A PROJECT ON

A STUDY ON COMPARATIVE STUDY BETWEEN OVERBALANCED AND UNDERBALANCED OIL DRILLINGS

MASTER OF TECHNOLOGY

IN

PETROLEUM ENGINEERING

Submitted By

GUDAPATI JHANSI14A91D0806

Under the Esteemed Guidance of

Shri VINAYM.Tech.,

Assistant Professor

Department of Petroleum Engineering

ADITYA ENGINEERING COLLEGEApproved by AICTE, Permanently affiliated to JNTUK & NBA Accredited,

Recognised by UGC under Section 2(f) & 12(B) of the UGC act 1956.Aditya Nagar, ADB Road, Surampalem, East Godavari District

2014 - 2017

ADITYA ENGINEERING COLLEGEApproved by AICTE, Permanently affiliated to JNTUK & NBA Accredited,

Recognised by UGC under Section 2(f) & 12(B) of the UGC act 1956.Aditya Nagar, ADB Road, Surampalem, East Godavari District

2014 - 2017

DEPARTMENT OF PETROLEUM ENGINEERING

CERTIFICATE

This is to certify that the thesis entitled “A STUDY ON COMPARATIVE STUDY

BETWEEN OVERBALANCED AND UNDERBALANCED OIL DRILLING METHODS”

is being submitted by Ms. GUDAPATI JHANSI (14A91D0806)in the partial fulfilment of the

requirements for the award of degree of Master of Technology in Petroleum Engineeringduring

the academic year 2014 – 2017, in Aditya Engineering College, Surampalem, Affiliated to

Jawaharlal Nehru Technological University Kakinada is a record of bonafied work carried out by

her under my guidance and supervision.

The results embodied in this Project report have not been submitted to any other

University or Institute for the award of any degree or diploma.

PROJECT GUIDE HEAD OF THE DEPARTMENT

Shri. VINAY Dr. R. Giri Prasad

External Examiner

DECLARATION

I hereby declare that that the project work titled “A STUDY ON COMPARATIVE STUDY

BETWEEN OVERBALANCED AND UNDERBALANCED OIL DRILLING METHODS”

has been carried out by me and this work has been submitted to Aditya Engineering College,

Surampalem, Affiliated to JNTUK in partial fulfilment of the requirements for the award of the

degree of Master of Technology in Petroleum Engineering.

I further declare that this project work has not been submitted in full or part for the award of any

other degree to any other educational institution.

GUDAPATI JHANSI

(14A91D0806)

ACKNOWLEDGEMENT

I would like to acknowledge the contributions to the following groups and individuals to the

development of my project.

I am taking great pleasure in thanking Prof. M.SREENIVASA REDDY, Principal and Prof.

V.SRINIVASA RAO, Vice Principal, Aditya Engineering College, Surampalem, for extending

their utmost support and encouragement..

I wish to express profound sense of gratitude to Dr. R.GIRI PRASAD, Professor and Head of

Department of Petroleum Engineering, who has the attitude and a substance of genius which

helped me in the accomplishment of my project.

I am deeply indebted to my guide Shri. VINAY, Sr. Assistant Professor, Dept. of Petroleum

Engineering, for his valuable suggestions, ever willing precious guidance and for being the

inspiring source throughout the fulfilment of this work.

I would like to express the deepest appreciation to all the Faculty members and Non Teaching

Staff of the Department of Petroleum Engineering for their encouragement and valuable

suggestions for completion of the project.

My Family Members and Friends receive my deepest gratitude and love for their support

throughout my academic year.

GUDAPATI JHANSI

(14A91D0806)

COMPARATIVE STUDY BETWEEN OVERBALANCED AND

UNDERBALANCED OIL DRILLING METHODS

ABSTRACT

The procedure used worldwide although drilling is acknowledged as overbalanced drilling.

Which is well-defined as the drilling process where the hydrostatic pressure used go above the

formation pressure. This is done with the main determination of “killing” the well. However,

there are frequent problems that go together with overbalanced drilling. Such complications are

difference pipe sticking, loss of movement, formation destruction and other problems. A

moderately new procedure was introduced, identified as underbalanced drilling, where the well is

being drilled with a hydrostatic pressure a smaller amount than that of the formation. Accurate

and proper execution of such technique excludes problems accompanying with overbalanced

drilling. More exactly so, underbalanced drilling resolves the problems of formation impairment,

difference pressure sticking and loss of rotation. On the other hand, underbalanced drilling has its

own problems as well. Furthermore, underbalanced drilling increases the rate of saturation and

provides other uses discussed in this project. The objective of this paper was to compare

between overbalanced and underbalanced drilling and establish which method is most suitable in

all aspects. Finally, it can be unwavering that UBD provides lower drilling costs, increased rate

of penetration (ROP) and less holedifficults when it was equated to overbalanced drilling of the

same formations.

Table of ContentsUnder the Esteemed Guidance of..............................................................................................................1

Shri VINAY M.Tech.,......................................................................................................................................1

Assistant Professor.....................................................................................................................................1

COMPARATIVE STUDY BETWEEN OVERBALANCED AND UNDERBALANCED OIL DRILLING METHODS................................................................................................................................5

ABSTRACT...................................................................................................................................................5

CHAPTER 1:.................................................................................................................................................9

INTRODUCTION.........................................................................................................................................9

1.1 Background study:...............................................................................................................................9

1.2 Overbalance Drilling Operation:........................................................................................................10

1.3 Underbalance Drilling Operation:......................................................................................................12

1.4 Underbalance Gases...........................................................................................................................14

1.5 Underbalance Techniques..................................................................................................................15

1.6 Statement of problem.........................................................................................................................16

1.7 Aims and Objectives..........................................................................................................................16

1.8 Scope and Limitation.........................................................................................................................17

1.9 Methodology......................................................................................................................................17

CHAPTER 2:...............................................................................................................................................18

LITERATURE REVIEW............................................................................................................................18

2.1 HISTORICAL OVERVIEW OF DRILLING IN THE OIL INDUSTRY...................................18

2.2 THE EMERGENCE OF DRILLING TECHNIQUES................................................................20

2.3 WELL SELECTION....................................................................................................................23

2.4 KINDS OF UNDERBALANCED DRILLING...........................................................................24

2.5 Case Study of an Underbalanced Drilling Operation in East Asia..............................................25

CHAPTER 3:...............................................................................................................................................27

METHODOLOGY......................................................................................................................................27

3.1 REVIEW OF THE DIFFRENCES BETWEEN OVERBALANCE AND UNDERBALANCE DRILLING...............................................................................................................................................27

3.2 COMPARATIVE ANALYSIS BETWEEN UNDERBALANCED AND CONVENTIONAL OVERBALANCED DRILLING IN THE GULF OF SUEZ USING A DRILLING SIMULATOR.....28

3.2.1 Extracted Data......................................................................................................................29

3.2.2 INTERPRETATION OF RESULTS...................................................................................30

3.2.3 ADVANTAGES OF UNDERBALANCED DRILLING OVER OVERBALANCE.........37

DRILLING...........................................................................................................................................37

3.2.4 DISADVANTAGES OF UBD............................................................................................39

CHAPTER 4:...............................................................................................................................................41

ANALYSIS..................................................................................................................................................41

4.1 LABORATORY SCREENING TECHNIQUES.........................................................................41

4.1.1 UNDERBALANCED LABORATORY EVALUATION...................................................41

4.1.2 OVERBALANCED LABORATORY EVALUATION......................................................42

4.2 TYPES OF RESERVOIRS SUITABLE FOR UNDERBALANCED DRILLING....................43

4.3 COMMON MECHANISMS OF FORMATION DAMAGE DURING OVERBALANCED AND UNDERBALANCED DRILLING OPERATIONS.......................................................................45

4.4 SURFACE EQUIPMENT REQUIREMENTS............................................................................47

CHAPTER 5:...............................................................................................................................................49

CONCLUSION AND RECOMMENDATION...........................................................................................49

5.1 CONCLUSION AND RECOMMENDATION...........................................................................49

5.1.1 CONCLUSION....................................................................................................................49

5.1.2 RECOMMENDATION.......................................................................................................50

REFERENCES............................................................................................................................................51

LIST OF FIGURES

Figure 1.1 : Conventional overbalance drilling.............................................................................................3

Figure 1.2 : Underbalanced Drilling..............................................................................................................5

Figure 1.3 : Gas injection via parasite string.................................................................................................7

Figure 3.1: underbalanced drilling through zone 1......................................................................................22

Figure 3.2 : Underbalanced drilling through zone 1 (progressing)..............................................................23

Figure 3.3 : Underbalanced drilling through zone1 (progressing)...............................................................23

Figure 3.4 : Underbalanced drilling through zone 2 (the underbalanced conditions have been

compromised)..............................................................................................................................................25

Figure 3.5 : Overbalanced drilling, zone 1 (progressing)............................................................................26

Figure 3.6 : Overbalanced drilling through zone 2 (progressing)................................................................27

Figure 4.1 : Typical surface equipment for UBD operation........................................................................40

CHAPTER 1:

INTRODUCTION

1.1 Background study:

The main determination of drillinghorizontal or vertical wells is to produce systematic

recoverable oil at lowest cost. Conventionally, the drilling fluid has larger than the pressure in

the formation when the wells have been drilled overbalance with the hydrostatic pressure. With

the moving degree of harshness when the drilled wells has with overbalance are topic to

formation destruction happened Unfortunately,its depending upon the drilling circumstances.

This is mainly due to the invasion of drilling fluids throughout drilling operations. The formation

weakening or skin due to drilling fluid incursion around the well bore reduces well productivity.

This is especially true for wells completed either open hole or with positioned liner due to the

difficulty to carry out any stimulation job to improveformation damage problems.

Nowadays, horizontal wells are preferred over vertical wells because they offer a net

productivity augmentation as well as an increase of the contact area with the reservoir. However,

formation mutilation is more critical to horizontal wells because these wells have such long

exposed interval that stimulation jobs are not effective and feasible.

Drilling operation is considered as the primary initiator of formation weakening as virgin

formation comes first time in contact with aexternal fluid, i.e. drilling mud, which invades the

formation and masses the pores around the well bore. Although drilling fluids are presently being

designed in such a way to minimize solid and fluid invasion into the formation.

In this project we will look at some comparative analysis between two methods of operating the

drilling; the usual method of drilling benefits (DB) and the low-pressure method of drilling

(UBD).

1.2 Operation drilling on rolling:

They are placed are many explanations for a conventional drilling operation being overweight

are generally known as conventional drilling. These characteristics are classified design the mud

used for drilling operations overweight.

The amount of pressure (or force per unit area) in the wellbore greater than the fluid pressure in

the layer is also regarded as an imbalance. This excess pressure is required to prevent reservoir

fluids (oil, gas, water) from entering the wellbore. However, an excess of the balance can

significantly slow the drilling process by effectively strengthening the near-wellbore rock and

removal of cuttings at the drill bit.

In conventional drilling unbalancing of the hydrostatic pressure of drilling fluid in the wellbore

designed to exceed the pressure of the hydrocarbon fluids in the formation. As in the opening

pressure higher than the fluid pressure in the rock, the drilling fluid may be lost into the

formation. These losses cause damage near the wellbore area, which leads to a decrease in

production, experience shows that even brief exposure to unbalance conditions can seriously

affect the well productivity.

