuous 'near-real-time' data verifying that the well is being drilled

5

through the pre-determined trajectory. Unlike the MWD, gyroscopic surveys require additional

rig time.

Throughout the drilling operation, the majority of wellbore surveys are carried out by MWD

tools. Modern MWD tools are utilizing a directional sensor with 3 perpendicular accelerometers

as well as 3 perpendicular magnetometers. As the drilling environment is extremely dynamic,

MWD tools have been designed to be very sturdy and at the same time providing high precision

measurements. In the past, MWD surveying techniques were considered much less accurate

than gyroscopic surveying methods, however, developments in magnetic surveying technology

have made MWD surveying methods a lot more precise making it far more practical and

efficient than extra time necessitating and also expensive gyroscopic surveys.

If a kick happens throughout logging, it is possible to circulate it out of the well. Nonetheless,

if the borehole collapses, it may not be possible to get a log across the entire interval. LWD

tools have already been used in vertical wells during drilling operations with casing.

Nonetheless, the addition of LWD tools to a retrievable BHA adds to cost, weight and also

length, which should be balanced against wireline retrieval risks as well as vibration issues in

longer BHA extensions.

A retrievable system allows the bit as well as BHA to be deployed originally as well as

replaced without tripping casing into and also out of the hole. This method is the only functional

option for directional wells due to the necessity to recover costly BHA components, such as

downhole motors, rotary steerable systems or measurements-while-drilling (MWD)and

logging-while-drilling (LWD) tools. A wireline-retrievable system facilitates replacement of

equipment that fails prior to reaching TD, and also allows fast, cost-efficient access to log,

examine as well as test formations. [3]

2.2 CwD and DCwD.

Ever since the beginning of the Oil Industry the initial concept of extracting oil from the

underground reservoirs has implied a continuous pathway of technological development. For

instance, back in 1901 Spindletop discovery well was drilled using a 10in casing as a drill string,

as an alternative to the drill pipe widely used nowadays. The idea of drilling using casing pipe

is not brand-new, as a matter of fact back in 1926 and also 1970 the first patents of equipment

6

to perform Casing while Drilling (CwD) were acquired. The concepts involved in this brand-

new technology were obviously understood; nevertheless, back then the techniques, materials,

and sustaining equipment were not ready to make this innovation applicable as well as

commercially profitable. Drill pipe has already been used as the basic component for a drill

string, however from 1998 the concept of using casing pipe as a component that replaces the

drill pipe was reconsidered. To achieve this objective, development of a full system that makes

it possible for this technology to be implemented was necessary. New concepts as well as

computer software were created to predict if the CwD application is both feasible and practical.

Nowadays in the industry two types of Casing Drilling applications exist: The directional

casing while drilling (DCwD) along with the non - directional casing while drilling (CwD).

CwD is generally applied in the sections where directional control is not needed, and DCwD is

used in sections where strict directional control is required. DCwD is drastically more

complicated, both in terms of tool choice and pre-planning needs, that's why more complex

planning procedure is required. Prior to figuring out if an application of DCwD is suitable,

simulations together with analysis have to be carefully evaluated to predict generally the

following parameters:

Buckling

Fatigue

Torque

Hydraulic requirements

All those parameters are entirely depending on selection of tools for the particular application

as well as input parameters for static simulations. Every result can confirm or discard the

selection of a component, establish the minimal rig capabilities or reformulate an entire BHA

setup. The initial step to select a well candidate where DCwD will be applied, begins with a

feasibility review which could be divided basically in two stages: technical feasibility research

along with economic feasibility research. Combination of outcomes acquired from both research

studies eventually will determine the feasibility of the entire application. Using an established

sequence, the technical feasibility should be analyzed first and if the outcome shows a good well

candidate, the economic feasibility should be determined to recognize the profitability and

associated risks. [4]

7

The Technical Feasibility Analysis steps can be listed as follows:

Analysis of Gathered Information from Offset Wells

Time Savings by using DCwD

Identification of Conventional Drilling Problems.

Simulations: Casing Driller, IDEAS

Retrievable BHA Design

Feasibility Criteria

2.3 Objectives of Casing while Drilling.

Core to the CwD (Casing while Drilling) principle is the simple fact that the string is

constantly at the bottom while drilling, and every foot drilled is a foot acquired in well length.

If the string ends up being stuck, and attempts to release it are unsuccessful, the internal string

is being pulled out (in case the BHA is of the retrievable type) before the casing is cemented in

place. As soon as the cement is set, the driller may proceed by drilling further based on the

drilling program. Using CwD will therefore lower the occurrence of unpleasant incidents that

might result in the loss of the wellbore, and time-consuming sidetracks. [5]

Operators are experiencing as well as overcoming new difficulties which just a couple of

years ago would certainly have precluded them from completing the drilling process in a lot of

today's wells. Operators acknowledge that drilling nonproductive time (NPT) is going for

unacceptably high levels. On drilling rig, every day of NPT means undesired, sometimes critical

financial losses. Accepting 30% drilling NPT has actually become a rule of thumb in lots of

challenging drilling environments, also reaching a 45% failure rate in some wells. Primarily,

wellbore instability issues seem to be the major source of NPT in problem wells. Some operators

have actually reported wellbore instability accounting for over 40% of their overall NPT and

also some 25% of total drilling expenses in these difficult wells. Tar zones, subsalt applications

as well as depleted zones are examples of a few of the issues encountered that need to be

overcome and which typically increase NPT during the drilling process. While advances have

actually been made, these challenges continue to lead to considerable risks for operators

working to develop brand-new discoveries.

8

Decreasing NPT while drilling through trouble zones is one of major objectives of CwD

(Casing while Drilling) application.

2.3.1 Depleted or Low-Pressure Zones.

New zones in developed fields keep being actively developed as operators make every effort

to maintain depleting reserves. Much of the world's brand-new reserves are discoveries made

beneath these existing, mature reservoirs. Drilling activities in or near producing or formerly

left reservoirs often encounter large variations in pressure gradient as depleted layers or under-

pressured zones are exposed during the drilling procedure. Zones with pressures irregular with

the overburden are typically encountered and the uncertainty of pressure expectations in these

wells can result in difficulties in well planning, handling mud systems due to issues with lost

circulation, sloughing, or collapsing formations. If conventional drilling methods are used, then

the greater mud weight used to hold back the target interval may lead to enormous losses in the

lower-pressure zone. To alleviate this danger, the operator is frequently forced into a

conservative drilling program with lowered flow rates, lower weight on bit and decreasing

penetration rates or extra casing points. CwD can be advantageous in these cases due to the fact

that low-pressure zones are simultaneously isolated while being drilled through and increased

wellbore strength caused by plastering effect, which will be discussed in detail further in this

research.

2.3.2 Subsalt Formations.

As the industry keeps on pushing the limits of advancement, a progressively larger number

of technological barriers emerge. In addition, a lot more complex tight-tolerance casing designs,

subsalt formations, and issues connected with them raise the operator's risk of drilling in these

environments. These zones normally have unstable pore pressures and can possibly be

susceptible to "creeping" as the pressures strive to normalize. This creep effect results in

extremely unsteady rubble zones, which can seriously hinder drilling efficiency.

9

Figure 2. Typical salt dome in the Gulf of Mexico. [6]

In some cases, operators need to drill long sections of salt. On Figure 2 a huge salt dome

which is typical for formations in the Gulf of Mexico can be observed. Rubble zones can be

normally discovered at the start or at the end of the salt area, with the section at the end being

more problematic. These rubble zones trigger lack of borehole stability and can produce severe

vibration in the drillstring to a moment where holes collapse or bottomhole assemblies (BHAs)

twist off. It is usual practice to drill sidetracks after the preliminary BHAs are trapped when

drilling out of these rubble zones. Also, salt has a tendency to creep into already drilled sections

where not only drilling forward but also drilling backwards is necessary. Maintaining the

directional well plan can likewise end up being more difficult in subsalt formations because of

the vibration issues. Cases of severe drillstring vibration while drilling a salt or subsalt section

have hindered measurement while drilling (MWD) or logging while drilling (LWD) systems

from running correctly and may need a trip to adapt the drilling assembly. In such circumstances,

having a stable drilling system where the formation can be cased off while drilling significantly

10

lowers the risk. If done correctly, this might be the greatest drop in operator NPT in challenging

wells. In some cases, using non-retrievable system can be advantageous because of the fact that

when retrievable BHA is removed, weak or moving formations at the bottom of the well are not

supported by anything.

