General Equipment, Communication, and Personnel Related Problems

Most drilling problems result from unseen forces in the subsurface. The 

major causes of these problems are related to equipment, gap in proper 

communication, and issues related to human errors (personnel-related). 

However, there are drilling problems that are directly related to formation, 

operational hazard, and geology. This section discusses the equipment, 

communication, and personnel-related problems.

2.1.3.1 Equipment

The integrity of drilling equipment and its maintenance are major factors 

in minimizing drilling problems. However, the equipment involved can 

also be a source of problems in addition to communication and personnel￾related issues. Drilling problems can significantly be reduced by proper rig 

hydraulics (i.e., pump power) for efficient mud circulation, proper hoisting 

power for efficient tripping out, proper derrick design loads and drilling 

line tension load to allow safe overpull in case of a stuck pipe problem, and 

well-control systems (ram preventers, annular preventers, internal preven￾ters) that allow kick control under any kick situation. Specific mud prop￾erties and required horsepower are needed for bottom hole and annular 

space cleaning, proper gel strength to hold the cuttings. Proper monitoring 

and recording systems are necessary to monitor trend changes in all drill￾ing parameters and can retrieve drilling data at a later date. Proper tubular 

hardware is specifically required to accommodate all anticipated drill￾ing conditions. Effective mud-handling and maintenance equipment will 

ensure the mud properties that are designed for their intended functions. 

The following drilling equipment may create potential drilling problems 

while drilling: i) rig pumps, ii) solids control equipment, iii) the rotary 

system, iv) the swivel, v) the well control system, and vi) offshore drilling. 

In the majority of cases, equipment failure may happen due to corrosion in 

addition to bending, fatigue, and buckling.

The integrity of drilling equipment and its maintenance are major fac￾tors in minimizing drilling problems. The following are all necessary for 

reducing drilling problems:

Proper rig hydraulics (pump power) for efficient bottom and 

annular hole cleaning

Proper hoisting power for efficient tripping out

Proper derrick design loads and drilling line tension load to 

allow safe overpull in case of a sticking problem

Well-control systems that allow kick control under any kick 

situation (i.e., proper maintenance of ram preventers, annu￾lar preventers, and internal preventers)

Proper monitoring and recording systems that monitor 

trend changes in all drilling parameters and can retrieve 

drilling data at a later date

Proper tubular hardware specifically suited to accommodate 

all anticipated drilling conditions

Effective mud-handling and maintenance equipment (i.e., it 

will ensure that the mud properties are designed for their 

intended functions)

2.1.3.1.1 Case Study

Inspection of the below-grade wellhead equipment has shown corrosion 

damage to the buried landing base, casing spools and surface casing, espe￾cially in water injection and supply wells in onshore fields in the Middle 

East. Occurrence of corrosion damage has been a concern in the buried 

wellhead equipment and surface casing immediately below the landing 

base in the onshore fields. Initial random inspections of the below-grade 

wellhead equipment in the mid-eighties showed corrosion damage to the 

buried landing base, casing spools, and surface casing. Typical landing base 

and surface casing equipment for onshore wells is depicted in Figure 2.2. 

The 13-3/8 casing is either welded or screwed on to the 13-3/8 l3-5/8

landing base. The 18-5/8 conductor pipe is cemented at a distance ranging 

from a few inches to 2–3 feet below the landing base.

                          Procedure and Data: A typical landing base inspection operation involves 

excavating the cellar to below the landing base to expose three to six feet 

of the surface casing or until hard cement is encountered below the land￾ing base, whichever is earlier. The exposed section is sand blasted and 

then inspected for evidence of corrosion. The data from such inspections 

for the last six years (1991 through 1996) is presented in Table 2.1, while 

Figures 2.3–2.5 illustrate some cases of severe corrosion damage on the 

landing base and surface casing on oil as well as water wells.

Causes: The damage was occurring in spite of an apparently success￾ful cathodic protection program that has reduced the number of casing 

leaks due to external corrosion damage. The possible causes of the cor￾rosion damage were: leakage of water from surface piping and wellhead 

valves during various operations on water related wells, presence of highly 

saline and corrosive water close to surface in the area, and impediments to 

effective cathodic protection at shallow depths.