When added together, high boost pressure in combination with poor drilling mud properties can

cause differential sticking problems in which the drill pipe is pressed against the borehole wall,

and as a result, the tube attached to the wall. Since the layer of pressure changes from one

formation to another, while the slurry is relatively constant density, preference varies from one

zone to

another. (Schlumberger Oilfield Glossary, 2014)

Image 1.1 illustrates operation unbalance drilling. As we can see, the drilling fluid circulates that

clog pores, which makes drilling thin Transfer and invade training.

A simple illustration of this equation for the drilling mode may be defined as:

Pm ˃ Pf

Figure 1.1 : Conventional overbalance drilling

1.3 Underbalance Drilling Operation:

A growing number of depleted reservoirs around the world and a growing need for more

efficient recovery of hydrocarbons forced oil and gas, to continuously improve its drilling

technology. Currently, the combination of drilling techniques that have been conceptualized

more than 100 years ago, with the latest technological innovations over the specialized drilling

techniques. These methods, if properly designed and implemented, allow to drill wells more

economically, safely and successfully in almost any given environment. One such technique is

called underbalanced drilling (UBD). Unbalanced drilling (UBD) is defined as the practice of

drilling wells with fluid gradient less than the natural gradient of the well layer. It differs from

the normal drilling pressure circulating in the lower level than the pressure, by this means

allowing the well to flow while drilling. Besides minimizing flow losses and increase the rate of

penetration, this method is widely accepted to minimize the damage caused by the invasion of

drilling fluid to the formation. UBD in many applications, additional benefits by reducing

drilling time, the longer the life of the bit and the early detection and dynamic tests of the

productive intervals during drilling obtained. It is important to maintain a low balance at any

time, if you want to minimize the damage layer. technology of drilling underbalanced is valuable

to minimize the problems associated with the invasion of methods of formation. Since most of

the hydrocarbons is currently in existing fields and vise exhaustion or complex, low quality

deposits, economical use of UBD is becoming increasingly popular. The majority of drilling

applications depression today are produced through the use of flexible piping systems. Forty

percent of all land wells drilled in 2000 were held in the depression. The joint sectoral projects

currently underway off the coast of Brazil, is likely to change the practice of regular applications

of offshore drilling.

"Little balanced drilling technology could save the industry millions of dollars to increase

the recovered oil for a short period of time. "

Underbalanced drilling, or UBD:

Whether the process is used for drilling oil and gas wells, wherein the pressure in the blast

furnace is maintained fluid in the wellbore, which rotates the pressure lower. Since the hole is

rotated, the formal fluid flows into the wellbore and at the surface. This is the usual situation

when the suction pressure is maintained at a pressure above the layer for preventing liquid in the

cavity. In such a conventional "excessive" liquid invasion, the invasion is seen as a blow, and if

the depression does not close, can cause drainage, dangerous situation. Underwater drilling on

the surface of "rotating head" - basically a coil which redirects the fluid in the separator, allowing

the cord continues to rotate, thereby ensuring safety.

Similarly, drilling occurs when the effective fluid pressure circulation, which are in contact with

the formation is less than the pressure of the pressure excitation. The purpose of application of

unbalanced drilling to reduce problems associated with invasive damage layer, which often

reduces the productivity of oil and gas.

about. When properly designed and implemented, an unbalanced drilling minimizes the

problems associated with the recesses in the layer of particulate matter, as well as other

problems, such as adverse reactions argillaceous phase capture of organic and inorganic

precipitation and emulsification. These effects can lead to an invasion of incompatible filter

filters the excessive state.

Special equipment and procedures necessary to control the pressure in a fluid layer between the

drilling, but drilling under drilling offer several important advantages to conventional drilling

methods. this includes

Improved formation evaluation,

for primary stimulation therapy may be reduced or eliminated,

reduce lost circulation during drilling,

Increased penetration and life,

Reducing the likelihood of rubbing pressed into the bottom.

Although not as common as over drilling, undersized achieved if the wellbore pressure is less

than or equal to the pressure vessel. Implemented with a light mud, which is used less pressure

than the pressure in drilling pressure to prevent damage to the layer, which can occur during

normal drilling procedures or excessive.

Negative differential pressure obtained during drilling imbalance between the reservoir and

piercing, promotes the production of composite liquids and gases. Unlike conventional drilling,

from the reservoir enters the vortex flow unbalance, but not away from it.

In Figure 1.2, the substrate rotating operation, showing the circulation of less hydrostatic drilling

fluid, wherein the stream can be formed out of the tank and forming a layer in the nest, as is

being drilled.

A simple equation, illustrating a state of drilling may be defined as:

Pf Pm

Figure 1.2 : Underbalanced Drilling

Although abducted and abused as well, it also called pressure-controlled techniques reduces the

usual problem of digging such as loss of circulation, diversity, minimal storing and building

damage. In addition, the flow of roughly includes a mining, gas refrigerator as little as quickly

looga eliminate termination.To put pressure on the control circuit pressure is used for internal

circuits that accompany the circle. The key point of success in drilling, cutting the length and

completion of the task, is to compare the balance during all the operation time. To achieve this,

early planning and engineering site is the basis for the success of the piracy. Usually, one part of

the drilling process is used, the non-linear flow can be used in a very soft environment.

Flow Date: The first drainage concept was introduced in the United States by the United States

in 1866. preceding to the excessive air demand for digging the well. As technology has been

improved over the past few years, internal systems with permanent foam gas and liquid have

been introduced in specific terms. The drilling technique is called the first time in South Texas,

and has become widely known worldwide with a successful application in southern Canada,

Australia and China. It is often used for recovering crop fields where stress is a serious problem.

During the 1990s, non-standard items were successfully used for land and sea operations in

Europe. Old techniques made by Angel (1957), Moore and Cole (1965) tried to predict the

volume or air needed to clean the hole in the air to drain the air. There were also several attempts

in the literature to develop a systematic screening method for evaluating the genetic bands in

complex applications. At present, non-volatile fluids are the most popular events in the field of

drilling technology. In accordance with the features of the boxes and sides, it is crucial to digging

well.1.2 Depressed depression Clay water must be the possibility of cleaning the hole casual to

prevent the fire from the well, and the ability to take on the production of fluids. Types of liquids

used for drilling, include depression:

Dry air

nitrogen gas

Natural gasDry air :

DRY AIR DRILLING:

Dry air comprises introducing air into the drill string without the use of liquids or additive. Drilling systems provide dry air at a rate faster penetration and longer life for one bit of any conventional drilling fluid. Once the air used in the drilling process, any contamination or blockage of a producing formation does not occur. Air drilling is limited to the formation of water wells and unstable high pressures layer. If this water wet drill cuttings to each other and to the walls of the tube and is transported from the opening of the air velocity. If these incisions are filled ring clay stopping the airflow and clog pipes formed. Although drilling with dry air can be carried out in the presence of large natural gas streams, it is possible risk of explosion in the wellbore and lights when a critical mixing ratio of methane in air is achieved.

NITROGEN GAS DRILLIND:

The main advantage is that the air a mixture of nitrogen and hydrocarbon gases is nonflammable. This eliminates the possibility of fire in the hole and eliminates the possibility of corrosion.

NATURAL GAS DRILLING:

Use of natural gas to prevent formation of flammable gas mixtures in the well, if hydrocarbon production zone permeated. Natural gas provides greater potential surface fires requires few changes in operating procedures used in drilling dry air

MIST drilling:

Drilling mist is a modification of the air holes, used in the production zones are water. When drilling a fog, a small amount of water containing the foaming agent in the gas stream is injected at the surface. In the mist, air drilling is the continuous phase and the dispersed liquid consists of droplets. The drilling system ensures penetration of fog and frames per equivalent ratio of nitrogen to the dry gas wells, with the added advantage of being able to handle wet education

FOAM mud:

This foam mud are two types of two ways: -1 stable foam and rigid foam.

1. stable foam:

Drilling system stable foam is produced by injecting water into the flow comprising 1% to 2% by volume of a foaming agent to the injection pressure. The viscosity of this foam is the primary means of transport for cutting, in contrast to annular air velocity dry air systems and air mist. The stable foam drilling systems, annular velocities help reduce erosion and large holes contractions led to the surface. Transactions that use drilling system capable of stable foam effectively eliminate up to 500 barrels per hour flow of drilling mud.

2. A solid foam

The drilling system adapted rigid foam stable foam drilling. Rigid foam systems include bentonite and a polymer stably produce stable foam stabilizing properties with large openings required for drilling large diameter holes foam. The system consisted of a pre-mixed liquid containing 96% water, 0.3% of soda ash, 3.5% bentonite and 0.17% guar gum. 1% concentration of the foaming agent added to the liquid before the injection into the air stream. Bentonite wall provided cake improved stabilization openings and dramatically remove. Since then, we have found that other polymers are more effective than guar gum, as well as to replace the bentonite in some applications.

AERATED DRILLING:

The porous system of the mud is another reduced pressure drilling is used primarily to prevent lost circulation. This system is an internal liquid air created by blowing air into the dirt condensed fluid or. Transporting sharp aerated liquid depends on the properties of lifting and transporting the liquid. The sole purpose of aeration, to reduce the weight of the liquid column in the layer and reduce the likelihood of lost circulation, without changing the properties of the drilling fluid. When drilling with aerated fluid system, it should be noted that they are all the most corrosion drilling methods under reduced pressure. However, with proper selection of the appropriate pH adjustment to water and the proper use of corrosion inhibitors technologically advanced systems are used with a carbonated liquid

1.5. Underbalance Techniques

Using the weight of the drilling fluids such as fresh water, diesel fuel and rent, it is the easiest

way to reduce the pressure in the wellbore. There are four main methods to achieve depression,

along with using the lungs of drilling fluids, gas injection and injection string parasites foam.

If you do not want to do so, then you will be able to use it for your business, and you will be able

to find the best results. If you do not want to go to the helipad, then you will not be able to travel

to the nearest gas station because of gas gasoline, gas and gas exploration in the gas field, and the

freezing point.

The technique of injecting gas down the drill pipe occupy and adding air or nitrogen to the

drilling fluid that is pumped straight down the drill pipe, Advantages of this method include

improved penetration, reducing the number of required gas and that the well must be designed

specifically for underbalanced drilling. In amateur injection gas through drama FreeLoader

circuit, the second pipe extends from the middle frame. While drilling cost increases, as well as

the time required, this method applies a constant pressure at the bottom of the well and does not

require any operational differences or unique MWD system. Image 1.3 shows a graphical

representation of the above procedure.

Figure 1.3 : Gas injection via parasite string

Less balanced less common application, foam nitrogen is less harmful for the reservations which

exhibit water sensitivity. While the safety margin is increased with the use of the foam, the

additional nitrogen needed to create a stable foam makes this technique being prohibitive.

Furthermore, there are limitations on the use of foam temperature in underbalanced drilling,

limiting the application of the method in wells that are smaller than a depth of 12,000 feet.

which was used as a traveler for 12 days and 12,000 people, you can travel 12,000 to 12,000

people.

SELECTION Drilling Fluids:

Structure wells fluid drilled traditional way, the fluid in the borehole system depression

transportation system for transportation of cuttings to the surface, cool and lubricate all of the

lower opening and helps control the bottomhole pressure. The design of the fluid system is one

of the most neglected parts of the project with depression. When designing the fluid system

depression, the effect on the current density equivalent desired, the pressure loss in the friction

ring and the fitting surface pressure. The design should generate a pressure below the formation

pressure but not so low as to create stability problems or overproduction. Compatibility between

components of the fluid system with produced fluids and fluid system with learning are critical

in choosing liquids incompatibility may cause damage to an emulsion layer or the fluid may also

affect the fluid characteristics of the system. Acid gases or hydrocarbons affect the stability of

most foams. Cleaning is always a concern in Underbalanced wells. Most Underbalanced liquid

system depends on the velocity of the fluid and not the viscosity for purification. Liquid

throughput capability at extremely poor rolling in a range from systems for clean gas to an

extremely good foam system

Thermal stability must be considered when designing a fluid system Underbalanced. Many of the

chemicals used can be decomposed at high temperatures. These include surfactants and

viscofantes agents. Temperature also affects the density of the fluid used in the system design.