2.3.3 Tar Zones.

Among the increasingly more common problems experienced in subsalt environments is

drilling through tar deposits. Considerable problems can occur due to the tar's highly viscous

and unstable state in the formation. Tar usually is not rigid enough for being drilled or broken

into convenient pieces by the drill bit and its extremely viscous nature does not allow itself to

be easily circulated out of the wellbore in a fluid condition. Preliminary encounters with tar

throughout the drilling process can possibly vary from minimal or no problems for thin,

segregated layers to significant troubles drilling through thicker layers. Extended, challenging

tar layers have actually created torque issues so serious that drillstrings have actually twisted off

and wells have needed to be sidetracked to resume drilling operations. Even after successfully

drilling through a tar zone, issues can continue throughout subsequent drilling below the tar

layer. Tar deposits collect in stratigraphic traps under salt zones and could be extremely prone

to flowing inside the wellbore. This propensity to flow into the wellbore generates additional

tensions and difficulties for the drillstring. Amongst these problems are drillstring torque while

drilling subsequent zones and more significantly, problems re-entering the wellbore right after

a trip. These problems generally lead to NPT spent re-drilling a tar zone. After the drilling cycle,

numerous instances of openhole logging tools becoming stuck or issues getting casing

throughout these zones also occur. With steerable casing technology, it is achievable to drill

through such tar zones and isolate them at the moment they are being drilled through. Once

casing is across the open hole, the total risk profile of the well is tremendously decreased.

Numerous proposals to manage tar have actually appeared throughout the years, however few

effective solutions have actually materialized. With steerable casing technology, finally this

might be possible. [6]

Overall, main objectives of CwD as well as DCwD (Directional Casing while Drilling)

application can be summarized as following:

11

Preventing NPT required for tripping drillpipe out of the well.

Preventing NPT required for setting the casing to desired depth.

Minimizing NPT related to hole problems (lost circulation, stuck pipe etc.)

Reducing risks related to hole problems while drilling through trouble zones.

2.4 Equipment.

This technology has actually been mainly developed and released by the Tesco Company.

Tesco has several rigs that are regularly drilling by use of CwD in Southern Texas. The CwD

system needs a few pieces of equipment which are distinct to this type of operations. Those

pieces of equipment can be organized as listed below:

1. Surface circulating and lifting system

- A casing drive system

- Powered catwalk

2. Downhole or sub-surface equipment

- A non-retrievable BHA (bit)

- A retrievable BHA (Retrieval pin box tool and bit)

Each of these tools is needed to carry out Casing while Drilling. Each will be described

briefly.

2.4.1 Casing drive system.

The Casing Drive assembly is utilized to grab and seal the casing so torque could be

transferred to the casing and mud could be pumped through it. Depending upon the size of casing

being dealt with, Tesco utilizes two different types of drive assemblies. An external gripping

system is utilized for casing sized from 4 1/2" to 8 5/8" and an internal gripping system for 7"

to 20" pipes. Both assemblies utilize swab-like cups to seal on the inside of the casing so mud

can be circulated (Figure 3).

12

Figure 3. Casing drive system. [7]

The gripper installations are hydraulically operated and have a 40K ft-lbf torque rating. The

external gripping mechanism has a 350 tons API 8C load rating and the internal system 500

tons. These assemblies both mate to a Top-Drive assembly which is required for performing the

CwD operations. The regular technique is to lift the casing with the link-tilt mechanism and stab

the pin of the casing joint into the box of the casing hanging in the slips. As soon as stabbed, the

top drive is lowered, stabbing the drive assembly into the new joint of casing. The drive

assembly is then triggered to grip the casing and the top drive is utilized to spin the casing into

the box. Final make-up connection is also done with use of top drive.

13

2.4.2 Powered catwalk.

Casing drilling rigs usually are modified with pipe handling simplification systems. One of

these modifications is powered catwalk, which is pipe handling system created in order to

provide opportunity to automatically move pipes from pipe rack to the drill floor. It is possible

for pipe to be off-loaded and loaded from both sides of the catwalk. Pipe is being lifted to the

catwalk from the pipe rack by hydraulic arms. Then, the catwalk lifts and positions the pipe in

such position so the next casing collar is ready for connection, which means until they can lift

it to vertical position. This system can automatically adjust to the length of casing collar and is

fully controller by the driller.

Figure 4. Tesco® TAC 23 Hydraulic Catwalk. [8]

2.4.3 Non-retrievable BHA.

The non-retrievable BHA might include drillable bit or non-drillable bit (Figure 5).

a) A drillable bit is made from soft steel and hard cutting elements; for that reason, it is

normally used on soft to medium formations. After the target TVD is reached, this type of bit is

14

simply being drilled through and drilling can then be continued with smaller diameter bit.

Weatherford is one of the companies providing this type of bits.

Figure 5. Non-retrievable Drilling Bits. [25]

b) Non-drillable bit is made from hard steel and can be utilized to drill across hard

formations. When using non-drillable bit, it must be detached and let fall into the rat-hole that

had already been drilled. When the drilling reaches the target depth, a ball is dropped to a ball

catcher, which completely shuts off the circulation inside the casing. The pressure then is

developed and forces the cylinder to push the bit to open. This piston force makes the bit expand

from within and leaves it with open cylinder. On the next drilling step, a brand-new curvature

should be steered to stay away from the bit in the rat hole. [9]

15

2.4.4 Retrievable BHA.

Use of retrievable systems is the only practical choice for directional wells because of the

need to recover the directional-drilling and guidance tools.

Figure 6. Retrievable BHA applied in DCwD. [10]

The tools utilized for most of the CwD industry applications reported in the literature were

limited to near-vertical wells due to the construction of the DLA (Drill-lock Assembly) and

running and recovering tools. As practical experience was growing with the original tools and

the requirements for directional work became better comprehended, a brand-new generation of

16

tools was designed. These particular tools maintained the proven ability to axially as well as

transversely unlock and lock the drilling BHA to the casing, locate the DLA in the profile

without depending on wireline measurements, seal in the casing to direct the drilling fluid

through the bit, and bypass fluid around the tools for running and recovering. New functions

contributed to the tools make it possible for them to be run and recovered in deviated wells with

inclinations greater than 90 °. The BHA can be released with a pump-down dart before running

the wireline. The majority of the tool complications is placed in the running and recovering

tools, instead of in the BHA components that are subjected to drilling forces and vibration. The

wireline-retrieval system can be applied with 13 3⁄8- in. or smaller sized tools, while at the same

time a drillpipe running/retrieval option is likewise available for all of the tools. The DLA has

a reasonably wide, total open bore (2 3⁄4 in. for a 7-in. casing DLA) in order to decrease pressure

losses as well as to facilitate any wireline operations that might be needed for the drilling BHA

suspended below the DLA. The directional-drilling BHA utilized along with the CwD system

typically consists of a pilot bit, nonmagnetic drill collar(s), underreamer, steerable mud motor

and also MWD.

Figure 7. Self-made picture of DLA (Drill-lock assembly).

17

This corresponds to the assembly which is frequently utilized for conventional directional

drilling, other than that the mud motor is frequently smaller sized than what would be applied

for traditional directional work in the very same size hole. A magnetic MWD tool frequently is

used for steering, and also it needs a section of nonmagnetic collars in between it and the casing

shoe. This extends the bit and underreamer from 80 to 120 ft below the casing shoe. The last

distinction between a CwD and traditional directional assembly is fact, that the bend in the motor

is restricted by the fact that the assembly need to travel through a smaller casing size. The gap

between the motor and case is much less than would exist around the open hole and motor for

conventional directional job. Generally, though, a sufficient bend angle can possibly be run to

drill the highest curvature that is safe to use while drilling with casing. [10]

Because of the fact that BHA’s diameter must be small enough to pass through the diameter

of casing used, hole drilled by only bit would be too small for casing to be set. To extend the

hole drilled, underreamer should be run behind the bit.

Figure 8. Bit and extendable underreamer. [11]

18

PDC cutters are being used on extendable arms in order to enlarge the hole. Usage of this

type cutters prohibits application of this tool for drilling through formations that can regularly

be drilled by PDC bits. Rocks which have high compressive strength and require diamond type

or roller cone bit may be not drillable with this kind of underreamer. This fact is among the

limitations of retrievable BHA assembly.

For retrieval process itself, BHA retrieval pin is being used in order to “grab” the BHA so it

can be pulled up to the surface. This operation may be performed for underreamer replacement,

bit changes or before cementing process.

Figure 9. Retrieval pin. [12]

Usually, this tool falls under its own weight, however it can be pumped down the hole if it

refuses to fall for some reason. It is centralized in the casing and should be connected to a neck

which is located on BHA assembly. After it is attached, weigh should be put on the BHA to

release it and after that it should be pulled to the surface. If the depth is shallow, this procedure

can be performed by drillpipe instead of wireline tool because it can be done in shorter time.

19

2.5 Benefits of CwD.

Along with reducing NPT caused by drillpipe tripping and casing running, CwD technology

has many other benefits like plastering or smear effect, improving wellbore stability and hole

cleaning and decreasing losses while drilling through high-loss formations. In this chapter a

brief description of each advantage will be discussed.