Preliminary Solution: In view of the safety and environmental hazards 

associated with possible shallow leaks from corroded casing or failure of 

wellhead equipment, a number of steps have been taken to control the dam￾age. These include regular inspection and repairs at regular intervals, pro￾tection with field-applied corrosion resistant coatings, and a requirement 

to coat all new wells immediately after the rig release.

Lessons learned: Corrosion damage could jeopardize well safety to the 

below-grade wellhead equipment and the upper few feet of the surface 

casing. This was recognized as a potential problem and it could result in 

flow of well fluids outside the wellbore. An effective protection program 

                            

has been implemented that includes regular inspection, standardized

repair procedures, and initial protection of all new wells with protective

coatings as well as sacrificial anodes.

2.1.3.2 Communication

There are no better issues in drilling process safety than communication.

Communication in drilling begins before the first foot is drilled. It begins

in the pre-planning and pre-spud meeting. Communication does not

stop at the pre-spud meeting, rather continues throughout all the various

meetings that are held. At the operator/contractor meeting, which should

be private, operators need to review their respective responsibilities, the

multimedia messaging service (MMS) requirements, the IADC report, the

BOP drills (e.g., reaction and trip drills), land covenants and the BOP clos￾ing-in procedure. The pre-cement meeting is more of a people plan. The

responsibilities of the company supervisor, drilling engineer, tool pusher,

driller, feed pump operator, chief cementing engineer and mud engineer

are all spelled out and delegated.

In addition to good communication at the various meetings, there also

needs to be good communication between the crew and the home office. The 

crew on-site needs to be very thoughtful and detailed in their reports of any

problems. Their communication needs to include the trends and related facts,

their operational plan to correct the problem and their recommendations.

Besides communication between the various parties, there is another

type of communication which is extremely important in a drilling opera￾tion. The driller must learn to communicate with the bottom of the hole. He

can do this through monitoring trends. The various trends tell the driller

exactly what is happening down below and gives him the information that

everyone needs to make critical decisions on a daily basis. In order to see

these trends, they must be written down. Some of these trends that he must

monitor include: i) pressure and stroke trends, ii) torque trends, iii) drag

trends, iv) rate of penetration trends, v) mud trends, and vi) pit trends.

The trends, daily reports, appraisals and other records are all effective

tools in communication. The logging records help the geologists pick their

sites and make better plans. The bit records help the drilling team in their

future bit selection. The reports and records help the engineer do his post￾appraisal of the well. It helps him to determine whether the program was

followed or the deviations were necessary and how future programs can be

improved during planning. Good communication helps management to

properly supervise and optimize their operations.

Good drilling training programs do not merely give out information,

they help drillers, engineers, rig foremen, and service companies learn to

communicate with each other, optimize their drilling operations, and prop￾erly supervise the well. When Bill Murchison started Murchison Drilling

Schools in 1977, he set out five objectives for his Operations Drilling

Technology and Advanced Well Control Course. They were: i) how to

supervise a drilling operation, ii) how to preplan field operations, iii) how

to analyze and solve drilling problems, iv) how to prevent unscheduled

events, and v) how to communicate on the rig. Twenty-four years later,

the same five objectives are helping companies around the world to super￾vise, optimize, and communicate better on the rig. The training has proved

so valuable that many oil companies, contractors, and service companies

have made it standard policy to put all their new service men through

the Murchison Drilling Schools Operations Drilling Technology and

Advanced Well Control Course. It has become part of their overall training

that they receive before going out into the field.

In order for effective communication to take place in that meeting, many

issues must be considered. Here are just a few of those considerations:

1. The meeting must be well planned by the engineer (e.g., he

must meet with a number of people before he even makes

his plans).

The purpose of the meeting needs to be very clearly spelled

out. Here are five purposes for that pre-spud meeting: i) to

open all doors of communication, ii) to reduce unscheduled

events, iii) to review the well plans, iv) to review the geologi￾cal considerations, and finally v) to coordinate the responsi￾bilities between the contractors, service companies and the

operators. The meeting must have an agenda which helps

accomplish these purposes.