As the liquid is heated, its density decreases. This is especially kill weight fluid. Corrosion is a

problem in the development of liquid systems Underbalanced. How good is obtained, the

reaction is extracted fluid, the gas introduced and the injected fluid can create an environment

that promotes high corrosion rates. Corrosion problems are accelerated, the barriers that form

naturally. The effect on the downhole tool is also taken into account when choosing a fluid

system Underbalanced. This includes the multiphase fluid compressibility, reduction in engine

power output. it can affect the performance and durability of engines mu and measuring

instruments into the well. Following infusion of gas into elastomers can also lead to explosive

decompression of the elastomers during trips. Downhole tools should be selected that will not be

effected by the fluid or a fluid system should be designed that mitigate the effect on down hole

tools. Fluid selection will also affect the ability to transmit data from down hole. Gas is a

compressible fluid, if gas is used in the fluid system, it may dampen or eliminate any signal

transmitted from down hole. Health, safety and environmental must be considered in selecting an

underbalanced fluid system. The system must be designed so that fluids can be handled safely at

surface. Both produced fluids, solids, and injected fluids must be handled in a minor that meets

local regulations. It must be remembered that thereturned fluid will be contaminated with

produced fluid. This will affect the disposal of the solids and all returned fluids.

COMPATIBILITY OF DRILLING FLUID:

Lab compatibility tests like shale reactivity, swelling test, retained permeability,

Scanning electron microscope(SEM) and X-Ray diffraction

Core and or drill cutting data

Geophysical and log

Including mud log data from offset wells

FORMATION FLUIDS, such as:-

Emulsion test

Formation damage tests

Underbalanced drilling fluid/formation fluid stability

Composition of all reservoir fluid like oil, water, gas

Samples fluids of reservoir

Gas mixtures affecting explosion envelope

HEALTH AND SAFETY ISSUES such as:

Determine non-existing equipment specifications necessary to meet safety standard

Development of emergency response plan

Review equipment design specifications

Review maximum exposure limitations of fluids and gas components

Training issues

Requirement necessary

Review material transportation, storage and handling procedure

Local safety regulatory compliance issues like personal and equipment

1.6 Statement of problemDue to the growing technologies associated with drilling operations, it is pertinent to look for

affordable, convenient and more productive alternatives. In this project, we would analyse both

drilling techniques and see its effect on various formations to be able to make a better choice for

each drilling scenario. Minimizing formation damage that occurs during conventional drilling is

a critical point for optimizing an oil field development, especially in fractured carbonate

reservoirs that often exhibit low matrix permeability. Invasion of drilling fluid into the fractured

formation can cause serious damage to the formation around the borehole and reduce well

productivity and ultimate recovery area thus minimize fluid invasion is important in this type of

reservoirs, drilling operations, where the drilling fluid pressure in the well is maintained below

the formation pressure in the uncased section is called (UBD drilling depression). Benefits

Productivity underbalanced drilling are well known in the art. UBD if used correctly, can

significantly reduce or eliminate dirt fracture invasion system. Although UBD has many

advantages compared with the database, a quantitative assessment of the possible consequences

of damage to the layer on the basis of complex formation characteristics and feasibility studies it

is important to judge the feasibility of UBD. Technology imbalance can be very successfully

aims to reduce or eliminate damage to the layer, if performed correctly, but an important part of

this study, there are problems that are often associated with UBD and development of properties

for the detailed design and implementation of appropriate programs UBD. The purpose of this

study is to evaluate the two main purposes: to highlight the performance of fracture reservoir by

using UBD and reduce the damage layer in UBD. Possible effects of damage may occur even if

the pressure condition of the depression is maintained for 100% of the time during the drilling

operation. Another major area of sensitivity to the damage layer during UBD operations is a loss

of pressure state of depression. Thus, it is vital to assess empathy training pulse effect on the

balanced position. The best way to assess the potential danger of damage is checked and the fluid

field representative core samples in simulated well conditions as possible damage to the dynamic

formation tester (DFD). Unfortunately, very little work in the literature to investigate damage

layer in fractured reservoirs. Jiao et al. He determined using two different binding agents,

CaCO3 and soluble fibers acid to reduce the solids and invasion in Berea core sample fracture.

Their results show that the use of fibrous additives are much more efficient than granular

additives, such as CaCO3. Ali et al. They reported the successful presentation in mixtures of

different sizes of fiber particles to prevent lost circulation into the unconsolidated sediments

severely depleted. Leopakke studied bridges and two individual particles in the fracture face.

They found that if the particle size is not compatible with the gap width can not form a stable

bridge and the particle size distribution of energies 2011 April 1730 adapted better opportunities

shutter. Their experimental results show that the mixture of granulated particles allows the best

work stopper fracture. The main aim of this work is an experimental study of the fluid invasion

in fractured carbonate reservoirs during drilling to a depression. For this purpose samples chalk

selected as representative of very fine-grained limestone in testing to simulate the central flood.

The behavior of penetration of the drilling fluid is measured under various conditions. Behavior

invasion invasion fluids depend on many of the key parameters such as pressure balanced bridge

additives and slurry composition (polymer content) and particle size distribution of the pore sizes

of cracks carbonate rock

1.7 Aims and Objectives

In view of the comparative analysis of overbalance and underbalance drilling operations in the Oil and

Gas industry, this project work seeks to investigate the following:

(i) To have an understanding of both the underbalance and overbalance drilling operations.

(ii) To know reservoirs suitable for either underbalance or overbalance drilling operations.

(iii) To also know the various effects and challenges associated with these operations.

1.8 Scope and Limitation

The scope of this study is to comparatively analyze underbalance and overbalance drilling

operations with emphasis on reservoir types.

1.9 Methodology

In the course of the project, vital information was obtained from the library, review of related

literatures, internet surfing, textbooks, petroleum journals and these formed the basis for analysis

of both underbalance and overbalance drilling operations.

CHAPTER 2:

LITERATURE REVIEW

2.1 HISTORICAL OVERVIEW OF DRILLING IN THE OIL INDUSTRY

Drilling was designed by the Chinese more than 4,000 years ago. They used a cutting head

attached to bamboo sticks, which are connected to drill to a depth of 3000 feet (915 m). Rise and

Fall of the impact of the drill string and the destruction of bamboo allowed less dense rock

formations. It was reported that often takes two to three generations of workers for large wells

(Treadway, C., 1997). In 1859, in Titusville, Pennsylvania, Colonel Drake FL finished the first

oil well using the percussion instrument with the type of instrument cable. One of the first

reports of percussion drilling technology was held in 1949 (Harpst and Davis, 1949).

Basic research and development in the perforation have been reported between 1950 and 1960

(Wanamaker, 1951, Faihust and Lacabanne, 1956, Topanelian, 1958 Fish, 1961 Simon 1964,

Hartman has, in 1966, McGregor, 1967). They have made significant progress in understanding

the percussion mechanism in the laboratory. Some applications have one oilfield also recorded in

order to demonstrate the effectiveness of drilling technology (Smith and Kopczynksi, 1961;.

Bates, 1964).

Since the 1990s, the oil wells were drilled deeper and deeper, and consequently, the depth

increases, the rocks are becoming more and more difficult. Has developed a hydraulic hammer or

hydraulic hammer to adapt to these new challenges and to achieve effective mechanical design

(Kong et al 1996;. .. Giles et al, 2001; Tibbitts et al, 2002).

These designs, however, are still at a preliminary stage in the countryside. Throughout its

history, the theoretical development of the technology of drilling is delayed relative, compared to

its improved mechanical designs. This phenomenon is not uncommon in the drilling industry as

an integrated rock drilling process involves many disciplines and complex physics that their

faces rigorously simulate prohibitively theoretical problems.

[

The first oil wells were drilled in 1800 were drilled underbalanced. These wells drilled with

insufficient fluid pressure in the annulus. Accordingly, if the permeable layer has been found, the

well flowed. Well flow is not monitored, so that led to the loss of reserves. The oldest patent

UBD back to the mid-1800s, when he was granted a patent to use compressed air to clean cuts in

the bottom of the hole.

Advances in the industry continued until the mid-twentieth century. People began to understand

the use of multiphase liquid mist and controlling fire in the borehole and provide greater

resistance to inflows of water. advances were made in understanding and modeling of multiphase

systems and air. The algorithms and equations were developed to predict the amount of gas

required for cleaning the holes and the pressure in the well as a result of circulating a liquid and

gas mixture. Growth continued in this technology 1900s with first application of the multiphase

fluid in the 1930s the use of multiphase fluid (air or natural gas with water or oil) became

popular full south of the United States at this time in the drilling of oil wells. During the 1970s,

UBD technology was used in limited applications. However, problems with UBD techniques

limited the growth of the industry. Environmental problems were the largest obstacle,

particularly in gas drilling systems, where large amounts of dust were released into the

atmosphere. Most wells drilled underbalanced prior to 1985 were low pressure applications with

the aim of increasing rate of penetration (ROP) in non-productive zones.

2.2 THE EMERGENCE OF DRILLING TECHNIQUES

Over time, the oil industry has witnessed great progress and developments, and to this day.

Viability of the presence of hydrocarbons (oil and gas) dictates liability in daily life to be done

with the oil industry. Thus, the latter became one of the most important industries in the modern

life. Drilling Problems are inevitable, and there is no drilling operations around the world will

take place smoothly. These problems may be related to the equipment used, the difficulties

encountered in the well, human error or accidents. Naturally, any problem or accident fatalities

can be economic consequences. Operation perfectly drilled one in which there is no problem, so

no additional time requirements and cost, or life-threatening.

Thus, we can conclude that drilling engineers aim to achieve optimal operation of drilling with

the shortest time and cost. To achieve this, they conduct research around the world to solve the

problems associated with the tedious drilling. The solutions may be in the form of modifications

of drilling equipment and chemicals or the introduction of new drilling technologies and new

equipment designs.

The method used all over the world during drilling known as imbalance drilling (DB). It is

defined as the drilling process, wherein the hydrostatic pressure exceeds the pressure used

training. This is done with the "kill" the main purpose well. However, there are many problems

associated with drilling on the balance sheet. These problems are to maintain the differential

pipe, loss of circulation, damage layer and other problems.

a relatively new method of drilling was introduced, known as underbalanced drilling (UBD).

Proper design and operation UBD can prevent or minimize fluid invasion problems and results

(deposition reaction clay and emulsification), along with damage invasive formation which

occurs during normal conditions on the balance.

UBD is a method in which the hydrostatic pressure in the fluid system circulating and

background while the well is drilled to lower the reservoir pressure is the percentage of the target

pressure. This condition may, of course, is generated with a low density fluid (clear water or

light hydrocarbon systems) in certain situations when a high pressure natural formación.UBD is

a procedure that is used for drilling oil and gas wells, where the pressure in the well it It remains

lower than the fluid pressure in the bed being drilled. As the well is drilled, formation fluid

enters the wellbore and the surface.

This is the usual situation in which is maintained above the formation pressure in the well to

prevent formation fluids into the well. In normal pit "over balanced" fluid invasion is considered

a blow, and if the well is not closed, it may cause an explosion in a hazardous situation.