2.5.1 Plastering effect.

In wells where CwD technology is used, annular flow area is much less than in conventional

drilling due to higher diameter of casing compared to drillstring. Because of this fact, annular

flow velocities are higher at same flowrate. Researches show that the use of this technique can

decrease formation damage. [13] The plastering effect or smear effect, is a noticed phenomenon

considered to impact boreholes being drilled with a narrow annular space. It is thought that the

wellbore wall is constantly shoveled by the rotating casing or liner, while cuttings are smashed

and smeared by casing string into fractures and pore spaces in the borehole wall. High quality

impermeable mud cake may be created under some conditions and thus it may improve wellbore

stability and strengthen the formation. In some cases, it is considered to solve lost circulation

issues and reduce formation damage. [14]

Figure 10. Plastering effect. [13]

20

In Figure 10, the effect of cuttings being pushed against the wellbore may be observed. This

effect is not properly recorded, but circumstantial evidence like a reduction in cuttings return

while drilling with casing proposes that there is some truth in the theory. It is believed that the

consolidated forces of high annular speed and casing pipe rotation develops an environment

particularly suitable for milling and smearing the cuttings into the formation, and that "The

Plastering Effect" enables tension caging to take place when the cuttings seal off the fractures

in near wellbore formation wall. One more evidence for the indicated effect has been discovered

by taking sidewall core samples which verify that cuttings as well as filter cake have been forced

into the formation. [14]

Figure 11. Plastering effect caused by cuttings being pushed into the formation. [15]

21

2.5.2 Wellbore cleaning

Cuttings removal from a well is primarily a matter of preserving sufficiently high flow rates

to deal with the vertical slipping of cuttings in vertical areas, and to deal with settling of solid

particles in horizontal sections.

Crucial parameters affecting clearing of the wellbore in vertical sections are mud properties

and annular flow rate. For ensuring that fluid’s axial velocity is higher than slip velocity of solid

particles high enough flow rate should be maintained. Minimum velocity required for lifting

the solids up to the surface is called slip velocity, and it is determined by the solids’ geometry

and mud parameters.

However, for horizontal sections, slip velocity’s importance is highly reduced. In horizontal

sections, the distance of vertical travel is limited to wellbore diameter while in vertical sections

it can be up to several kilometers. That’s why it is more important to ensure that solids are not

collecting at solids bed and are being circulated out of the well. Cuttings’ removal in horizontal

sections in addition to flow velocity highly depends on string RPM. [16]

𝐴𝐴𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎 = �𝑂𝑂𝑂𝑂2−𝐼𝐼𝑂𝑂2�∗𝜋𝜋4

Eq. 2-1

From Eq. 2-1can be seen that annular flow area depends on difference of annulus’ outer and

inner diameter.

𝑣𝑣𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎 = 𝑄𝑄𝐴𝐴𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎

Eq. 2-2

Moreover, flowrate to annular flow area ratio determines the annular flow velocity, as it can

be seen from the Eq. 2-2. So, due to casing’s larger diameter, in sections drilled by CwD

compared to conventionally drilled sections annular flow velocity will be much higher, which

will make possible to maintain wellbore cleaning with lower flowrates compared to

conventional drilling. There is one more parameter, which is called Pipe-to-hole Area Ratio

(PHAR). PHAR is parameter which is used for measurement of relative size of the pipe in

relation to the wellbore. This parameter is used for determination of drill string RPM and proper

pump rate in order to maintain wellbore cleaning in medium and high inclination wells. PHAR

is calculated using following equation:

22

𝑃𝑃𝑃𝑃𝐴𝐴𝑅𝑅 = 𝑅𝑅ℎ2

𝑅𝑅𝑝𝑝2 Eq. 2-3

Where 𝑅𝑅ℎrefers to the radius of wellbore and 𝑅𝑅𝑝𝑝 refers to the radius of pipe used. The

theory says that, less drill string RPM is required in order to preserve a viscous coupling, and

therefore desirable hole cleaning, when drilling with a low PHAR. Such as in the case of

drilling by using casing or liner.

Figure 12. Effect of viscous couple on cuttings bed. (Self-made picture)

2.5.3 Wellbore stability.

Casing and liner drilling techniques provide numerous unique aspects that may assist in

alleviating wellbore stability problems. Because the casing/liner is constantly at TD throughout

drilling, the amount of time spent tripping is decreased, and every foot drilled is a foot acquired

in well length. It is typically accepted that most wellbore stability and stuck pipe problems occur

throughout drillstring tripping procedure. One of the most typical concerns while drilling is swab

and surge pressure inconstancies which may cause lost circulation or well control situations.

The failure to circulate the well from the bottom while tripping is another problem, and it can

lead to cuttings settlement or stuck pipeline while tripping in the BHA. Elimination of tripping

23

leaves no chance to instigate such issues. Furthermore, there would be no need for wash and

ream procedures after TD is reached and prior to running casing. [14]

Smooth, continuous motion of the casing string compared to motion of the string made up

from conventional drillpipes is called inherit stiffness of casing. The outcome is a less twisting

wellbore, with a lowered chance of key-seating and stuck pipe issues, which may take place as

a result of mechanical friction. [17] This effect can be observed in Figure 13.

Figure 13. Drilling with casing creates more circular profile (right) compared to

conventional drillstring (left). [14]

The plastering effect which was discussed in chapter 2.5.1, has another property which is

called stress caging. The solids being pushed to the formation by motion of casing strengthen

near-wellbore porous formation. This phenomenon may be able to improve the fracture strength

of the formation, which will lead to increase of wellbore stability. [14]

2.5.4 Losses while drilling.

Ability to maintain required wellbore cleaning at much lower flowrates compared to drilling

with conventional drillpipe combined with plastering effect may be very beneficial while

drilling through high loss formations. While drilling through this type of formations less mud is

24

lost due to lower flowrates. This results in improved HSE, as big enough fluid losses may lead

to noticeable underbalance, which may end up as a well control situation.

2.6 Challenges and Limitations of CwD (DCwD)

Along with benefits of Casing while Drilling, there are several challenges and limitations.

Major challenges of CwD application are following:

1.Torque and drag.

Because of the fact that casing is heavier and has larger diameter comparing to conventional

drillpipe, the torque required to rotate casing string until TD is higher than in case of drillpipe.

This can be seen from Eq. 2-4.

𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇 = 𝐹𝐹𝑇𝑇𝑇𝑇𝐹𝐹𝑇𝑇 ∗ 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑇𝑇𝑅𝑅 Eq. 2-4

2.Stuck pipe.

While risk of pipe getting stuck because of differential sticking is decreased due to Plastering

Effect, there is additional risk caused by stiffness of the string and higher wall to wall friction.

Because of casing’s higher stiffness, it is more sensitive to Dog-leg Severity (DLS). [18]

3.Gas influx.

In case of gas kick occurrence, gas bubble will be longer due to less annular space in CwD.

The longer gas bubble means that the higher surface pressure can be developed. Therefore, the

necessary annular surface pressure may be reached sooner, which means that in certain cases

the influx may become less than in conventional cases. But since the surface pressure is higher,

it may get closer to MAASP and fracturing the formation can be a bigger risk. Also kill methods

have to be chosen carefully considering these facts.

4.Fatigue failure.

In high dog-leg wells drilled with CwD, risk of fatigue failure is increased because of high

reversing stress acting on casing connections. Safe number of total revolutions has to be

calculated in pre-job planning in order to prevent failures caused by fatigue.

25

5.Cost.

Another limiting factor of CwD is cost. In case of CwD while daily drilling cost is reduced,

the investments required for rig modifications like casing drive system (CDS) and hydraulic

catwalk are still very high. Approximate price of this modifications can reach $5,000,000–

6,000,000. [19]

Figure 14. Capital equipment cost required to convert conventional drilling rig into CwD

rig. [19]

26

3.Well Control.

Basically, well control is a technique used in petroleum operations like drilling, workover as

well as well completion. This technique is being utilized in order to control the balance between

formation pressure and hydrostatic pressure to prevent undesired flow of formation fluids like

gas (methane, H2S, CO2) and oil and formation water from the formation to the wellbore and

for removal of the influx in case if occurred. In well control two barriers exist: primary, which

is hydrostatic pressure of drilling mud and secondary, which is BOP (blowout preventer). A

third barrier is also usually in place which is called a ‘sher barrier’ and it means the Shear/Blind

Rams. As it was mentioned before, in well control two main types of pressure, which are

hydrostatic pressure and formation pressure, should be considered.

3.1 Hydrostatic Pressure.

Hydrostatic pressure is a pressure acting on the bottom of column created by fluid. It can be

calculated by use of equation Eq. 3-1.

𝑝𝑝 = 𝜌𝜌 ∗ 𝑔𝑔 ∗ ℎ Eq. 3-1.

Where: p – hydrostatic pressure (bar)

ρ – the density of the fluid (kg/m3)

g – the gravity acceleration (m/s2)

h – height of the liquid column (m)

As it can be seen from equation above, that hydrostatic pressure depends only on height of

the column and density of the fluid, and does not depend on geometry of fluid column, so in

terms of drilling it means that not MD (Measured Depth), but TVD (True Vertical Depth) should

be used as height. However, in oilfield Eq. 3-2 is more often used and the field units are applied.

𝑝𝑝 = 𝑀𝑀𝑀𝑀 ∗ 0.052 ∗ 𝑇𝑇𝑇𝑇𝑇𝑇 Eq. 3-2.

Where: p – hydrostatic pressure (psi)

MW – mud weight (ppg)

TVD – true vertical depth (ft)

27

3.2 Formation Pressure.

Formation pressure is a pressure created by fluids located in the pores of porous formations.