3. The meeting needs to have the presence of the right people.

The operator’s superintendent and the contractor’s superinten￾dent both need to be there. The tool pushers and drillers, the

foremen, the engineers, the geologist, the offshore installation

manager and the representatives from the service companies

all need to be at this meeting. Unless all these key individu￾als are at the meeting to both communicate their concerns

with others and come to a mutual understanding of how the

program is to be implemented, the efficiency, profitability and

success of the entire drilling operation is jeopardized.

2.1.3.3 Personnel

Given equal conditions during drilling/completion operations, person￾nel are the key to the success or failure of those operations. Overall well

costs as a result of any drilling/completion problem can be extremely high.

Therefore, continuing education and training for personnel directly or

indirectly involved is essential to successful drilling/completion practices.

For example, four of every five major offshore accidents are caused by

human errors. This highlights the need to make safety, which is the back￾bone of any offshore company’s corporate culture. Over recent years, there

has been a growing recognition of the importance of human factors in the

management of safety-critical industries. Many of the concepts are new to

the oil and gas industry with much of the seminal work and development

of techniques having arisen from the nuclear and aviation domains. These

have set the standard for human factors practice.

Human factors has identified the aetiology of most major incidents as

being linked to human failure. The findings have been that, although most

will have multiple causes, over 80% will have a cause which is related to

human performance. Human factors is a relatively new science. It is con￾cerned with adapting technology and the environment to the capacities

and limitations of humans. The challenge for human factors is to act in a

prescriptive way to make systems and working practices safer and more 

efficient. Many drilling incidents have been found relating to human fac￾tors. However, currently there is not yet a special approach by which drill￾ing safety professionals may rationally evaluate the actual human factor

risk lever and accordingly select appropriate risk control measures for a

given drilling process.

It has been found that more than 80% of incidents are related to human

factors in the global drilling industry. After studying the human error fea￾tures in 59 serious drilling blowout cases from 1970 to 2006 in China, it

shows that the percentage of the human factor as direct cause of a blow￾out incident can reach 93.53%. It includes the individual violation and

management deficiency which reveals the human factor.

Up to now, there is no special approach by which drilling safety profes￾sionals may rationally evaluate the actual human factor risk control and

accordingly select appropriate risk control measures for a given drilling

process. Therefore, it is necessary to create a special method for quanti￾ficational evaluation of the drilling human factor risks, so that strategi￾cally measures can be taken to control the risks associated with drilling

activities.

Many accident investigation techniques and other methods used by the

petroleum industry today list a set of underlying human-related causes and

subsequent improvement suggestions. Norsok (2001) defines an accident

as “an acute unwanted and unplanned event or chain of events resulting in

loss of lives or injury to health, environment or financial values.” Another

way of putting it is energy gone astray (Hovden et al., 2012). What differen￾tiates two accidents is primarily the type and amount of energy astray. The

knowledge of accidents is important in order to operate with efficient risk

management and preventative work. In order to increase the knowledge of

accidents, they must be investigated. Accident investigation models aim to

simplify complex events to something tangible and understandable.

2.1.4 Stacked Tools

Stacked tool is defined as “if a tool is lost or the drillstring breaks, the

obstruction in the well is called junk or fish.” It cannot be drilled through if

there is stacked tool. The preventive measure is to educate the crew. Special

grabbing tools are used to retrieve the junk in a process called fishing.

In extreme cases, explosives can be used to blow up the junk and then the

pieces can be retrieved with a magnet.

Wellbore debris is responsible for many of the problems and much of

the extra costs associated with producing wells, especially in extreme water

depths and highly deviated holes. Even a small piece of debris at the right 

place at the wrong time can jeopardize well production. For this reason,

debris management has become a major concern for oil and gas producers.

Considering rig rates and completion equipment costs, debris removal is

moving into the realm of risk management.