However, in underbalanced drilling, there is a "rotating head" on the surface, substantially seal

which diverts production fluids in the separator, allowing the drill string to rotate.

In many situations the condition of depression artificially generated by simultaneous introduction

of some type of non-condensable gases from the liquid circulating system to reduce the effective

hydrostatic density. Strip most nitrogen is used because of its availability and transport ease, but

were also performed operations on the air depression, natural gas, treated with combustion air

with reduced oxygen content (unit semipermeable membrane treated), depending on the

particular situation under consideration portion .

UBD methods frequently used for horizontal wells, where concern about the damage layer has

been particularly important because the contact time is more fluid and a higher incidence of

open-hole horizontal well application endings against the vertical. This is because even a

relatively small damage invasive horizontal wellbore can significantly reduce productivity in

comparison with the drilled wellbore and the casing vertical pipe. If depressed condition must be

artificially generated, most of the time is achieved mechanically by means of a process known as

injection drillstring. In this process, the noncondensable gas are introduced directly into the drill

string in superfici

2.3 WELL SELECTION

The selection process consists of analyzing geo mechanical and petro-physical

information to determine whether a particular well and/or reservoir is a potential

candidate for UBD. For a UBD candidate, preliminary wellbore-hydraulics modeling is

performed to determine operational feasibility. That is, whether underbalanced settings

are possible and can be maintained through the entire hole section while providing

adequate hole cleaning and satisfying downhole motor limits.

Once a prospect is identified, the optimal technique is selected and any potential

production improvement is evaluated. Of primary importance in this evaluation are

reservoir properties, which determine formation production and are input for reservoir

modeling that estimates anticipated production during UBD. Different scenarios are

modeled, and the results used in both detailed wellbore-hydraulics flow modeling and

economics evaluation.

Final candidate qualification depends on the economic evaluation, as well as comparing

other technologies such as stimulation. At this point, the importance of the quantified

productivity improvement becomes apparent as various economic benefits are evaluated.

For example, UBD techniques can significantly reduce fluid costs through use of lighter

fluid systems and reduced mud losses. It requires some level of surface system

automation for rapid response to downhole conditions, and some form of data acquisition

system, with costs dependent on the specific UBD equipment set-up necessary to obtain

the required amount of data. UBD has an effect on formation damage, where UBD can

minimize or eliminate it, compared with conventional drilling (Overbalanced drilling)

which has long-term implications for improved productivity.

Thus, the selection process comes back to the primary objectives of the project as to what

needs to be accomplished to deliver specific benefits, and what equipment and data

acquisition capabilities are required to do so.

Characteristics of UBD:

The effective downhole circulating pressure of the drilling fluid is equal to the hydrostatic

pressure of the fluid column, plus associated friction pressures, plus any pressure applied on

surface.

Conventionally, wells are drilled overbalanced. In these wells, a column of fluid of a certain

density in the hole provides the primary well-control mechanism. The pressure on the bottom of

the well will always be designed to be higher than the pressure in the formation (Fig. 1a). In

underbalanced drilled wells, a lighter fluid replaces the fluid column, and the pressure on the

bottom of the well is designed intentionally to be lower than the pressure in the formation (Fig.

1b).

Because the fluid no longer acts as the primary well-control mechanism, the primary well control

in UBD arises from three different mechanisms:

Hydrostatic pressure (passive) of materials in the wellbore because of the density of the fluid

used (mud) and the density contribution of any drilled cuttings.

Friction pressure (dynamic) from fluid movement because of circulating friction of the fluid

used.

Choke pressure (confining or active), which arises because of the pipe being sealed at

surface, resulting in a positive pressure at surface.

Flow from any porous and permeable zones is likely to result when drilling underbalanced. This

inflow of formation fluids must be controlled, and any hydrocarbon fluids must be handled

safely at surface.

The lower hydrostatic head avoids the buildup of filter cake on the formation as well as the

invasion of mud and drilling solids into the formation. This helps to improve productivity of the

well and reduce related drilling problems.

UBD produces an influx of formation fluids that must be controlled to avoid well-control

problems. This is one of the main differences from conventional drilling. In conventional

drilling, pressure control is the main well control principle, while in UBD, flow control is the

main well-control principle. In UBD, the fluids from the well are returned to a closed system at

surface to control the well. With the well flowing, the blowout preventer (BOP) system is kept

closed while drilling, whereas, in conventional overbalanced operations, drilling fluids are

returned to an open system with the BOPs open to atmosphere (Fig. 2). Secondary well control is

still provided by the BOPs, as is the case with conventional drilling operations.

Hole Cleaning Considerations

Reducing the pressure in the well usually cause a high rate of penetration. However, higher

penetration rate can cause excessive pressure lower holes that circulate and return to the well

unbalance conditions. Furthermore, because the annular fluid segregation, there is an increased

risk that the good to be packaged, which leads to grab. In this situation, the gas tends to rise,

because the liquid deposited at the bottom of the hole. It is a major cause elevated pressures in

the well due to a higher density fluid into the sand. Large cutting volumes, generated a high level

of penetration is also difficult to remove. Thus, the penetration rate must be carefully controlled

to ensure cleaning of the borehole and removing a sufficient amount of snails. The liquid flow

may lead to inadequate conditions that cause differential adhesives hole adhesions. Thus,

reducing the rate of penetration required for vessels which are transferred to the surface. The

aqueous phase is an important factor for better Aviscosified ROP. When drilling with foam and

mist, the cleaning efficiency reaches a limit of the well after a certain level of imbalance, and the

perforation rate begins to decrease, as shown

Case Study

Underbalanced Drilling Operation in East Asia

With the proper selection of candidates, using these drilling techniques to meet the specific needs

of a complex project can improve the overall success of the drilling and add great value to the

operator. The following case study provides a good illustration of the importance of keeping the

pressure conditions are continuously in the process of underbalanced drilling and completion.

If severe loss zone prevented traditional drilling to join the site in several wells in East Asia,

UBD has been successfully used to achieve two goals. First, he solved the problem of

preservation of drilling underbalanced pressure control to minimize losses in the process of

drilling the true depth (TD). Secondly, it is to exaggerate the damage site and to evaluate the

performance of different intervals. This included characterizes the flow property testing to

determine the stability and the need to stimulate production. This application requires the

acquisition of high quality data, by using additional sensors in the well to control BHP. In some

wells, two types of gas meters have been used to provide continuous monitoring of the gas

velocity. The data is transmitted via satellite to the center of the formation evaluation services,

where analysis was carried out in real time, including periodic testing and flow CWDA in some

wells.

In this case, successful allowed UBD drilling at no loss, although some wells have achieved

entirely TD, when unexpectedly high performance eliminates further drilling without imbalance

and cause damage to the formation, were achieved or beyond a surface equipment and the

drilling equipment. Compared with conventional drilling imbalance herein, UBD NPT reduced

by 75% due to exclusion associated with the loss of control, legs that are stuck pipe and better

well control time. Furthermore, for a rock bit high compressive strength has been reduced to two

to three bits, as compared with six to eight bits, that is usually required for drilling imbalance.

Since the training was extremely sensitive to damage, even with limited periods of short and

overweight, OB, probably not given the observed performance improvements. UBD also gave a

characteristic layer for application to confirm reservations and to further determine the properties

of the production intervals of the formation, including confirmation, at least one area previously

considered unproductive.

However, in this case, the greatest advantage UBD performed to increase production tenfold

compared with offset wells OB resistant, and has increased five-fold compared with the best well

productivity caused by this displacement fields. Stimulation was not necessary, providing

additional savings on a UBD, and production tests show little long term

Case studies

Drilling

In this part of the case study I will focus on the parameters used to control and adjust the BHP during the

drilling operation, i.e. the liquid (mud) flow rate, the gas injection rate and the back pressure applied by

the choke. Often the choke is considered to be the most effective parameter when a change in the BHP is

desired. (Pèrez-Tèllez et.al, 2004) I would like to investigate this further and look into the reasons behind

the BHP changes caused by the different parameters and which of the three that changes the BHP the

fastest. I will also look into the phenomenon of liquid hold up and its consequences for the drilling

process. 5.1.1. Under pressured well Figure 5.2 shows a BHP curve for an under pressured well. This

curve is not from an actual drilling process, but will be used to look into the response from changes in the

circulating parameters. The goal in the test was to start from the parameters shown in Table 5.1

Experiment values under pressured well

and then increase the BHP approximately 4 bar by change one parameter at the time and keeping the

other ones constant. Table 5.1 also shows the parameter values needed to increase the BHP P a g e 30

with 4 bar. During the testing there was some influx from the reservoir which is plotted in Figure 5.3. To

obtain the parameter values used in the experiment I first started with the Steadyflodrill simulator and

made a steady state plot of the BHP against gas injection rate like the one showed in Figure 5.1. By using

a function in the simulator called “track values” I could see the values the graphs are made up of, and by

that be able to see how much the BHP would change if I changed the gas injection rate, jumped to another

liquid rate graph or if I changed the wellhead pressure. This method gave a good impression of where the

values needed to lie to obtain a useful result. When I had done this I switched to the Dynaflodrill

simulator and fine-tuned the values there before making the experiment plots. So all in all some trial and

error had to be performed to get a useful result, but with the starting help from the Steadflodrill simulator

the time spent on this was not very long.

Start values End values

Liquid rate 500 lpm 700 lpm

Gas rate 15000 lpm 11680 lpm

Back pressure 8 bar (100% open choke) 9,7 bar (45% open choke)

In Figure 5.2 we see 3 increases in BHP which comes from the changes in parameters. The first one (from

the left) is the change in liquid rate, the next the gas rate and the last one from the change in choke

position. We also see that the BHP returns to its original level after each increase since I then changed the

parameters back to their original values before I tested the next P a g e 32 parameter. The same trend can

easily be observed on Figure 5.3 where it is seen as a drop in the influx when the BHP is increased. When

the test was performed I waited for the pressure to stabilize at around 62,5 bar, then I changed the

parameter to the new value and then waited for the BHP to stabilize at a new level, which then would be

around 66,5 bar if everything was done correct. The bars on Figure 5.2 mark where the change in

parameter was performed, and when a reasonably steady – state situation was obtained.

Liquid rate

If we start with the change in liquid rate we see that this is actually the first parameter to obtain a stable

BHP after the change. If we look at the curve we see that the BHP first goes a little bit up due to the

increase in friction pressure caused by the increased flow rate. This alternation can also be seen in the plot

of liquid flow rate in and out of the well which is shown in Figure 5.4.

Here we see that the flow rate of liquids from the well is alternating when the flow rate in is increased.

The reason for this alternation in both BHP and flow rate from the well is probably that we are dealing

with a multiphase flow regime. The GLR in the well doesn’t change instantly to its new level at every

location in the well. Some of the free gas present in the well must be circulated out to make room for the

new liquid which is entering the well. This process is not a steady process and fluctuations must be

expected.

Gas rate

When looking at the gas rate we see the same trend as when changing the liquid rate, some alternation in

the BHP before stabilizing. The reason for this is that the two operations are basically the same: Changing

the GLR to a new level. We can see on Figure 5.2 that the BHP rises a bit slower and takes a bit longer to

stabilize when changing the gas injection rate than when changing the liquid rate. The reason for this is

probably that a reduction in the flow rate of fluids changes the GLR slower than an increase, which is the

case with the liquid rate change.

Choke

Changing the choke opening does not change the BHP in the same way as the two previous parameters.