Normally, it is considered to be equal to hydrostatic pressure of water column of the same height

as depth of the formation, however it may vary due to dissolved solids content. Formation

pressure is created by the overburden pressure of rocks located above, acting on fluids in porous

formations. Generally, overburden pressure gradient is expected to be 1 psi/ft, but it can vary

from one place to another, due to difference in rock densities. There are two types of anormal

formation pressures: abnormal, which is higher than hydrostatic pressure of water column at

given depth and subnormal, which is lower.

Figure 15. Graph displaying pore pressure gradients. [26]

3.3 Pressure Balance.

In terms of well control, when we talk about pressure balance, we should consider balance

between hydrostatic pressure of mud column and formation pressure. Generally, there are two

conditions possible: underbalanced and overbalanced. Underbalanced drilling is a drilling

practice, in which hydrostatic pressure of drilling mud column is less than formation pressure

(phydrostatic < pformation). Usually, underbalanced drilling is applied in cases where fracture gradient

is too low. In case of overbalanced drilling hydrostatic pressure should be maintained higher

than formation pressure (phydrostatic > pformation). So, during regular drilling operations we want to

28

keep the well overbalanced through the entire drilling or workover operations. Situation, in

which well will become underbalanced in case of regular drilling operations may cause a kick,

and if prompt actions are not taken even blowout.

Undesirable entrance of formation fluids like oil and/or gas is called an influx or a kick. Kick

can be caused by the drop of hydrostatic pressure below the formation pressure or sudden

increase of formation pressure discovered while drilling through abnormally pressured

formations. Kick or blowout can be caused by several reasons:

1. Mud weight used is less than formation pressure.

2. Swabbing occurred while tripping operations.

3. Lost circulation.

4. Failure to keep the hole full of mud while tripping operations.

3.3.1 Mud weight used less than formation pressure.

During drilling operations, formation pressure at any certain depth can never be known for

sure. While well is being designed, normal formation gradient is being applied for expectable

formation pressure calculations. But due to existence of abnormally pressured formations, at

these formations’ depth formation pressure can cause a well control situation. And mud weight

cannot be calculated with consideration of abnormally pressured formations because of

limitation caused by fracturing pressure.

3.3.2 Swabbing occurred while tripping operations.

Swabbing is effect caused by lifting the drilling, or in case of Casing while Drilling operation

the casing, column up to the surface while tripping operations. The most dangerous moment is

when the BHA (Bottom Hole Assembly) is being lifted from the bottom of the well due to its

larger diameter. If this process is performed faster than it should be, this may cause drop of the

bottom hole pressure which creates “sucking effect” known as swabbing and creates an

opportunity for undesirable flow of formation fluids into the wellbore. In case of a CwD

29

operation since only the retrievable BHA is pulled out the swabbing effect is less than in case

of an entire drill string movement.

3.3.3 Lost circulation.

Lost circulation issue may occur while drilling through weak formations with very low

fracturing pressure. In this situation due to the flow of drilling mud into these formations and

the drop of hydrostatic pressure may cause a kick.

3.3.4 Failure to keep the hole full of mud while tripping.

While tripping, drilling column is being lifted to the surface and its volume should be

displaced by adding mud. If not done so after removing the column, its volume will be displaced

by mud which already is in the hole, and this will cause hydrostatic pressure drop and result in

a kick. And one more important detail is that while drilling collars and BHA are being displaced,

mud’s flowrate should be higher because of larger diameter of those sections.

3.4 Well Control Procedures.

Before any actions can be taken, kick should be discovered. “The well usually talks to us, we

just need to listen”.[20] There are several early warning signals which should be paid attention

to:

1. Unexpectable increase of drilling rate. (ROP)

2. Pit volume gain

3. Changes in pump pressure

4. Reduction of drill pipe weight

5. Gas, oil, or water-cut mud.

If any of this warning indicators are noticed, the shut-in procedure established should be

immediately performed by the drilling crew. Fast actions should be undertaken in order to

prevent more influx from entering the wellbore. According to API RP 59 recommendation, the

crew should be trained to perform well shut-in procedure in less than 2 minutes. In this situation

any delay can cause the kick end up in becoming blowout causing losses in health, equipment

and even life. [21]

30

Figure 16. Drilling data recorder information for a well kick.

[21]

31

In a well control situation, there are two options for well shut-in: hard shut-in and soft shut-

in. Main advantage of hard shut-in is that the well can be shut-in in less time therefore allowing

less influx to enter wellbore, but it may cause a water hammer effect and formation damage.

With soft shut-in situation is quite opposite. Well shut-in takes longer time creating opportunity

for more influx to enter the wellbore, but creates neither hammer effect nor formation damage.

Basically, well shut-in procedure consists of following steps (hard shut-in):

1. Closing the annular preventer

2. Opening choke line manifold valve

3. The remote choke is already closed

4. Adjusting closing pressure on BOP

5. Recording SIDPP and SICP after they have stabilized

6. Recording pit gain

7. Recording well depth.

3.4.1 Kill Sheet Calculations.

After the well is shut-in data recorded should be applied for kill sheet calculations. One of

our main goals at this stage is to calculate kill mud weight (KMW), which is mud weight which

will create hydrostatic pressure higher than the formation pressure in order to regain primary

barrier. Kill mud weight is calculated by Eq. 3-3.

𝐾𝐾𝑀𝑀𝑀𝑀(𝑝𝑝𝑝𝑝𝑔𝑔) = 𝑀𝑀𝑀𝑀(𝑝𝑝𝑝𝑝𝑔𝑔) + 𝑆𝑆𝐼𝐼𝑂𝑂𝑆𝑆𝑆𝑆(𝑝𝑝𝑎𝑎𝑝𝑝)𝑇𝑇𝑇𝑇𝑂𝑂(𝑓𝑓𝑓𝑓)∗0.052

Eq. 3-3

One more important parameter which has to be calculated before killing the well is initial

circulation pressure (ICP), which is the pump pressure required to start circulation and is

calculated by Eq. 3-4.

𝐼𝐼𝐼𝐼𝑃𝑃 = 𝐾𝐾𝑃𝑃𝑅𝑅 + 𝑆𝑆𝐼𝐼𝑇𝑇𝑃𝑃𝑃𝑃 Eq. 3-4

Because of increase of increase in the mud weight, in order to maintain same pump rate,

pump pressure has to be increased and this pressure is referred to as final circulation pressure

(FCP) and is calculated by Eq.3-5. [22]

𝐹𝐹𝐼𝐼𝑃𝑃(𝑝𝑝𝑅𝑅𝑅𝑅) = 𝐾𝐾𝑃𝑃𝑅𝑅(𝑝𝑝𝑅𝑅𝑅𝑅) ∗ 𝑁𝑁𝑁𝑁𝑁𝑁 𝑀𝑀𝑎𝑎𝑀𝑀 𝑊𝑊𝑁𝑁𝑝𝑝𝑊𝑊ℎ𝑓𝑓(𝑝𝑝𝑝𝑝𝑊𝑊)𝑂𝑂𝑂𝑂𝑝𝑝𝑊𝑊𝑝𝑝𝑎𝑎𝑎𝑎𝑎𝑎 𝑀𝑀𝑎𝑎𝑀𝑀 𝑊𝑊𝑁𝑁𝑝𝑝𝑊𝑊ℎ𝑓𝑓(𝑝𝑝𝑝𝑝𝑊𝑊)

Eq.3-5

32

3.4.2 Well Kill Methods.

After kill sheet is calculated, well should be killed in order to regain control. There are many

methods of killing the well and most often-used are: “Driller’s Method” and “Wait and Weight

Method”. Now I would like to talk about them in detail. The main difference between “Driller’s

Method” and “Wait and Weight Method” is number of circulations required in order to kill the

well. In case of “Driller’s Method” two circulations are required in order to kill the well, but in

case of “Wait and Weight Method” only one.

3.4.2.1 Driller’s Method.

As it was mentioned earlier, driller’s method requires 2 circulations in order to regain primary

barrier. The influx is being circulated out of the well during first circulation, which is done with

original mud already located in the wellbore. After first circulation is complete and gas is

circulated out of the wellbore, kill mud is being pumped. While there are many advantages of

“Driller’s Method” like minimum arithmetic required as well as minimum waiting around time,

there are several limitations, which include the fact that surface casing pressure values rise to

their maximum while using this method. Also, no kill mud can be pumped to the hole, which

means that hydrostatic pressure drops in the annulus caused by expanding gas (in case of gas

influx) can be only compensated by closing the choke which leads to very high pressure in

casing when the influx gets close to the surface. [22]

On the Figure 17, pressures in the drill pipe and the annulus can be observed. As it can be

seen, during first circulation annular pressure can reach pretty high values while Driller’s

Method is being applied. On the figure at “Point 1”, in case if influx is gas, annular surface

pressure reaches its highest value and it is caused by gas expansion is the largest at this point.

This can lead to formation fracturing if the last casing shoe is close to the surface, which means

that it’s the weakest part of the wellbore considering the lowest fracture pressure. Also, while

applying this method, casing burst pressure limitations should be taken into consideration.