A clean wellbore is not only a prerequisite for trouble-free well testing

and completion. It also helps ensure optimum production for the life of the

well. Debris left in the wellbore can ruin a complex, multimillion-dollar

completion. It can prevent a completion from reaching total depth. It will

never reach an optimum production level. These issues are pushing the

industry to create reliable, efficient systems for quickly ridding of wellbores

harmful debris and larger pieces of junk.

If a tool is lost or the drillstring breaks, the obstruction in the well is

called junk or fish. It cannot be drilled through. Special gripping tools are

used to retrieve the junk through a process called fishing. In extreme cases,

explosives can be used to blow up the junk and then the pieces can be

retrieved with a magnet.

During the stacked tool problem, the remedial measures are run the

junk basket, run basket with collapsible teeth (e.g., “Poor Boy” Basket),

and run magnet.

2.1.4.1 Objects Dropped into the Well

Despite utmost care, wrenches, nut-bolts, rocks or any objects (i.e., rather

than fishing objects) are inadvertently dropped into the borehole while

drilling. In addition, the LS-100 (The LS-100 is a small, portable mud rotary

drilling machine manufactured by Lone Star Bit Company in Houston,

Texas) is often operated near its design limits with a high degree of struc￾tural stress on the drill stems and tools. This will encounter unexpected

layers of very soft sand or filter or hard rock. As a result, it can cause caving

or tool breakage. Sometimes, the entire drillpipe can be lost in the hole.

If objects are dropped into the borehole after the final depth has been

reached, it may be possible to leave them there and still complete the well.

If this is not the case, it may be possible to make a “fishing” tool to set-up

on the lost gear. For example, if a length of well screen falls down the bore￾hole, it may be possible to send other sections down with a pointed tip on

the end and “catch” the lost casing by cramming the pointed end forcefully

into it. These types of “fishing” exercises require innovation and resource￾fulness suitable to the circumstances. While this task may appear to be

routine, there is no single “right” way of conducting this operation. If sedi￾ments have caved in on top of the drill bit or other tools, circulation should

be resumed in the hole and the fishing tool placed over the lost equipment. 

If the lost tools/bits/drillpipes are not critical, it is best to avoid retrieval

efforts, instead, resorting to just changing the location somewhat and start￾ing to drill a new hole. Even if the equipment is important, it is still best to

start drilling at a new location while others try to retrieve it since consid￾erable time can be spent on retrieval and there is a low likelihood of suc￾cess. The decision to retrieve can be set aside while continuing the drilling

operation.

2.1.4.1.1 Case Study

An employee was operating a workbasket inside the substructure while

doing various tasks in preparation to nipple down the annular. He had used

a 5-pound (2.3 kg) shop hammer several minutes prior to the incident in

order to break out the annular hydraulic lines. After he completed the task,

he dropped the hammer to the bottom of the man-basket. While he was

moving throughout the basket to arrange the BOP handler (chain hoist),

the 5-pound (2.3 kg) hammer was accidentally “kicked” out of the basket.

It was “launched” approximately 10 feet (3 meters) down to the driller’s

side of the substructure where it struck another employee on the hard hat.

The impact of the hammer created a pinch point between the hard hat and

his safety glasses, thus resulting in a laceration below his left eyebrow.

Cause of the incident: i) The hammer was not secured or tethered after use,

ii) employees were standing in the “line of fire” watching the employee in

the work basket complete his work, iii) the employee operating the work

basket did not call a “stop task” to move other employees out of the “danger

area”, and iv) poor housekeeping procedures in the work basket (i.e., the

hammer and other items were not placed or secured properly).

Corrective Actions: To address this incident, this company did the follow￾ing: i) employees were reminded of the importance of tethering / securing

any tools when working overhead, even when working in a work basket, ii)

personnel were instructed to discuss “line of fire” for any work, especially

when the potential for a dropped or “launched” object existed, iii) person￾nel were instructed to discuss application of Stop Work Authority (obliga￾tion) and were reminded that SWA includes stopping and asking other

personnel / bystanders to move from a “danger area”, and iv) the JSA /

Work Plan for operating in a work basket must be reviewed/revised to

include the importance of keeping the lift basket orderly (i.e., housekeep￾ing must be maintained).