Modifying the choke opening does not add or remove any mass to the circulating system, but changes the

GLR by applying back pressure. When looking at Figure 5.2 and in Table 5.1 one can see that the

increase in back pressure of 1,7 bar gives an increase in BHP of 4 bar. This has again to do with the fact

that we are dealing with a multiphase flow system. When back pressure is applied the gas bubbles in the

well get compressed. This leads to more space for the liquid phase, and the result is that more liquid is

pumped into the well than what is flowing out. (Guo and Ghalambor, 2004) A bigger proportion of the

borehole will then be filled with liquid, with a higher hydrostatic pressure gradient as the result. All this

will lead to an extra increase in the BHP, in addition to the back pressure increase. Figure 5.4 illustrates

this by showing a spike downwards for the flow rate of liquids out of the well when the choke is being

closed. The amount of free gas is highest at the top of the well and this, along with the fact that the gas is

more compressible at lower pressures high up in the hole, leads to that all the “new” liquid in the column

will be found here. Figure 5.5 shows the amount of free gas in the annulus before and after the choke

closing. We see that the amount of free gas at the top have changed from about 65% to about 58% after

the closing. At the bottom there is almost no change at all. Before the amount was 21,8%, and after it was

21,7%. From 600 m and down the changes in amount of free gas is negligible.

Over pressured well

Over we have looked at the drilling of a well which needs gas injection to be able to achieve

underbalanced conditions and to bring reservoir fluids to surface. Now we will take a look at a well with a

different reservoir pressure. The well path and the fluids in the reservoir are the same as before, but the

pore pressure is now higher, so no gas mixing in the drilling fluid will be necessary. Figure 5.6 shows the

BHP in the same manner as for an under pressured well. The difference here is that since we don’t inject

gas, no changes in the gas injection rate can be made. Table 5.2 summarizes the parameters used in the

test. To obtain the parameters I used the same method as described in the paragraph about the under

pressured well, except that here I could only use a plot like the one in Figure 5.1 when looking at BHP

values when the gas injection rate where zero.

Start values End values

Liquid rate 500 lpm 700 lpm

Gas rate 0 lpm 0 lpm

Back pressure 8,9 bar(48% open choke) 9,9 bar (35% open choke)

Also here the goal of the test was to increase the BHP with approximately 4 bar. The influx of formation

fluids is shown in Figure 5.7. The influx is not exactly the same, but it is in the same area as before. It is

difficult to compare the two situations at a very detailed level since it is two different situations and the

pressure changes will not be exactly the same. What is interesting when comparing the two BHP plots is

to see if the BHP reacts differently when there is no gas injected, and less free gas in the annulus overall.

It is important to notice that the reservoir produces some gas which will go out of solution when reaching

the top of the well. This means that even though no gas is injected it doesn’t lead to an annulus which is

completely without free gas.

Liquid rate

When looking at the change in liquid rate we see a quick response in the BHP when the flow rate is

increased. The BHP then stabilizes for about 15 minutes before starting to rise again. This behavior is

explained in the following way. The first BHP increase comes from the increase in frictional pressure

caused by the increase in pump rate. The second increase starts when the GLR starts to change and thus

also the density of the fluid in the annulus starts to change. When the GLR has reached a new and stable

level the BHP will stop increasing. If one compare the BHP plots from the under pressured well with the

over pressured, one sees that the change caused by the frictional pressure is clearer in the over pressured

well plot. In the under pressured well plot the frictional and hydrostatical change in pressure glides more

into each other and the difference is not as visible. The reason for this difference is probably connected to

the gas amount present in the well. When the well is mostly filled with liquid, which for all practical

purposes is incompressible, the increase in frictional pressure is much faster transmitted from the top to

the bottom of the well.

Choke

As mentioned above we have some free gas in the annulus. This gas is only located at the top of the well.

When looking at Figure 5.6 we see an almost instantaneously increase in the BHP when the choke is

being closed. This is expected since the well is almost entirely filled with liquids. When the choke is

being closed less fluid are leaving the well than before. Since the flow of liquid into the well is the same,

the result will be a higher pressure all along the annulus. This pressure increase will compress the gas and

the same effect as described under choke regulations for an under pressured well will lead to a higher

BHP increase than if the well was filled entirely with liquid. After the first BHP increase we see that the

pressure stabilizes for some time before increasing to its final level. A reason for this can be that when the

BHP is increased the influx of formation fluids goes down. This means that less gas is entering the well.

By that I mean formation fluids which will become gas when it gets to the top of the well. Since the liquid

injection rate is kept constant the GLR in the well will start to change. When this new composition of

liquids reaches the top of the well a lower GLR will be established and the BHP will increase further.

Figure 5.8 illustrates this by showing the amount of free gas in the well in the period of stable BHP after

the first increase, and the amount after the last increase in BHP.

Conclusion

This test has shown us that the choke is not always the fastest way to change the BHP. We have seen that

the liquid rate parameter actually changes the BHP the fastest for the under pressured P a g e 38 well. The

reason for this is probably that the well drilled is a relatively short one, and that it therefore don’t take so

long time to alter the GLR and thus the density of the drilling fluid to its new level. For the over pressured

well the situation is opposite. In the over pressured well there are very little gas in the well compared with

the under pressured one. A pressure change coming from a reduction in the choke opening will be faster

transmitted through a liquid column due to its incompressibility, and thus increase the BHP faster. In the

end we then see that we have two different parameters that change the BHP the fastest. The change in the

choke opening is then not always the fastest way to change the BHP. Which parameter that is will vary

with fluid system, well type, influx of formation fluids etc. Knowing how to most efficiently change the

BHP is important since it allows you to respond the quickest possible way to a situation. For instance if

you need to change the BHP fast due to a higher influx of gas than expected it will be desirable to use the

parameter with the shortest response time to stabilize the situation. Knowing how the different parameters

influence the multiphase flow system is important since it can give a better understanding of why the well

reacts as it does if changes in this system like a higher influx than expected should occur. Adjustment of

operation parameters can then be made more correctly.

Liquid holdup:

Liquid holdup is a phenomenon that takes place in multiphase systems because the gas and liquid phases

are not flowing with the same velocity. In underbalanced drilling this is driven by the difference in

density between the two phases. When gas and liquid are flowing downward through a pipe the liquid

will flow faster than the gas due to its higher density. When flowing upward a pipe the gas will flow

faster than the liquid resulting in what is called liquid holdup. (Lyons et. al., 2009) This will lead to a

different GLR at a certain place in the annulus than at the injection point. At the top of the annulus you

will have a higher GLR than at the bottom since the gas moves faster than the liquid. In other words, less

liquid is coming out from the annulus than what is being pumped in through the drill pipe. This change in

GLR will affect the BHP. A lower GLR at the bottom increases the hydrostatic pressure since the liquid

with its higher density gets more dominant in the pressure column. This will increase the BHP from the

level it would have been at if the GLR had been constant throughout the entire circulating system.

Mathematically liquid hold up can be presented as follows. (Lyons et. al., 2009) (5.1) Figure 5.0

illustrates the phenomenon of liquid holdup.

Here we see the volume fraction of free gas in the under pressured well discussed above. At the moment

the plot is made, the well is being circulated with both liquid and gas injected through the drill string. The

holdup effect can be observed in both the annulus and in the drill string. In the drill string the flow goes

downwards which means that the liquid phase will flow fastest, which can be seen in the reduction of free

gas from the top to the bottom of the string. In the annulus we see the same trend, more gas at the top and

less at the bottom. We see that at the bottom of the annulus the amount of free gas is less than what it is at

the top of the drill string. This means that there is a higher liquid content at the bottom of the well, which

as mentioned above, will affect the BHP.

2. Tripping

Performing tripping during an underbalanced operation can be a challenge. The type of well being drilled

is determining the challenges, and which measures must be taken to conduct a successful operation. For a

well not able to bring fluids to surface without help from the circulating system a tripping operation can

cause problems. As for a connection the separation of fluids plays a role during tripping, but it may not be

the only issue related to this operation. My goal in this chapter is to have a closer look at the problems

occurring during tripping, and possible ways to deal with them.

Challenges

Separation of fluids

In the chapter about the performing of connections I discussed the phenomenon of separation of fluids. I

mentioned in this regard that in a worst case scenario the BHP could exceed the formation pressure

because of separation in a longer time perspective. This is shown in Figure 5.30 and Figure 5.31 which

shows the BHP against time and the formation fluid influx against time, respectively. The well simulated

is the same under pressured well as the one used in the chapter about connections. On these two figures

we see that as the time goes the BHP approaches the formation pressure and the influx of formation fluids

approaches zero.

When performing tripping the pumps will be off for a long time and thus no drilling fluids are entering

the hole. The reservoir however, will continue to produce fluids until the BHP equals the formation

pressure. Because of the separation process this column will after a time exist entirely of liquids from the

bottom and up to a certain point in the well, and entirely of gas from this point to the top. This will, as

seen under the connections, lead to an increased BHP since a liquid column with higher density will be

formed. Figure 5.32 shows the distribution of free gas in the well after a full separation process. The

difference in the pressure columns from before and after the separation is depicted in Figure 5.33.

Here we see an almost complete separation process with gas on top and liquid from about 200 meters and

down.

Here we see the development in the pressure column in the well due to the change in the density. We see

that when the gas separates from the liquid the density increases and the pressure increases faster down

the well. At the end point of the separation, which is when the formation stops flowing, the BHP have

actually increased with 11,2 bar from 65,3 bar before the separation to 76,5 bar after the separation.

Heavy oil

For an under pressured well you can experience problems during tripping besides the gas – liquid

separation issue. Even for reservoirs containing heavier oil with low gas-oil ratios (GOR) the well will

eventually kill itself. Figure 5.34 shows the BHP development during tripping for the same type of well as

before, but with a different reservoir fluid and pressure. This reservoir contains heavy oil with a low

GOR. The pore pressure however, is so high that it is possible to drill the well without using gas in the

drilling fluid. The drilling fluid therefore consisted only of the base oil used when simulating the wells

mentioned above. The liquid rate was the same as before. Figure 5.35 shows the influx of the formation

fluid against time.

The great difference between the two wells I have simulated is the difference in time before the well is

killed. The one where separation takes place is killed much faster than the other one. We see from Figure

5.30 that when the pumps are turned off at about 120 minutes it only takes about 220 minutes (3 hrs and

40 min) before the flow from the reservoir is stopped at about 340 minutes. When looking at the other

well the time span is a lot longer. The pumps are turned off at about 140 minutes and the reservoir stops

flowing after 1160 minutes (19 hrs and 20 min). To find the reason for this big discrepancy one has to

investigate the two cases more thoroughly. For the first case we have seen that we get a separation of

fluids in the annulus and that this eventually leads to a fluid column in the well with 100% gas the first

200 meters, and 100% liquid the rest of the well. Figure 5.36 shows that the flow of liquids from the well

stops instantaneously when the pumps are turned off. This means that the flow in the annulus is stopping

up and the liquid starts to flow down and gas up. As long as the BHP is below the formation pressure

there will also be some flow into the well from the reservoir. Figure 5.37 shows the flow of liquids from

the well in the second case.

We see a clear difference between the two cases on the above plots. The flow from the well in the second

case doesn’t stop instantaneously. This is due to the fact that we don’t have any separation of fluids in this

case since there is no free gas in this well. The reason for the killing of the well must then be a bit

different in the second case than the first one. To explain this difference we can look at Figure 5.38 and

Figure 5.39. Figure 5.38 shows the plot of formation oil against depth when the well is killed for the first

case.