33

Figure 17. Graphs displaying first and second circulation pressures. [23]

3.4.2.2 Wait and Weight Method.

Unlike Driller’s Method, Wait and Weight method requires only one circulation to kill the

well. It’s called like this because crew has to wait until kill mud is being mixed and then

weighted mud is being pumped to the hole. So, at the time when new kill mud is being pumped

in, old weight mud is being removed along with the influx through the choke. This method offers

advantages like lowest wellbore and surface pressures as well as minimum choke circulating

time. But along these advantages there are several limitations like considerable waiting time

which allows the influx to migrate and if large increase in mud weight is required, it might be

difficult to do so in one circulation. Reason standing behind lower wellbore and surface

pressures is the fact that hydrostatic pressure drop is lower than in Driller’s method due to the

fact that new kill mud can partly compensate hydrostatic pressure drop caused by migration and

expansion of influx up through the wellbore.

34

Figure 18. Graph displaying Wait and Weight circulation pressure.[24]

As in can be seen at the Figure 18, during PH2 (phase2) while influx is being circulated out,

annular pressure increase is lower than in Driller’s method.

35

4. Practical part.

In this practical part, kick tolerance calculations can be observed for theoretical well drilled with

casing. Also, calculations like annular pressure loss, bottomhole pressure and others have been

performed and compared to conventional drilling utilizing drill pipes. Main aim of these

calculations was to display difference between conventional drilling and drilling with casing in

terms of well control. One of important parameters considered in this chapter is length of over

pressured formation drilled before kick is detected, due to the fact that in CwD well annulus is

very narrow compared to conventional well and even small change in influx volume can lead to

a huge difference in well control procedure. Therefore, it has to be considered during well

planning.

4.1 Kick tolerance calculations.

In this chapter kick tolerance calculations performed within the confines of this thesis research

can be observed.

4.1.1 Kick tolerance calculations for 1st kick depth scenarios.

For 1st kick depth the following data was used:

Table 1.

Data Unit CwD 9 5/8"

Conventional 9 5/8"

Dbit in 12 1/4 12 1/4 MW ppg 9.22 9.22

TVDkick ft 2132 2132 Shoe TVD ft 489 489

FPG psi/ft 0.433 0.433 Gas grad psi/ft 0.102 0.102

Temp grad F°/ft 0.02 0.02

36

At Figure 19, well profile for theoretical well’s first kick depth can be observed.

Figure 19. Theoretical well profile for first kick depth. (Self-made picture)

4.1.1.1 CwD calculations.

First, mud hydrostatic pressure at the kick depth has to be calculated by Eq. 4-1:

𝑝𝑝ℎ𝑦𝑦𝑀𝑀𝑂𝑂𝑦𝑦𝑎𝑎𝑓𝑓𝑎𝑎𝑓𝑓𝑝𝑝𝑦𝑦 = 𝑀𝑀𝑀𝑀 ∗ 0.052 ∗ 𝑇𝑇𝑇𝑇𝑇𝑇 Eq. 4-1

𝑝𝑝ℎ𝑦𝑦𝑀𝑀𝑂𝑂𝑦𝑦𝑎𝑎𝑓𝑓𝑎𝑎𝑓𝑓𝑝𝑝𝑦𝑦 = 9.22 ∗ 0.052 ∗ 2132 = 1022.16 𝑝𝑝𝑅𝑅𝑅𝑅

37

According to the fact that recommended annular velocity in order to maintain hole cleaning is

150 – 200 ft/min, annular velocity of 175 ft/min was assumed. After that well flowrate can be

calculated by Eq. 4-2:

𝑄𝑄 = 𝑇𝑇∗(𝑂𝑂ℎ2−𝑂𝑂𝑝𝑝2)

1029.4 Eq. 4-2

Where: Q-flowrate (bbl/min)

V-annular velocity (ft/s)

Dh-hole diameter (inch)

Dp-drill string diameter (inch)

𝑄𝑄 =175 ∗ (12 1

42− 9 5

82

)1029.4

= 𝟗𝟗.𝟕𝟕𝟕𝟕 𝑏𝑏𝑏𝑏𝑏𝑏/𝑚𝑚𝑅𝑅𝑚𝑚

Then APL (annular pressure loss for kick depth) is calculated by Eq. 4-3:

𝐴𝐴𝑃𝑃𝐴𝐴 = (1.4327∗10−7)∗𝑀𝑀𝑊𝑊∗𝐿𝐿∗𝑇𝑇2

𝑂𝑂ℎ−𝑂𝑂𝑝𝑝 Eq. 4-3

Where: MW-mud weight (ppg)

L-TVD true vertical depth (ft)

V-annular velocity (ft/s)

𝐴𝐴𝑃𝑃𝐴𝐴 =(1.4327 ∗ 10−7) ∗ 9.22 ∗ 2132 ∗ 1752

12 14 − 9 5

8= 𝟑𝟑𝟑𝟑.𝟖𝟖𝟖𝟖 𝑝𝑝𝑅𝑅𝑅𝑅

38

After APL is calculated BHP can be determined for kick depth by Eq 4-4:

𝐵𝐵𝑃𝑃𝑃𝑃 = 𝑝𝑝ℎ𝑦𝑦𝑀𝑀𝑂𝑂𝑦𝑦𝑎𝑎𝑓𝑓𝑎𝑎𝑓𝑓𝑝𝑝𝑦𝑦 + 𝐴𝐴𝑃𝑃𝐴𝐴 Eq. 4-4

𝐵𝐵𝑃𝑃𝑃𝑃 = 1022.16 + 32.85 ≈ 𝟏𝟏𝟏𝟏𝟖𝟖𝟖𝟖 𝑝𝑝𝑅𝑅𝑅𝑅

According to normal formation pressure gradient estimated formation pressure for kick depth is


𝑝𝑝𝑓𝑓𝑦𝑦𝑂𝑂𝑓𝑓𝑎𝑎𝑓𝑓𝑝𝑝𝑦𝑦𝑎𝑎 = 𝐹𝐹𝑃𝑃𝐹𝐹 ∗ 𝑇𝑇𝑇𝑇𝑇𝑇 = 𝟗𝟗𝟑𝟑𝟑𝟑.𝟏𝟏𝟖𝟖 𝑝𝑝𝑅𝑅𝑅𝑅 Eq.4-5

Fracture gradient for previous casing shoe was estimated by use of Hubbert and Willis method

(Eq. 4-6):

𝐹𝐹𝐹𝐹 = � 𝜈𝜈1−𝜈𝜈

� ∗ �𝜎𝜎𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑎𝑎𝑜𝑜𝑜𝑜𝑜𝑜𝑎𝑎−𝑝𝑝𝑓𝑓𝑂𝑂

� + 𝑝𝑝𝑓𝑓𝑂𝑂

Eq. 4-6

Where: ν – Poisson ratio = 0.4

𝜎𝜎𝑦𝑦𝑜𝑜𝑁𝑁𝑂𝑂𝑜𝑜𝑎𝑎𝑂𝑂𝑀𝑀𝑁𝑁𝑎𝑎 – overburden stress (gradient assumed 1psi/ft)

𝑝𝑝𝑓𝑓 – formation pressure

D – depth

𝐹𝐹𝐹𝐹 = �0.4

1 − 0.4� ∗ �

1 ∗ 489 − 0.433 ∗ 489489

� +0.433 ∗ 489

489= 𝟏𝟏.𝟖𝟖𝟏𝟏𝟏𝟏

𝑝𝑝𝑅𝑅𝑅𝑅𝑓𝑓𝑓𝑓

= 𝟏𝟏𝟖𝟖.𝟕𝟕 𝑝𝑝𝑝𝑝𝑔𝑔

Kick tolerance calculation begins with calculating maximum kick height at casing shoe by use

of Eq. 4-7:

𝑃𝑃 = 0.052∗𝜌𝜌𝑚𝑚𝑎𝑎𝑜𝑜∗(𝑇𝑇𝑂𝑂−𝐶𝐶𝑆𝑆𝑂𝑂)+𝐹𝐹𝐹𝐹∗𝐶𝐶𝑆𝑆𝑂𝑂∗0.052−𝑝𝑝𝑓𝑓0.052∗𝜌𝜌𝑚𝑚𝑎𝑎𝑜𝑜−𝐹𝐹

Eq. 4-7

Where: H= maximum kick height at casing shoe

39

𝜌𝜌𝑓𝑓𝑎𝑎𝑀𝑀 - maximum mud weight for next hole section, ppg

TD = next hole total depth, ft

CSD = previous casing setting depth, ft

FG = fracture gradient at the casing shoe in ppg

𝑝𝑝𝑓𝑓 = pore pressure at next TD in psi

G = gradient of gas in psi/ft

𝑃𝑃 =0.052 ∗ 9.22 ∗ (2621 − 489) + 15.6 ∗ 489 ∗ 0.052 − 0.433 ∗ 2621

0.052 ∗ 9.22 − 0.102= 𝟕𝟕𝟖𝟖𝟑𝟑.𝟑𝟑 𝑓𝑓𝑓𝑓

Maximum kick volume at casing shoe can be calculated by Eq. 4-8:

𝑇𝑇 = 𝐼𝐼𝑎𝑎 ∗ 𝑃𝑃 Eq. 4-8

Where: 𝐼𝐼𝑎𝑎=annular capacity, bbl/ft

H = height of gas bubble, ft

𝐼𝐼𝑎𝑎 = 𝑂𝑂ℎ2−𝑂𝑂𝑝𝑝2

1029.4 𝐼𝐼𝑎𝑎 =

(12142

)−(9582

)

1029.4= 𝟏𝟏.𝟏𝟏𝟖𝟖𝟖𝟖𝟖𝟖 𝑏𝑏𝑏𝑏𝑏𝑏/𝑓𝑓𝑓𝑓

Maximum influx volume at previous casing shoe is equal to:

𝑇𝑇1 = 0.0558 ∗ 752.3 = 𝟒𝟒𝟏𝟏.𝟗𝟗𝟕𝟕 𝑏𝑏𝑏𝑏𝑏𝑏

After that by using Boyle’s Law (Eq. 4-9) maximum influx volume at next TVD can be

calculated:

𝑆𝑆1∗𝑇𝑇1𝑇𝑇1

= 𝑆𝑆2∗𝑇𝑇2𝑇𝑇2

Eq. 4-9

Where T – temperature in Rankin will be:

40

𝑇𝑇1 = 60 + 0.02 ∗ 489 + 460 = 529 𝑅𝑅

𝑇𝑇2 = 60 + 0.02 ∗ 2621 + 460 = 572 𝑅𝑅

So, Boyle’s law will look like:

15.6 ∗ 0.052 ∗ 489 ∗ 41.97529

=0.433 ∗ 2621 ∗ 𝑇𝑇2

572

𝑇𝑇2 = 𝟏𝟏𝟖𝟖.𝟖𝟖𝟕𝟕 𝑏𝑏𝑏𝑏𝑏𝑏

The maximum allowable annular surface pressure (MAASP) is calculated by Eq. 4-10:

𝑀𝑀𝐴𝐴𝐴𝐴𝑆𝑆𝑃𝑃 = (𝐹𝐹𝐹𝐹 − 𝜌𝜌𝑓𝑓𝑎𝑎𝑀𝑀) ∗ 𝐼𝐼𝑆𝑆𝑇𝑇 ∗ 0.052 Eq. 4-10

For this section:

𝑀𝑀𝐴𝐴𝐴𝐴𝑆𝑆𝑃𝑃 = (15.6 − 9.22) ∗ 489 ∗ 0.052 = 𝟏𝟏𝟕𝟕𝟑𝟑.𝟑𝟑𝟑𝟑 𝑝𝑝𝑅𝑅𝑅𝑅

Figure 20. Kick tolerance graph for 1st kick depth CwD.

15.86

162.23

0

50

100

150

200

250

0 2 4 6 8 10 12 14 16 18

MA

ASP

, psi

Kick volume, bbl

Kick tolerance graph 2621ft CwD

41

4.1.1.2 Conventional drilling calculations.

For conventional drilling calculations 5” drill pipe was considered. According to the fact that

recommended annular velocity in order to maintain hole cleaning is 150 – 200 ft/min, annular

velocity of 175 ft/min was assumed. Because of diameter change, flowrate has to be recalculated

by Eq. 4-2:

𝑄𝑄 =175 ∗ (12 1

42− 52)

1029.4= 𝟑𝟑𝟏𝟏.𝟑𝟑𝟕𝟕 𝑏𝑏𝑏𝑏𝑏𝑏/𝑚𝑚𝑅𝑅𝑚𝑚

Then APL (annular pressure loss for kick depth) has to be recalculated by Eq. 4-3:

𝐴𝐴𝑃𝑃𝐴𝐴 =(1.4327 ∗ 10−7) ∗ 9.22 ∗ 2132 ∗ 1752

12 14 − 5

= 𝟏𝟏𝟏𝟏.𝟗𝟗 𝑝𝑝𝑅𝑅𝑅𝑅


𝐵𝐵𝑃𝑃𝑃𝑃 = 1022.16 + 11.9 ≈ 1034 𝑝𝑝𝑅𝑅𝑅𝑅

According to normal formation pressure gradient estimated formation pressure for kick depth

will be the same as in previous formation pressure calculation:

𝑝𝑝𝑓𝑓𝑦𝑦𝑂𝑂𝑓𝑓𝑎𝑎𝑓𝑓𝑝𝑝𝑦𝑦𝑎𝑎 = 𝟗𝟗𝟑𝟑𝟑𝟑.𝟏𝟏𝟖𝟖 𝒑𝒑𝒑𝒑𝒑𝒑

Maximum height at previous casing shoe will remain same, because it does not depend on well geometry:

𝑃𝑃 = 𝟕𝟕𝟖𝟖𝟑𝟑.𝟑𝟑 𝑓𝑓𝑓𝑓

Because of change in annular capacity, volume at previous casing shoe is recalculated by Eq. 4-8:


1029.4 𝐼𝐼𝑎𝑎 =

(12142

)−(52)

1029.4= 𝟏𝟏.𝟏𝟏𝟑𝟑𝟏𝟏𝟒𝟒 𝑏𝑏𝑏𝑏𝑏𝑏/𝑓𝑓𝑓𝑓

𝑇𝑇1 = 0.1214 ∗ 752.3 = 𝟗𝟗𝟏𝟏.𝟑𝟑𝟑𝟑 𝑏𝑏𝑏𝑏𝑏𝑏

42

Using Boyle’s law (Eq. 4-9):

𝑃𝑃1 ∗ 𝑇𝑇1𝑇𝑇1

=𝑃𝑃2 ∗ 𝑇𝑇2𝑇𝑇2


𝑇𝑇1 = 60 + 0.02 ∗ 489 + 460 = 529 𝑅𝑅

𝑇𝑇2 = 60 + 0.02 ∗ 2621 + 460 = 572 𝑅𝑅


15.6 ∗ 0.052 ∗ 489 ∗ 91.33529

=0.433 ∗ 2621 ∗ 𝑇𝑇2

572

𝑇𝑇2 = 𝟑𝟑𝟒𝟒.𝟖𝟖𝟏𝟏 𝑏𝑏𝑏𝑏𝑏𝑏

The maximum allowable drill pipe shut-in pressure (MAASP) is given by:

MAASP = (𝐹𝐹𝐹𝐹 − 𝜌𝜌𝑓𝑓𝑎𝑎𝑀𝑀) ∗ 𝐼𝐼𝑆𝑆𝑇𝑇 ∗ 0.052

For this section:

MAASP = (15.6 − 9.22) ∗ 489 ∗ 0.052 = 𝟏𝟏𝟕𝟕𝟑𝟑.𝟑𝟑𝟑𝟑 𝑝𝑝𝑅𝑅𝑅𝑅

Figure 21. Kick tolerance graph for 1st kick depth conventional.

34.51

162.23

0

50

100

150

200

250

0 5 10 15 20 25 30 35 40

MA

ASP

, psi

Kick volume, bbl

Kick tolerance graph 2621ft Conventional

43

4.1.2 Kick tolerance calculations for 2nd kick depth scenarios.

The well profile can be observed on Figure 21. For 2nd kick depth the following data was used:

Table 2.

4.1.2.1 CwD calculations.

First, mud hydrostatic pressure at the kick depth has to be calculated by Eq. 4-1:

𝑝𝑝ℎ𝑦𝑦𝑀𝑀𝑂𝑂𝑦𝑦𝑎𝑎𝑓𝑓𝑎𝑎𝑓𝑓𝑝𝑝𝑦𝑦 = 9.3 ∗ 0.052 ∗ 5589 = 𝟑𝟑𝟕𝟕𝟏𝟏𝟑𝟑.𝟖𝟖𝟒𝟒 𝑝𝑝𝑅𝑅𝑅𝑅

According to the fact that recommended annular velocity in order to maintain hole cleaning is

150 – 200 ft/min, annular velocity of 175 ft/min was assumed. After that well flowrate can be


𝑄𝑄 =175 ∗ (8 1

22− 72)

1029.4= 𝟑𝟑.𝟗𝟗𝟖𝟖 𝑏𝑏𝑏𝑏𝑏𝑏/𝑚𝑚𝑅𝑅𝑚𝑚

Then APL (annular pressure loss for kick depth) is calculated by Eq. 4-3:

𝐴𝐴𝑃𝑃𝐴𝐴 =(1.4327 ∗ 10−7) ∗ 𝑀𝑀𝑀𝑀 ∗ 𝐴𝐴 ∗ 𝑇𝑇2

𝑇𝑇ℎ − 𝑇𝑇𝑝𝑝


𝐵𝐵𝑃𝑃𝑃𝑃 = 2702.84 + 152 ≈ 𝟑𝟑𝟖𝟖𝟖𝟖𝟖𝟖 𝑝𝑝𝑅𝑅𝑅𝑅

Data Unit CwD 9 5/8" Conventional 9 5/8"