It is noted that this case study was taken from AIDC website for study

purposes.

Fishing Operations

Fishing is the process of removing equipment that has become stuck or

lost in the wellbore. Its name derives from a period in which a hook, simi￾lar to fishing hooks, used to be attached to a line before lowering into the

borehole in order to extract the lost item. From that period onward, any

object dropped or stuck in a well that interferes with its normal operations

is called a fish and is targeted for removal from the well. The operation of

removing these objects is called a “fishing job”. Typically, in drilling vocab￾ulary, a fishing job is simply called ‘fishing’. The fish, or lost object, is classi￾fied as tubular (e.g., drillpipe, drill collars, tubing, casing, logging tools, test

tools, and tubing) or miscellaneous (e.g., bit cones, small tools, wire line,

chain, hand tools, tong parts, slip segments, and junk). Industry-wide, 25%

of drilling costs may be attributed to fishing. Fishing jobs are classified into

three categories: i) open hole fishing: when there is no casing in the area

of fishing, ii) cased hole fishing: when the fish is inside the casing, and iii)

thru-tubing: when it is necessary to fish through the restriction of a smaller

pipe size (tubing). Figure 2.6 shows the basic fishing tools including the

spear and socket, each with milled edges. Using nails and wax, an impres￾sion block helps determine what is stuck downhole. Anything that goes in

the hole can be left there and anything with an outside diameter less than

that of the hole can be dropped in it. After a fishing job begins, any and/or 

all fishing tools in the hole may themselves have to be removed by fishing.

So precautions should be taken.

The most causes of fishing jobs are i) twist-off, ii) sticking of the drill￾string, iii) bit and tool failures, and iv) foreign objects such as hand tools,

logging instruments, and broken wire line or cable lost in the hole. When

the preparation for a fishing job becomes necessary in an uncased hole,

one has to find out as much as possible about the situation before taking

action. In addition, the questions that need to be answered before fishing

operation are: i) what is to be fished out of the hole?, ii) is the fish stuck, or

is it resting freely?, iii) if stuck, what is causing it to be stuck?, iv) what is

the condition in the hole?, v) what are the size and condition of the fish?,

vi) could fishing tools be run inside or outside the fish?, vii) could other

tools be run through the fishing assembly that is to be used?, viii) are there

at least two ways to get loose from the fish if it cannot be freed?

Any fishing operation in an open or cased hole involves the usage and

operation of the following tools and accessories: i) spears and overshoots,

ii) internal and external cutters, iii) milling tools, iv) taps and die collars,

v) washover pipe – a) washover pipe overshot (releasable), b) washover

pipe back-off connector, and c) washover pipe drill collar spear, vi) acces￾sories – a) bumper jar, b) mechanical jar, c) hydraulic jar, d) jar accelera￾tor, e) hydraulic pull tool, and f) reversing tool, vii) safety joints, viii) junk

retrievers, ix) impression blocks. In a fishing job involving the drillstring,

the operator can often ascertain whether or not the lost drillpipe is stuck

in the hole by determining what happened just before it was lost. The stuck

pipe problems will be discussed in Chapter 7.

History of the Fishing: During early years of petroleum well drilling,

spring-pole cable tools were used instead of rotary drilling. Drillers used a

hook connected by hemp rope to the pole in order to recover drilling tools

inadvertently left in the wellbore. The physical and operational similarity

to the angler’s art resulted in the process of lost tool recovery being named

“fishing” (Moore 1955). The Prud’homme family plantation near Bermuda,

Louisiana, displays in its museum a set of rotary drilling equipment, includ￾ing fishing tools, used to dig three water wells in 1823. A French engineer

designed this equipment, and an African technician built it (Brantly, 1961).

Both rotation and reciprocation were powered by a fifteen-man prime

mover. Most fishing tools were designed for cable-tool drilling and for

production operations, then adapted for rotary drilling. Fishing tools have

been necessary ever since commercial drilling operations were started.

It is generally accepted that fishing operations account for 25% of drilling

costs worldwide (Short, 1995). Since fishing is a non-routine procedure, 

all personnel connected with a given operation are more likely to commit

operational error. Study on fishing art is needed which can be beneficial for

engineering, geological, operational, and accounting staff.