Here we see that on top we have no formation oil because of the gas, but in the major part of the well

from about 200 mMD to about 900 mMD we have about 7% formation oil. (And some percent formation

water) The rest of this liquid column must then be made up of the liquid phase of the drilling fluid. At the

bottom the formation oil (and water) have flown into the well from the reservoir and are now dominating

the liquid column there. If we take a look at Figure 5.39 which shows the same plot for the second case

we see a bit different situation.

Here we see that the reservoir fluids dominate a bigger part of the well, and only in the top part the

drilling fluid is dominating. The killing mechanism here is then not separation, but the fact that the

reservoir pressure is not strong enough to push the heavy oil all the way out of the well. The reservoir

flow is stopped by the weight of the produced liquid column.

Conclusion

To tie up the loose ends we can say that the main difference between the two cases of well killing during

tripping is that in case one the well is killed because the separation creates an uneven density distribution

which causes a too heavy fluid column in the well, in case two the well is killed because heavy liquid

flows from the reservoir into the well until the weight of the liquid column exceeds the reservoir pressure.

The consequence of the two cases above, and all scenarios in between as long as the well is under

pressured, is that the well is killed after a shorter or longer time period. This in itself is not very critical

since the BHP is just stabilizing at the formation pressure. Actually this makes the tripping of the well

easier since there is no flow coming from the well and the rotating control device can thus be open and

tripping performed in a conventional way without the use of e.g. a snubbing unit. (Graham, 2011) The

problems start when you have finished the tripping and want to start drilling again. It can then be difficult

to regain the underbalanced conditions you had before without causing a significant overbalanced

situation in the well. This is off course the exact thing one tries to avoid during an underbalanced

operation since it can cause significant P a g e 68 reservoir damage. For the well with the separation

problem the consequences will be in the same category as mentioned in relation with the connection

issues: A pressure spike when starting the circulation again. Figure 5.40 illustrates this problem. The

reservoir liquid which has been accumulating in the wellbore during the tripping must be circulated out

before the pre-trip GLR again can be established and a stable underbalanced BHP regained.

We see that a pressure spike with a top of nearly 90 bar induces an overbalanced situation for nearly 20

minutes in the well. 90 bar is 15 bar over the formation pressure and is a quite severe overbalance. This

could be enough to cause serious reservoir damage which can reduce the benefits of the underbalanced

operation significantly. For the well in case two one will also experience an overbalanced pressure spike

due to the friction pressure that is being added to the BHP when the pumps are turned back on. This spike

however, will be much smaller compared to the one for case number one. Figure 5.41 depicts the

regaining of circulation for case two.

We see here that the pressure spike only has a magnitude of 1,3 bar above the formation pressure. The

duration however, is about 30 minutes. Even though this is longer than for case one the low magnitude of

the spike probably makes this situation less damaging for the reservoir than the one in the case with

separation. From the analysis of the two cases one can draw the conclusion that killing due to separation

both happens faster and will be more damaging to the reservoir when circulation is restarted. To prevent

the killing of a well during tripping is possible if one make use of one of the measures mentioned in the

chapter about connections: The parasite gas injection method. This method allows you to maintain

circulation all the time through the tripping procedure. Instead of being injected through the drill pipe the

gas is injected through a parasite string or a concentric casing. The injected gas lowers the density of the

produced fluids from the reservoir which makes the reservoir pressure sufficient to transport the fluids to

surface during the whole tripping period. Figure 5.42 shows how the BHP is kept relatively stable

throughout the tripping period.

We see here that we don’t get the rise in BHP due to separation or a too heavy liquid column as in the two

cases described above, and that the BHP is very stable. Also when the circulation is started again we only

see a small alternation in the BHP, and no great spike, before it settles at a stable level again. The

drawback with this method is as mentioned in the connection chapter that it is not always suitable due to

the modifications needed to be made to the wellbore geometry. In the two example cases I used the

standpipe gas injection method. When you use this method it is no way to maintain circulation in the well

during the tripping operation, and thus there really is no method to prevent the well from killing itself

eventually. It is only a matter of time before it happens.

CHAPTER 3:

METHODOLOGY

3.1 REVIEW OF THE DIFFRENCES BETWEEN OVERBALANCE AND UNDERBALANCE DRILLING

The major difference between conventional overbalanced drilling and underbalanced

drilling is the hydrostatic pressure exerted by drilling fluids in each technique. To

elaborate, hydrostatic pressure of the drilling fluid is proportional to its density. When it

comes to overbalanced drilling, the equivalent circulating density (ECD) of the drilling

fluid is adjusted so that the pressure due to the drilling fluid column is higher than the

formation pressure, resulting in what can be referred to as a “killed” state where there is

“no inflow of formation fluids. It should be noted that the density of the drilling fluids is

adjusted by the use of suitable additives.

On the other hand, UBD is the technique in which the circulating pressure of the drilling

fluid is less than the formation pressure, such condition if applied, should be present

along the entire section of the pay zone. The result is the flow of formation fluids (water,

oil or gas) into the wellbore. The low pressure of the drilling fluid is attributed to its low

density, which is attained by the injection of non-condensable gases into the circulating

fluid, reducing its “effective hydrostatic density”.

The gases used could be Nitrogen, Air, Natural gas, processed flue gas, reduced oxygen content

air. Injection of gases into drilling fluids to reduce their density is an artificial induction of the

underbalanced state. Naturally occurring underbalanced state can be found in over pressured

reservoirs where low density mud can be utilized; this is known as flow drilling. The technique

used worldwide while drilling is known as overbalanced drilling. Which is defined as the drilling

process where the hydrostatic pressure used exceeds the formation pressure. This is done with

the main purpose of “killing” the well. However, there are numerous problems that accompany

overbalanced drilling. Such problems are differential pipe sticking, loss of circulation, formation

damage and other problems. A relatively new technique was introduced, known as

underbalanced drilling, where the well is being drilled with a hydrostatic pressure less than that

of the formation. Correct and proper execution of such technique eliminates problems associated

with overbalanced drilling. More precisely, underbalanced drilling solves the issues of formation

damage, differential pressure sticking and loss of circulation. Additionally, underbalanced

drilling increases the rate of penetration and provides other uses discussed in this project. On the

other hand, underbalanced drilling has its own problems as well.

The difference between overbalanced and underbalanced drilling , when the fluid is sending

through the pipeline or shaft at higher pressure compare to reservoir it is called overbalanced

drilling or conventional drilling. This process carrying during drilling recovery the oil and gas

from the reservoir, this higher pressure could damages the rock and wellbore.

In this formation process when we start to drill oil and gas wells we should maintain the

pressure in the wellbore lower compare to fluid pressure being drilled this is called

underbalanced drilling . Up to the surface between in drilling processes the formation fluids

flows through the wellbore pipelines

3.2 COMPARATIVE ANALYSIS BETWEEN UNDERBALANCED AND CONVENTIONAL OVERBALANCED DRILLING IN THE GULF OF SUEZ USING A DRILLING SIMULATOR

The drilling simulator used is called “CS Inc. Drilling and Workover Simulator 2009”. It

comprises a software part and a hardware part, the latter consists of a set of panels similar

to those found in an actual rig. This section will start by describing the Data Input and

Output. For confidentiality reasons, the well whose data will be inserted into the

simulator will be referred to as well “X”. Additionally, the Egyptian company from

which the data has been procured will be named company “Y”. In addition, the data used

is to be slightly adjusted before being input into the simulator. This is because well “X” is

a directional well whereas the drilling simulator used is not a complex one and does not

deal with any deviated or directional wells. For well “X”, its Daily Drilling Report

(DDR) and drilling program are the documents from which the data was extracted.

3.2.1 Extracted Data

The data types required by the simulator include:

Pressure data

BHA data

Mud data

Table 3.1 : showing Pressure profile of the drilled formations

Formation Pressure gradient (psi/ft.)

Depth of formation top (m)

Depth of formation top (ft.)

Casing setting depth in formation (m)

Casing setting depth in formation (ft.)

Zone1 (S.Gharib) 0.433 - - 2141 7023

Zone2 (Hammam-Faroun)

0.26 2170 7117.6 - -

Table 3.2 : showing the BHA used

Reference OD (in) ID (in) Length (ft.)DCs 6-3/4” 3” 62”HWDPs 5” 3” 775”DPs 5” 4.276” 6186”

Table 3.3 : showing the mud used

Mud system Mud weight (kg/lit)

Mud weight(ppg)

Plastic viscosity (cp)

Yield point(lb./100 ft2)

1 1.27 10.6 32 352 0.93 7.75 7 10

3 (Kill mud) 1.08 9 18 12

The drilling program is used to provide profile of the drilled formations, while the other

three parameters are provided by the daily drilling report (DDR).

To simulate the underbalanced state, the kick zone had to be first identified. This was

achieved by referring to the DDR. Data input into the simulator requires the initial

conditions to be inserted. More precisely, the data of the last casing before drilling the

zone of interest is to be considered. By referring to the drilling program it is clear that 9-

5/8” casing is to be set at the end of South Gharib (S. Gh.) formation before proceeding

to Hammam-Faroun (H.F.). As a result, the two formations that will be dealt with the

simulator are South Gharib (S. Gharib) and Hammam-Faroun(H.F), once the

formations of interest are identified, their pressure gradients must be determined. This is

carried out, as mentioned earlier, using the drilling program.

3.2.2 INTERPRETATION OF RESULTS

3.2.2.1 UNDERBALANCED DRILLING ZONE 1(S. GHARIB)

In Fig 3.I, it is seen that while drilling S. Gharib formation, starting at a depth of 7073 ft,

the kick occurred at 7113.5 ft. S. Gharib formation is mainly a salt formation however,

the kick occurrence and hence the start of the underbalanced conditions can be attributed

to the presence of thin streaks of limestone. The vertical scales represent the following

parameters: ROP (purple), Weight on bit WOB (Green), Pit Deviation (Blue),

Formation pressure (Red) and Bottom hole pressure (Black). The horizontal scale

represents time. In Fig 3.1, it is obvious that:

i. There is constant pit deviation (No losses or gains).

ii. Formation pressure is also constant since only one formation is being drilled.

iii. Bottom hole pressure showing gradual decrease as a result of replacing the wellbore mud

with the lighter mud.

iv. No change in ROP.

Fig 3.2 shows similar trends to Fig 3.1, except for the increase in ROP from 12 ft/hr to

nearly 30 ft/hr. This is due to the reduction in mud weight and the rise of the

underbalanced conditions. In Fig 3.3, the same trends are followed as in Fig 3.1 and Fig

3.2 for the ROP, WOB, formation pressure, and pit deviation. As for the bottom hole

pressure, it stabilized due to the complete replacement of the old mud weight by the new

mud weight. In other words, the old, heavier mud is completely out of the hole. The

sudden decrease in the ROP and WOB in Fig 3.3 is due to a connection being made

during that time of drilling.