Dbit in 8 1/2 8 1/2 MW ppg 9.3 9.3

TVDkick ft 5589 5589 Shoe TVD ft 2621 2621

FPG psi/ft 0.433 0.433 Gas grad psi/ft 0.102 0.102

Temp grad F°/ft 0.02 0.02

44

Figure 22. Theoretical well profile for second kick depth. (Self-made picture)

According to normal formation pressure gradient estimated formation pressure for kick depth is


𝑝𝑝𝑓𝑓𝑦𝑦𝑂𝑂𝑓𝑓𝑎𝑎𝑓𝑓𝑝𝑝𝑦𝑦𝑎𝑎 = 𝐹𝐹𝑃𝑃𝐹𝐹 ∗ 𝑇𝑇𝑇𝑇𝑇𝑇 = 𝟑𝟑𝟒𝟒𝟑𝟑𝟏𝟏 𝑝𝑝𝑅𝑅𝑅𝑅

45

Fracture gradient for previous casing shoe was estimated by use of Hubbert and Willis method

(Eq. 4-6):

𝐹𝐹𝐹𝐹 = �0.4

1 − 0.4� ∗ �

1 ∗ 5589 − 0.433 ∗ 55895589

� +0.433 ∗ 5589

5589= 𝟏𝟏.𝟖𝟖𝟏𝟏𝟏𝟏

𝑝𝑝𝑅𝑅𝑅𝑅𝑓𝑓𝑓𝑓

= 𝟏𝟏𝟖𝟖.𝟕𝟕 𝑝𝑝𝑝𝑝𝑔𝑔

Kick tolerance calculation begins with calculating maximum kick height at casing shoe by use

of Eq. 4-7:

𝑃𝑃 =0.052 ∗ 9.3 ∗ (5964.5 − 2621.4) + 15.6 ∗ 2621.4 ∗ 0.052 − 0.433 ∗ 5964.5

0.052 ∗ 9.3 − 0.102= 𝟑𝟑𝟏𝟏𝟒𝟒𝟏𝟏.𝟑𝟑 𝑓𝑓𝑓𝑓

Maximum kick volume at casing shoe can be calculated by Eq. 4-8:


1029.4 𝐼𝐼𝑎𝑎 =

(8122

)−(72)

1029.4= 𝟏𝟏.𝟏𝟏𝟑𝟑𝟑𝟑𝟖𝟖𝟖𝟖 𝑏𝑏𝑏𝑏𝑏𝑏/𝑓𝑓𝑓𝑓

𝑇𝑇1 = 0.02258 ∗ 3041.3 = 𝟕𝟕𝟖𝟖.𝟕𝟕𝟕𝟕 𝑏𝑏𝑏𝑏𝑏𝑏





𝑇𝑇1 = 60 + 0.02 ∗ 2621 + 460 = 572 𝑅𝑅

𝑇𝑇2 = 60 + 0.02 ∗ 5964.5 + 460 = 639 𝑅𝑅


15.6 ∗ 0.052 ∗ 2621 ∗ 68.67572

=0.433 ∗ 5964.5 ∗ 𝑇𝑇2

639

𝑇𝑇2 = 𝟕𝟕𝟑𝟑.𝟏𝟏𝟖𝟖 𝑏𝑏𝑏𝑏𝑏𝑏



46

For this section:

𝑀𝑀𝐴𝐴𝐴𝐴𝑆𝑆𝑃𝑃 = (15.6 − 9.3) ∗ 2621 ∗ 0.052 = 𝟖𝟖𝟖𝟖𝟖𝟖.𝟕𝟕𝟒𝟒 𝑝𝑝𝑅𝑅𝑅𝑅

Figure 23. Kick tolerance graph for 2nd kick depth CwD.

4.1.2.2 Conventional drilling calculations.

For conventional drilling calculations 5” drill pipe was considered. According to the fact that

recommended annular velocity in order to maintain hole cleaning is 150 – 200 ft/min, annular

velocity of 175 ft/min was assumed. Because of diameter change, flowrate has to be recalculated

by Eq. 4-2:

𝑄𝑄 =175 ∗ (8 1

22− 52)

1029.4= 𝟖𝟖.𝟏𝟏𝟑𝟑 𝑏𝑏𝑏𝑏𝑏𝑏/𝑚𝑚𝑅𝑅𝑚𝑚

Then APL (annular pressure loss for kick depth) has to be recalculated by Eq. 4-3:

𝐴𝐴𝑃𝑃𝐴𝐴 =(1.4327 ∗ 10−7) ∗ 9.3 ∗ 5589 ∗ 1752

8 12 − 5

= 𝟕𝟕𝟖𝟖.𝟏𝟏𝟕𝟕 𝑝𝑝𝑅𝑅𝑅𝑅

63.15

858.64

0

100

200

300

400

500

600

700

800

900

1000

0 10 20 30 40 50 60 70 80 90 100

MA

ASP

, psi

Kick volume, bbl

Kick tolerance graph 5964.5 ft CwD

47


𝐵𝐵𝑃𝑃𝑃𝑃 = 2702.84 + 65.16 ≈ 𝟑𝟑𝟕𝟕𝟕𝟕𝟖𝟖 𝑝𝑝𝑅𝑅𝑅𝑅

According to normal formation pressure gradient estimated formation pressure for kick depth

will be the same as in previous formation pressure calculation:

𝑝𝑝𝑓𝑓𝑦𝑦𝑂𝑂𝑓𝑓𝑎𝑎𝑓𝑓𝑝𝑝𝑦𝑦𝑎𝑎 = 𝐹𝐹𝑃𝑃𝐹𝐹 ∗ 𝑇𝑇𝑇𝑇𝑇𝑇 = 𝟑𝟑𝟒𝟒𝟑𝟑𝟏𝟏 𝑝𝑝𝑅𝑅𝑅𝑅

Maximum height at previous casing shoe will remain same, because it does not depend on well geometry:

𝑃𝑃 = 𝟑𝟑𝟏𝟏𝟒𝟒𝟏𝟏.𝟑𝟑 𝑓𝑓𝑓𝑓

Because of change in annular capacity, volume at previous casing shoe is recalculated by Eq. 4-8:


1029.4 𝐼𝐼𝑎𝑎 =

(8122

)−(52)

1029.4= 𝟏𝟏.𝟏𝟏𝟒𝟒𝟖𝟖𝟗𝟗 𝑏𝑏𝑏𝑏𝑏𝑏/𝑓𝑓𝑓𝑓.

𝑇𝑇1 = 0.0459 ∗ 3041.3 = 139.6 𝑏𝑏𝑏𝑏𝑏𝑏





𝑇𝑇1 = 60 + 0.02 ∗ 2621 + 460 = 572 𝑅𝑅

𝑇𝑇2 = 60 + 0.02 ∗ 5964.5 + 460 = 639 𝑅𝑅


15.6 ∗ 0.052 ∗ 2621 ∗ 139.6572

=0.433 ∗ 5964.5 ∗ 𝑇𝑇2

639

𝑇𝑇2 = 𝟏𝟏𝟑𝟑𝟖𝟖.𝟑𝟑𝟖𝟖 𝑏𝑏𝑏𝑏𝑏𝑏



48

For this section:

𝑀𝑀𝐴𝐴𝐴𝐴𝑆𝑆𝑃𝑃 = (15.6 − 9.3) ∗ 2621 ∗ 0.052 = 𝟖𝟖𝟖𝟖𝟖𝟖.𝟕𝟕𝟒𝟒 𝑝𝑝𝑅𝑅𝑅𝑅

Figure 24. Kick tolerance graph for 2nd kick depth conventional.

128.38

858.64

0

100

200

300

400

500

600

700

800

900

1000

0 20 40 60 80 100 120 140

MA

ASP

, psi

Kick volume, bbl

Kick tolerance graph 5964.5 ft Conventional

49

4.2 Influx inflow rate and available well shut-in time calculations.

One more important parameter is influx inflow rate and it can be calculated by using Eq. 4-10:

𝑄𝑄 = 0.007∗𝑓𝑓𝑀𝑀∗∆𝑝𝑝∗𝐿𝐿

𝜇𝜇∗ln𝑅𝑅𝑜𝑜𝑅𝑅𝑤𝑤∗1440

Eq. 4-10

Where: Q = inflow rate, bbl/min

md= permeability, mD

Dp = differential pressure

L = length of section drilled in overbalanced formation, ft

µ = gas viscosity, centipoise

Re = radius of drainage, ft

Rw = radius of wellbore, ft

After kick tolerance is determined, 5 bbl. because of pit gain alarm setting and 1 bbl. because of

safety reasons have to be subtracted from it. After that estimated shut-in time limit can be

calculated.

For creating Table 3 and Table 4 data from 9 5/8” section was used. At Table 3, created for

CwD application scenario, one can observe influx inflow rate and well shut-in time available

for corresponding length drilled in overpressured zone. It can be seen that in case of CwD, if

length drilled in overpressured zone reaches 20 ft., shut-in time available is barely enough to

shut-in the well properly. On the contrary, at Table 4, created for conventional drilling

application scenario, it is displayed that even in case if 20 ft. of overpressured formation has

been drilled, there is still enough time for proper shut-in. So, the conclusion can be drawn, that

early kick detection in case of CwD application is even more important than in cases of

conventional drilling being performed. Therefore, pit gain alarm setting is recommended to be

set as low as possible.