Conventional Fishing: In oil-field operations, fishing is the technique of

removing lost or stuck objects from the wellbore. The term fishing is taken

from the early days of cable-tool drilling. At that time, when a wireline

would break, a crew member put a hook on a line and attempted to catch

the wireline to retrieve, or “fish for,” the tool. Necessity and ingenuity led

these oil-field fishers to develop new attraction. The trial-and-error meth￾ods of industry’s early days built the foundation for many of the catch tools

used currently. A fish can be any number of things, including: (i) stuck pipe,

(ii) broken pipe, (iii) drill collars, (iv) bits, (v) bit cones, (vi) dropped hand

tools, (vii) sanded-up or mud-stuck pipe, (viii) stuck packers, or (ix) other

junk in the hole. There are some conventional fishing jobs such as: (i) wash

overs, (ii) overshot runs, (iii) spear runs, (iv) wireline fishing, (v) stripping

jobs, and (vi) jar runs which are among many fishing techniques developed

to deal with the different varieties of fish.

Some care should be taken when an object is pulled out of the hole with

most tools and fishing so it does not create a swelling action. Care should

also be taken to prevent pulling into a tight place such as a key seat so you

cannot go back down. Fishing jobs are very much a part of the planning

process in drilling and workover operations. Drill operators will often bud￾get for fishing with the increasing cost of rig time and depth, and due to

more complicated wells. When a fishing operation is planned for a work￾over, the operator will work closely with a fishing-tool company to design a

procedure and develop a cost estimate. Taking into account the probability

of success, the cost of a fishing job has to be less than the cost of redrilling

or sidetracking the well for it to make economic sense.

Figure 2.7 shows the bit components such as bit cones, nozzles, and

other pieces of junk which are typically small enough to be retrieved by a

magnet (Figure 2.8) or junk basket (Figure 2.9). The most common fish is

bit cones. Cones are run off for several reasons: i) poor solids control, ii)

poor hydraulics, iii) improper bit choice, iv) operator error such as drop￾ping or pinching, v) manufacturing defects, vi) excessive time on bottom,

vii) inordinately abrasive lithology, and viii) unsuspected junk on bot￾tom. Magnet is used to retrieve small pieces of ferrous material from the

hole. Some junk magnets have circulating ports that enable cuttings to be

washed away from the junk. In general, circulation of drilling fluid lifts

the junk off-bottom. Beneath the tool joint, mud velocity decreases as the

annulus grows wider. This decrease in mud velocity allows the junk to 

use a wedding band (collar clamp). Make-up torque failures can be avoided

by the use of a gauge. Wear can be found by inspection, collar clamp loss

stopped by adequate supervision, and harmonic stress can be minimized

by proper rotary speed. Poor shopping is a matter that is harder to deal

with, and it seems to be on the increase. As shown in Figure 2.10, excessive

torque can cause a drillstring to part downhole. Here (left), the drillpipe

has twisted off beneath the tool joint. Even thick-walled drill collars may

be subjected to wear and fatigue.

Figure 2.11 shows the overshot assembly, which is divided into three

segments. The top sub connects the overshot to workstring. The bowl has 

a tapered helical design to accommodate a grapple, which holds the fish in

place. The guide helps position the overshot onto the fish.

Fishing for Bit Cones, Tong Dies, and Small Tools: When the bit is on the

bank and the small junk is in the hole, several choices present themselves.

If the hole is mudded up and a fishing magnet is immediately available, go

directly back to bottom and try to catch the fish. If not mudded up, or if a

magnet is not on location, run a used bit below two junk subs and attempt to

bust and wash by the junk. If no hole can be made, mud up and call for a junk

basket. When it arrives or mud up is complete, round trip placing the junk

basket on bottom. Cut hole equivalent to the length of the junk basket and

withdraw from the hole. The junk basket is similar to a core barrel and will

retain the fish and core by means of retainer springs. If the fish is recovered,

drill ahead. If not, run a used bit and attempt to drill and wash by them. If no

hole can be made, mill the junk with a concave mill. The concavity will center

the cones or tools and bust them up. The two junk subs should remain in the

string until the iron has been accounted for. Especial care should be taken to

remove all metal junk from the hole before a diamond or P.D.C. bit is run.