Figure 3.4: underbalanced drilling through zone 1

Figure 3.2: underbalanced drilling through zone 1

Figure 3.6 : Underbalanced drilling through zone1 (progressing)

3.2.2.2. UNDERBALANCED DRILLING ZONE 2 (HAMMAM-FAROUN)

Zone 2 started at a depth of 7117.6 ft. this zone is considered a depleted zone because

its pressure gradient is 0.26 psi/ft (Table 3.1). The formation pressure of H.F. is about

1850 psi, while the formation pressure of the overlying S. Gharib formation is around

3000 psi. Fig 3.4 shows that the underbalanced condition has been compromised and this

resulted in an overbalanced condition. This is due to the large formation pressure

difference, where zone 1 has high pressure while zone 2 has a very low pressure and

nearly considered depleted. The pit deviation shows a decrease due to the fact that little

fractures (leaks) got formed due to the overbalanced condition that resulted in some

losses in circulation (about 10 bbl/hr). The entrance into zone 2 is signaled by the abrupt

decrease in bottom hole pressure from 3000 psi to 1850 psi. Due to the conversion of

underbalanced conditions to overbalanced conditions, ROP decreased from 35 ft/hr to

less than 10 ft/hr. The bottom hole pressure is above 2500 psi while the formation

pressure is around 1850 psi, this confirms the presence of the overbalanced condition. Fig

3.3 shows a trend similar to that of Fig: 3.4. However, the sudden and little decreases in

the bottom hole pressure values are due to the loss of drilling fluid into the leaks in the

formation as the drilling progresses

3.2.2.3. OVERBALANCED DRILLING OF ZONE 1

The mud weight, as mentioned earlier, was changed to 9 ppg to drill the formation

overbalanced. In Fig 3.4, it can be observed that the bottom hole pressure is around 3350

psi while it was around 2800 psi during underbalanced drilling. While the maximum ROP

was 35 ft/hr in the underbalanced conditions, it is around 22 ft/hr during overbalanced

drilling for the same formation, Fig: 3.5 show steady parameters.

Figure 3.7 : Underbalanced drilling through zone 2 (the underbalanced conditions have been compromised)

3.2.2.4 OVERBALANCED DRILLING ZONE 2

While drilling zone 2 (starting at depth 7117.6 and having a formation pressure around

1850 psi), it is observed that even though the mud weight used in this zone is higher than

the one used while drilling underbalanced, no losses or leaks occurred (Fig 3.6). A

possible explanation for such a phenomenon is that zone 1 when drilled underbalanced

was allowed to release some of the stresses inside it when it caused the kick. This

decrease in stresses, in turn, resulted in a small decrease in the overburden stress on zone

2. As a result, the decrease in stresses on zone 2 gave a chance for fracture initiation and

leakage of fluids into it. On the other hand, when zone 1 was drilled overbalanced it was

not allowed to release any of the stresses inside it. Consequently, when zone 2 was

Figure 3.8 : Overbalanced drilling, zone 1 (progressing)

reached, there were no chances of fracture initiation to occur of course, the ROP dropped

when zone 2 was reached. This is due to an increase in overbalanced conditions because

of the higher difference between bottom hole pressure and formation pressure.

3.2.2.5 ECONOMIC ANALYSIS

The cost of drilling the entire 8 ½” section is estimated to be $637,499 according to the

drilling program of well X. Additionally, drilling the 8 ½” section took 13 days.

Therefore, the average cost per day of drilling the section can be calculated as follows:

Averagecost per day = Total cost of drilling the section = 637,499 = $49,038

Figure 3.9 : Overbalanced drilling through zone 2 (progressing)

No. of days 13 day

The thickness of the section is around 1880 ft. The maximum ROP value obtained by

underbalanced drilling is 35 ft/hr. Therefore, the number of days needed to drill the

section using this ROP value can be calculated as follows:

Time needed to drill section days = Total section thickness = 1880 = 53.7 hrs = 2.2 days

ROP 35Hence the total cost required to drill the section would be

Total cost $ = 2.2 X 49,038 = $107,884

As for overbalanced drilling, the maximum ROP was 20 ft/hr. This means the

calculations would proceed as follows

Time needed to drill section days = Total section thickness = 1880 = 94hrs = 3.9 days

ROP20

Total cost $ = 3.9 X 49,038 = $191,248

This is nearly 77% more than the cost of underbalanced drilling. The following

observations were noted:

While drilling S. Gharib in the Gulf of Suez at underbalance conditions, the ROP

improvement from 20 ft/hr to 35 ft/hr. Improvement of ROP by UBD is the main

reason for drilling underbalance.

Regarding the hole problems, a comparison was done between overbalance and

underbalanced drilling at the same section and it was found that: The creation of

overbalance conditions resulted in losses of circulation at depth below 7117.6 ft

(H.F.), the losses amounted to 10 bbl/hr. Whilst drilling at underbalanced conditions

no losses were experienced as circulation losses can occur at overbalance conditions,

not underbalanced.

UBD prove more advantageous than overbalance drilling, but in some cases the loss

of underbalanced conditions can lead to more serious problems than overbalance

drilling. This was the case when the underbalanced condition was compromised due

to the sharp decline in pore pressure after zone H.F. was reached. Because UBD

allowed the overlying formation (S. Gharib) to release some stresses by allowing

some gas to flow from it. As a consequence, the underlying formation (H.F.) was

subjected to lower overburden stresses. This provided an opportunity for leakage into

the formation once the underbalance conditions are compromised, which was the

case.

The simple economic analysis, based on the time saved by increasing ROP due to

UBD resulted in (for the 8 ½” section of the well) shows that, the drilling costs

increased by about 77% for overbalanced drilling.

Finally, it can be concluded that UBD provides lower drilling costs, increased ROP

and less hole problems when it was compared to overbalanced drilling of the same

formations.

Economic limitations

It is important not to forget the business driver behind the technology. If benefits cannot be

achieved, the project must be reviewed. The improvements from UBD—increased penetration

rate, increased production rate, and minimization of impairment—must offset the additional cost

of undertaking a UBD project.

This is often the most difficult limitation of UBD to overcome. If the reservoir/production

engineers are not convinced that there is a sound reason for drilling underbalanced for

productivity reasons, most underbalanced projects will never get past the feasibility stage.

To drill a well underbalanced, extra equipment and people are required, and this adds to the

drilling cost of a well. The operators must show a return for their shareholders, so they will want

to know if this extra investment is worthwhile before embarking on a UBD project.

Costs associated with underbalanced drilling

The following factors contribute to the cost increases for an underbalanced drilled well in

comparison to a conventionally drilled well:

Pre-engineering studies.

Rotating diverter system.

Surface separation and well-control package.

Snubbing system to deal with pipe light.

Data acquisition system.

Extra downhole equipment [nonreturn valves and pressure while drilling (PWD)].

Special drillstring connections (high-torque gas that is tight with special hardbanding).

Additional personnel training.

Additional operational wellsite personnel.

Additional safety case update consistent with planned UBD operations.

Extra time required to drill underbalanced.

From industry experience to date, we can state that underbalanced drilled wells are 20 to 30%

more expensive than overbalanced drilled wells. This applies to both offshore and onshore

operations in a similar area.

Cost alone, however, is not a good measure for the evaluation of UBD. The value of the well

must also be recognized. The average three-fold increase in productivity of an underbalanced

drilled well can add considerable value to a field development plan or a field rehabilitation

program. If we add a potential increased recovery from a field to the value of an underbalanced

well, even an increase as small as 1% in total hydrocarbon recovery may have a large impact on

field economics.

3.2.3 ADVANTAGES OF- UNDERBALANCED DRILLING OVER OVERBALANCEDDRILLING

Bits balanced wells have several advantages compared to conventional drilling, such

as:

I. Deleted damage layer: the usual well, drilling mud is forced to the formation in a

process called "invasion", often causing formation damage - reducing layer's ability to

transfer the oil into the wellbore at a pressure and flow rate is given. This may or may

not be indispensable. In underbalanced drilling, if the state of the balance remains at a

low level until the well is productive, the invasion does not occur and the damage

layer can be completely avoided.

II. A higher rate of penetration (ROP): less than the downhole pressure, it is easier to

cut and remove the rock drill.

III. Reduced circulation losses: lost circulation occurs when uncontrolled formation

flowing drilling fluid. You can lose a large amount of dirt before the actual mud cake

formed or loss may continue indefinitely. If the well is drilled depression, the sludge

will not go into the formation and the problems can be avoided.

intravenously Differential adhesion eliminated: differential adhesion occurs when the

drill pipe is pressed against the borehole wall, so that part of its circumference only

see the reservoir pressure, while the others continue pushed downhole pressure, as a

result of the pipe is stuck to the wall and may require thousands of pounds force to

remove it, it may not be possible. Since the pressure in the tank is greater than the

pressure in the wellbore to UBD, away from the walls of the pipe, the elimination of

differential adhesion.

against damage layer: some rock formations tend reactive to water. If the drilling

fluid is used, the water in the drilling mud reacts to form (mostly clay) and essentially

causes damage layer (decreased permeability and porosity). The use of underbalanced

drilling can be avoided.

VI. Excludes damage layer. In a typical borehole, a drilling fluid is forced towards the

formation in a process called intrusion into, often causing damage to the layer,

reducing the ability of the formation to transmit oil into the wellbore at a

predetermined pressure and flow. This may or may not be indispensable. The drilling

with a small balance, when a state of depression persist until then, and will not be

productive, the invasion does not occur and the damage layer can be completely

avoided.

VII. Increases the rate of penetration (ROP). When a lower pressure at the bottom of

the well, it is easier to cut and remove the rock bits.

VIII. Reduction of lost circulation. Lost circulation occurs when the drilling mud

flows in an uncontrolled formation. You can lose a large amount of dirt before the

actual mud cake formed or loss may continue indefinitely. If the well is drilled with a

small balance, the sludge will not be included in the layer and can avoid this problem.

IX. Eliminates differential adhesion. Differential adhesion occurs when the drill pipe

is pressed against the borehole wall, so that part of its circumference only see the

reservoir pressure, while the others continue pushed downhole pressure. As a result,

the tube is stuck to the wall and may require thousands of pounds of force to remove

it, it may not be possible. Since the pressure in the tank is greater than the pressure in

the wellbore to UBD, away from the pipe wall, eliminating differential adhesion.

H. layer reduces damage and loss of water. Some rock formations tend reactive to

water. If the drilling fluid is used, water, drilling fluid is reacted to form (mostly clay)

and essentially causes a damage layer (decreased permeability and porosity) using a

drill bit can help balance

3.2.4 DISADVANTAGES OF UBD underbalanced drillingi. Expense: UBD is usually more expensive than a conventional drilling program,

particularly if drilling in a sour environment or in the presence of adverse operational or

surface conditions (i.e. remote locations, offshore, etc.). Obviously, the major objective in

implementing a UBD operation in most cases is to improve well productivity over a

conventional overbalanced completion. Therefore, in a properly executed operation, it is

expected that the potential downside of increased drilling costs will be more than offset

by increased productivity of the well.

ii. Safety Concerns: The technology for drilling and completing wells in an underbalanced

fashion continues to improve. Recent developments in surface control equipment,

rotating blowout prevention equipment, and the increased usage of coiled tubing in UBD,

has increased the reliability of many UBD operations. The fact that wells must be drilled

and completed in a flowing mode, however always adds safety and technical concerns in

any drilling operation. The use of air, oxygen content-reduced air, or processed flue gas

as the injected gas in a UBD operation, although effective at reducing the cost of the

operation, can cause concerns with respect to flammability and corrosion problems.

Considerable work has been done recently in high pressure testing to ascertain safe

combustible limits of produced Mixtures of natural gas, oil and drilling mud with air, flue

gas, and oxygen content-reduced air.

iii. Wellbore Stability Concerns: Well consolidation issues have been a longstanding

concern in UBD operations, particularly in poorly consolidated or highly depleted

formations. Considerable evidence exists, therefore, that stability concerns in many UBD

applications may not be as problematic as classically assumed, but a reservoir by

reservoir evaluation i s required to quantify stability concerns for each UBD application.

iv. Underbalanced drilling is usually more expensive than conventional drilling (when

drilling a deviated well which requires directional drilling tools), and has safety issues of

its own.

v. Technically the well is always in a blowout condition unless a heavier fluid is displaced

into the well. Air drilling requires a faster up hole volume as the cuttings will fall faster

down the annulus when the compressors are taken off the hole compared to having a

higher viscosity fluid in the hole. Because air is compressible mud pulse telemetry

measurement while drilling (MWD) tools which require an incompressible fluid can not

work.

vi. Common technologies used to eliminate this problem are either electromagnetic MWD

tools or wireline MWD tools. Downhole mechanics are usually more violent also because

the volume of fluid going through a downhole motor or downhole hammer is greater than

an equivalent fluid when drilling balanced or over balanced because of the need of higher

up hole velocities. Corrosion is also a problem, but can be largely avoided using a coating

oil or rust inhibitors.