50

Table 3. 9 5/8” section, CwD.

Table 4. 9 5/8” section, conventional.

Length drilled Inflow rate

Closing time

available

Length drilled

Inflow rate

Closing time available

1 0.244 40.43 11 2.683 3.68 2 0.488 20.21 12 2.927 3.37 3 0.732 13.48 13 3.171 3.11 4 0.976 10.11 14 3.414 2.89 5 1.219 8.09 15 3.658 2.70 6 1.463 6.74 16 3.902 2.53 7 1.707 5.78 17 4.146 2.38 8 1.951 5.05 18 4.390 2.25 9 2.195 4.49 19 4.634 2.13

10 2.439 4.04 20 4.878 2.02

Length drilled

Inflow rate


Length drilled

Inflow rate


1 0.244 116.90 11 2.683 10.63 2 0.488 58.45 12 2.927 9.74 3 0.732 38.97 13 3.171 8.99 4 0.976 29.22 14 3.414 8.35 5 1.219 23.38 15 3.658 7.79 6 1.463 19.48 16 3.902 7.31 7 1.707 16.70 17 4.146 6.88 8 1.951 14.61 18 4.390 6.49 9 2.195 12.99 19 4.634 6.15

10 2.439 11.69 20 4.878 5.84

51

4.3 Summary of example well calculations.

In the Table 5, overall summary of example well calculations can be observed. It can be seen,

that the main difference between drilling with casing and conventional drilling methods is

annulus capacity. This difference is very noticeable in case of 9 5/8” casing section, because of

the fact, that the larger diameter casing section is being drilled, the difference will be more

noticeable. For CwD this value is 0.0558 bbl/ft compared to 0.1214 bbl/ ft for conventional

drilling method, which is 2.17 times difference. Smaller annulus capacity causes higher annular

pressure losses, 32.85 psi for CwD compared to 11.9 psi for conventional drilling.

Main differences between CwD and conventional drilling in terms of well control are kick

tolerance and maximum allowable well shut-in time. As it can be seen in the Table 5, in case of

conventionally drilled 9 5/8” section maximum allowable kick volume at the bottomhole is

34.51 bbl. compared to 15.86 bbl. for CwD drilled. For conventionally drilled 7” section

maximum allowable kick volume at bottomhole is 128.38 bbl. compared to 62.15 bbl. for CwD

drilled. So, the conclusion can be made, that maximum allowable kick volume for sections

drilled by CwD is more than twice less than for same sections drilled utilizing conventional drill

pipes. Which means that early detection of the kick is crucial part of successful well control

procedure, therefore the pit gain level alarm is recommended to be set to the lowest possible

value.

Depending on influx inflow rate and kick tolerance calculation results, maximum allowable well

shut-in time can be determined. In case of CwD drilled 9 5/8” section, if 20 ft. of overpressured

formation was drilled, kick inflow rate is 4.878 bbl/min. So, there are only 2.02 minutes to shut-

in the well after the pit level alarm, which is not suitable. In such cases it is recommended to

position previous casing shoe deeper. For other cases displayed in Table 5, closing time is

enough for proper well shut-in procedure. Complete example well profile can be observed on

Figure 25.

52

Table 5. Summary of example well calculations.

Data Unit CwD 9 5/8"

Conventional 9 5/8" CwD 7" Conventional

7" Dbit in 12 1/4 12 1/4 8 1/2 8 1/2 MW ppg 9.22 9.22 9.3 9.3

TVDkick ft 2132 2132 5589 5589 Shoe TVD ft 489 489 2621 2621

FPG psi/ft 0.433 0.433 0.433 0.433 Gas gradient psi/ft 0.102 0.102 0.102 0.102

Temp gradient F°/ft 0.02 0.02 0.02 0.02 Phydr psi 1022.16 1022.16 2702.84 2702.84

Q bbl/min 9.76 22.26 3.95 8.03 APL psi 32.85 11.9 152 65.16 BHP psi 1055.01 1034 2855 2768 Pform psi 923.15 923.15 2420 2420

Overbalance psi 131.86 110.85 435 348 FG ppg 15.6 15.6 15.6 15.6

Max.kick length (H) ft 752.3 752.3 3041.3 3041.3 Annulus capacity bbl/ft 0.0558 0.1214 0.02258 0.0459 Max. kick volume

at shoe (V1) bbl 41.97 91.33 68.67 139.6

Max. kick volume at bottom hole (V2) bbl 15.86 34.51 63.15 128.38

MAASP psi 162.23 162.23 858.64 858.64 Max. kick volume with 1 bbl safety bbl 14.86 33.51 62.15 127.38

Pit level alarm bbl 5 5 5 5 Max allowable kick

after alarm bbl 9.86 28.51 57.15 122.38

Overpressure at kick psi 200 200 200 200

Length drilled in overpressure

before detection ft 20 20 20 20

k (permeability) mD 500 500 500 500 µ gas viscosity cP 0.3 0.3 0.3 0.3

Re-drainage radius ft 400 400 400 400 Rw-wellbore radius ft 0.521 0.521 0.354 0.354

Qkick-inflow rate bbl/min 4.878 4.878 4.610 4.610 Closing time min 2.02 5.84 12.40 26.55 Applicable Y/N N Y Y Y

53

Figure 25. Complete example well profile. (Self-made picture)

54

5. Conclusion.

Kick tolerance and maximum well shut-in time allowable were calculated for an example well.

Four different kick scenarios for two different TVDs were analyzed. The conclusion can be

made, that there is a huge difference in kick tolerance calculation results between drilling with

casing and with conventional drill pipes. For 9 5/8” CwD scenario at 2132 ft. kick TVD

maximum allowable kick volume is only 45.95 % of the same in case of conventional drill pipe

used and for 7” CwD scenario at 5589 ft. kick TVD maximum allowable kick volume is only

49.18 % of the same in case of conventional drill pipe used. Also, due to smaller annular

capacity, in case if kick is gas, in will expand faster in terms of height of the bubble which can

result in very high surface casing pressures and MAASP value can be reached very fast. One

more important conclusion that can be made, is that in case of 20 feet or more of overpressured

formation has been drilled, if previous casing shoe is at shallow depth there may be not enough

time for proper well shut-in procedure. So, in such cases, it’s recommended to place previous

casing shoe deeper.

55

6. References

1. Kate Mantle, Schlumberger, Oilfield Review, 2014

2. Warren, Casing While Drilling Chapter, SPE Advanced Drilling Engineering Textbook,

Tescocorp, Houston, Texas, 2004

3. Using Casing to Drill Directional Wells, Kyle R. Fontenot, Bob Strickler, T. Warren,

Published 2005

4. New Techniques Aimed at Facilitating Application of Directional Casing Drilling in

Ecuador, H. Ramírez; M. Breton; A. P. Lougon; R. Rodriguez; M. Barreto; J. Chancay, SPE-

177070-MS

5. Utilizing Managed Pressure Casing Drilling in Depleted Reservoir Zones, Tarje Livik

Naterstad, 2014

6. New Directional Drilling with Liner Systems Allows Logging and Directional Control

While Getting Casing Across Trouble Zones, A. Srinivasan, et. al., 2010

7. Review of casing while drilling technology, January 2016, Podzemni Radovi,

2016(29):11-32, DOI:10.5937/podrad1629011P

8. Courtesy of Nabors

9. Dowell, J.D., Drilling with Casing overview, Chevron internal report, Houston, Texas,

2007

10. Directional Drilling with Casing, Tommy Warren, SPE, Bruce Houtchens, SPE, and Garret

Madell, SPE, Tesco Corp. 2003

11. Dowell J. D., Drilling with Casing overview, Chevron internal report, Texas, 2007

12. Feasibility studies of combining drilling with casing and expandable casing, Hendry

Shen MSc, 2007

13. Karimi, et al., 2011

56

14. Moellendick, et al.,2011

15. Courtesy of Schlumberger LTD.

16. Skalle, 2012

17. Pritchard, 2010

18. Carlsen, et al., 2000

19. Dipal Patel, et al., 2019

20. Private conversation with SOCAR AQS drilling engineer.

21. Emailing C., et.al., Blowout and Well Control Handbook, 2017

22. Ron Baker, et. al., Practical Well Control, 1998

23. https://www.drillingmanual.com/2017/12/methods-of-well-control-drillers-

method.html

24. https://www.drillingmanual.com/2017/12/the-wait-and-weight-method.html

25. Baker Hughes, External presentation, 2004

26. Federer, et.al., 2017

https://www.drillingmanual.com/2017/12/methods-of-well-control-drillers-method.html

https://www.drillingmanual.com/2017/12/methods-of-well-control-drillers-method.html

https://www.drillingmanual.com/2017/12/the-wait-and-weight-method.html

Well Control Planning for Casing Drilling (CwD) Wells ...

Documents

Transcript of Well Control Planning for Casing Drilling (CwD) Wells ...