CHAPTER 4:

ANALYSIS

4.1 LABORATORY SCREENING TECHNIQUES

A variety of laboratory techniques are available to quantify the effect of UBD and OBD

on a given formation.

4.1.1 UNDERBALANCED LABORATORY EVALUATION

i. Obtain representative preserved or restored state samples at correct initial oil and water

saturation conditions.

ii. Measure initial, undamaged reference permeability to oil or gas (depending on the

reservoir type under consideration) at varying conditions of drawdown pressure

encompassing the range of expected field drawdown pressures (to observe presence of

capillary or turbulence effects).

iii. Conduct a UBD fluid test by circulating the proposed drilling fluid in an underbalanced

mode across the core face with the maximum expected underbalanced pressure gradient

across the core while continuously tracking permeability for a 24-bour period or until a

stabilized dynamic permeability is obtained.

iv. Degrade underbalanced pressure in several stages, allowing more than 24 hours

equilibration at each stage to observe if counter current imbibition effects are apparent

and cause a reduction in permeability as underbalanced pressure is reduced. Conclude

with measuring gas permeability after a balanced flow phase.

v. Expose core to an overbalanced pulse with base drilling mud, including expected

concentration of drill/mud solids for a 5 to 6O minute period (duration and magnitude of

the overbalanced pulse depend on the type of drilling operation and potential problems

expected).

vi. Conduct a variable drawdown pressure return-permeability test with gas or oil to determine

the threshold pressure required to mobilize any damage induced by the overbalanced pulse

and ascertain if damage is reduced by increasing drawdown pressure and final amount of

damage remaining at the maximum expected drawdown pressure (if damage is severe,

potential stimulation treatments could be evaluated at this time).

This procedure provides a good indication as to whether countercurrent imbibition effects are

going to be problematic and how much underbalanced pressure must be maintained to

minimize their effect. An indication of the severity of formation damage and depth of

invasion to be expected if the underbalanced condition is compromised can also be provided

by this type of test as well as the ability of formation pressure (or stimulation treatments) to

remove the damage.

4.1.2 OVERBALANCED LABORATORY EVALUATION

i. Core procurement and initial permeability measurements are identical to those described

for the underbalanced laboratory tests.

ii. Conduct an overbalanced drilling fluid test by circulating actual field quality mud

(containing drill and mud solids and bridging agents) in a turbulent fashion across the

core face at the maximum expected overbalance pressure. Observe fluid loss rates, filter-

cake buildup, and sealing potential and depth of filtrate and solids invasion. A spectrum

of muds from conventional systems, which may commonly be used (i.e., gel chemical) to

more sophisticated polymer-type (MMH, etc.) blends with specialty-sized bridging and

fluid loss agents, may be evaluated to obtain the optimal system for overbalanced

operations.

iii. Conduct a variable drawdown pressure return-permeability test with gas or oil to

determine the threshold pressure required to mobilize any damage induced by the

overbalanced exposure and ascertain if damage is reduced by increasing drawdown

pressure and final amount of damage remaining at the maximum expected drawdown

pressure (if damage is severe, potential stimulation treatments could be evaluated at this

time).

This test sequence illustrates how damaging a conventional overbalanced drilling

program may be (in comparison with either a well-executed or poorly executed

underbalanced program from

the proceeding test program matrix) and provides an indication if comparable or superior

potential performance may be obtainable at less cost and risk from a specially tailored

conventional-type drilling system in comparison with an underbalanced operation.

4.2 TYPES OF RESERVOIRS SUITABLE FOR UNDERBALANCED

DRILLING

On the basis of the information presented, certain types of reservoirs are more applicable

for UBD operations than others. Prime reservoir types where UBD has been successful in

the past include the following:

High permeability (> 1, 000md) consolidated inter-crystalline sands and carbonates. At

high formation pressures, well control issues may limit the utility of UBD because of

surface processing and handling issues.

High permeability poorly/unconsolidated sands (some risk of wellbore collapse present in

some situations, however, a number of underbalanced operations have been conducted

successfully in unconsolidated sands). At high formation pressures, well control issues

may limit the utility of UBD because of surface processing and handling restrictions and

sand production issues.

Underpressured/depleted formations where conventional drilling would exert more than

1,000,000 psi hydrostatic overbalance pressure.

Formations containing significant concentrations of water based mud filtrate-sensitive

materials (expandable clays (> 1 %), deflocculatable clays (>5%», anhydrite, halite, etc.

Formations exhibiting severe potential incompatibility issues with base filtrates

(emulsions, sludges, precipitates).

Dehydrated formations exhibiting sub-irreducible water saturations or hydrocarbon

saturations may be candidates for UBD with the appropriate based filtrate to avoid

countercurrent imbibition and phase-trapping problems (water for oil-wet systems and oil

for water-wet systems).

4.3 COMMON MECHANISMS OF FORMATION DAMAGE DURING OVERBALANCED AND UNDERBALANCED DRILLING OPERATIONS

A number of potential formation damage mechanisms may occur during overbalanced

and underbalanced drilling operations. These mechanisms include:

1. Mechanically Induced Formation Damage

a. Physical migration of in-situ fines and mobile particulates.

b. The introduction of extraneous solids of either an artificial nature (i.e. weighting

agents, fluid loss agents, or artificial bridging agents) or naturally occurring drill

solids generated by the milling action of the drill bit on the formation.

c. Relative permeability effects associated with the entrainment of extraneous

aqueous or hydrocarbon phases within the porous medium.

d. Formation damage effects associated with the use of extreme underbalanced or

overbalanced pressures and associated fines migration or spontaneous imbibition

phenomena.

e. Direct mechanical glazing phenomena associated with bit-formation interactions.

This particular damage mechanism is usually associated with gas drill operations

where high bit-rock temperatures commonly occur.

2. Chemically Induced Formation Damage

a. Clay induced formation damage associated with the reaction of low salinity or

fresh invaded fluid filtrates with potentially reactive clays (swelling clays or

mixed layer clays). Low salinity or pH shocks may also result in clay

deflocculation phenomena which are a disruption of electrostatic forces which are

holding clays in a flocculated state. This phenomenon is common in some

kaolinite rich reservoirs.

b. The precipitation of waxes, solids, asphaltenes or diamondoids caused by a

reduction in temperature or pressure associated with the drilling process, or

incompatibility between introduced hydrocarbon fluids and in-situ hydrocarbon

fluids resulting in a destabilization and precipitation of asphaltenes.

c. The formation of insoluble precipitates caused by the blending of incompatible

drilling and completion filtrates with in-situ foreign waters.

d. The generation of high viscosity stable water in oil emulsions in the near wellbore

region caused by the invasion of incompatible water-based filtrates resulting in

the formation of an emulsion block.

e. Wettability alterations associated with the use of invert drilling muds or other

muds containing high concentrations of polar surfactants or materials. Near

wellbore wettability alterations can reduce the relative permeability of oil

significantly and increase relative permeability to water, causing a dramatic

change in the water-oil production characteristics of a given completion.

3. Biologically Induced Formation Damage

The introduction of bacterial agents during drilling and completion is a major

concern as problems associated with bacterial growth in porous media can be of a

delayed yet significant onset. Major problems associated with bacterially induced

damage would include:

a. Secretion of high molecular weight polysaccharide polymers to form plugging

bio- films or bio-slimes.

b. Colonization of bacteria onto conductive metal surfaces resulting in pitting and

corrosion.

c. Propagation of sulphate reducing bacteria (a classification of anaerobic bacteria

which do not require oxygen to survive) and the resulting metabolization of

sulphate present in naturally occurring formation or injection water to toxic

hydrogen sulphide gas.

4.4 SURFACE EQUIPMENT REQUIREMENTS

Because UBD provide means of controlling downhole pressures during drilling, as

implemented in the industry, this technique uses the same type of equipment for both,

surface equipment requirements and configurations vary widely.

System design set-ups range from simple wellhead rotating control devices (RCDs) to

full equipment packages. Across the entire spectrum, a key consideration is safety and

whether the equipment setup controls the operation within strict safety limits.

In general, for UBD applications, key components of a complete surface equipment

package where influx is expected and reservoir productivity is the primary objective

includes:

Upstream gas generation and fluid compression/injection systems.

Wellhead rotating control devices (RCD’s).

Downstream choke-manifold system.

Open or closed fluid-handling systems, including downstream fluid separation

package (3- phase or 4-phase separation system).

Geologic sampler.

Emergency shutdown (ESD) systems.

Data acquisition and display systems.

Flow metering devices and pressure valves.

Rig-injection pumps.

Figure 4.1 shows typical surface equipment for underbalance drilling conditions taking into key

consideration safety.

Figure 4.10 : Typical surface equipment for UBD operation

CHAPTER 5:

CONCLUSION AND RECOMMENDATION

5.1 CONCLUSION AND RECOMMENDATION

5.1.1 CONCLUSION

The field cases selected have shown scenarios where the project was initially planned to

be overbalanced but were switched to Underbalanced based on the project drivers and the

well conditions. The cases have also shown situations where OBD was implemented, but

reservoir performance encouraged the consideration of UBD. It is important to implement

lessons learned and be flexible in the project plan to best address the situation faced. A

tendency that should be avoided is to preclude one method over the other solely based on

subjective considerations. UBD is often viewed as complex and more costly by the

industry. It is safe to conclude that OBD cannot match UBD in terms of minimizing

formation damage/improved productivity and allowing characterization of the reservoir;

and this aspect needs to be considered in the technical and economic comparison of the

methods before a final decision is made.

What is the best operational system to use? This question must be answered from a

technical, safety and economic point of view. Technically, the system which will yield

the best bottomhole pressure control with a continuously underbalanced condition is

optimum with the required necessity of continuous real time bottomhole location and

pressure measurements.

Which to use and how to choose? While both underbalanced and overbalanced drilling

provide means of controlling downhole pressures during drilling, the methods differ

significantly in how they do it. During candidate well selection, the benefits and

limitations of each technique must be considered qualitatively and quantitatively to

determine which should be applied.

5.1.2 RECOMMENDATION

When determining whether underbalanced drilling or overbalanced drilling should be

applied as a solution, the benefits and limitations of each should be both qualitatively and

quantitatively considered, and a decision should be reached depending on the merits of

each technique. UBD addresses drilling problems, reducing NPT by minimizing losses,

and differential sticking and the time associated with well control events typically

associated with conventional overbalanced drilling.

Where the primary drivers are reservoir related, UBD has been found to be the best

option. Reservoirs benefiting most from UBD are those formations prone to damage.

Additionally, if reservoir characterization while drilling is of importance then

underbalanced drilling is the option that should be selected, although UBD can be more

costly than OBD due to additional equipment that may be required to achieve and

maintain underbalanced conditions.

When properly designed and executed UBD provides a whole new approach to complex

reservoir management problems and may facilitate the economic completion and

exploitation of reserves unobtainable by any other type of currently available technology.

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