Milling: Besides the dressing of fish tops, mills are used to grind up junk

(Figure 2.12). They are also used to cut casing windows, to ream out

casing, to cut fishing necks, and to mill up tubulars that cannot be fished

(e.g., drillpipe cemented in the hole). Clustered tungsten carbide such as

Klustrite is used to face mills. Larger particles are used for milling larger

objects. Too much weight will knock the larger particles off the mill face.

High speed and high weight certainly do not invariably yield high rate of

penetration. One or two magnets should be used in the possum belly and

cleaned continuously while milling. Cuttings are known to build up in the

stack, which should be inspected and cleaned as needed.

Fishing Equation: The decision to fish or not must be weighed

against a need to preserve the wellbore, recover costly equipment or 

  

comply with regulations. Each choice is fraught with its own costs, risks

and repercussions. Before committing to a specific course of action, the

operator must consider a number of factors: i) well parameters: proposed

total depth, current depth, depth to top of the fish and daily rig operating

costs, ii) Lost-in-hole costs: the value of the fish minus the cost of any

components covered by tool insurance, iii) fishing costs: daily fee for

fishing expertise and daily rental charges for fishing tools and jars, and

iv) fishing timetable: time spent mobilizing fishing tools and personnel,

estimated duration of the fishing job and the probability of success.

Earlier research has derived equations to determine how long fish￾ing operations can be economically justified. These were based on Gulf

of Mexico wells. The work presented here investigates the economics of

fishing in the North Sea. The effort was justified by an early BP task force

review, which showed that the Gulf of Mexico and the North Sea have sig￾nificantly different sticking problems. In the Gulf of Mexico, most stuck

pipe is due to differential sticking. Spotting a diesel based pill is considered

to be the most successful remedy. In the North Sea, mechanical sticking is

the major problem and the best remedial action is less obvious. Spotting a

pill is only one option among a number of possible options. In 1984, Keller

et al. (1984) introduced the concept of Economic Fishing Time (EFT).

They developed an equation to calculate the time at which the cost of fish￾ing becomes equal to the cost of an immediate side-track. They considered

that probability of successful fishing can be estimated as:

The fishing times an EFT were characterized using the Weibull distribution

which has the following probability density function (PDF)

Economic Considerations: There is an important trade-off that must be

considered during any fishing operation. Although the actual cost of a

fishing operation is normally small compared to the cost of the drilling

rig and other investments in support of the overall drilling operation, if

a fish or junk cannot be removed from the borehole in a timely fashion,

it may be necessary to sidetrack (i.e., directionally drill around the

obstruction) or drill another borehole. Thus, the economics of the fishing 

operation and the other incurred costs at the well site must be carefully

and continuously assessed while the fishing operation is underway. It is

very important to know when to terminate the fishing operation and get

on with the primary objective of drilling a well. In such case, Eq. (2.1) can

be rewritten in terms of number of days (Df

) that should be allowed for

fishing operation as:

Optimum Fishing Time (OFT): OFT is an economically attractive alter￾native to EFT because it attempts to minimize total costs. When fishing

operations are started, there are only two possible outcomes: getting free or

failing to free. The costs associated with these outcomes are:

OFT is the point at which the gradient becomes zero which can be

derived from Eq. (2.11) as:

Problems Associated with Drilling Operations

Introduction

The rotary drilling rig and its components are the major vehicle of modern 

drilling activities. In this method, a downward force is applied on the drill 

bit that breaks the rock with both downward force and centrifugal force, 

thereby forming the pivotal part of an effective drilling operation. The con￾ventional practice in the oil industry is to use robust drillstring assembly 

for which large capital expenses are required. However, during any drill￾ing operation, numerous challenges are encountered, each of which can 

have significant impact on the time required to complete a drilling project. 

Often, one problem triggers another problem and snowballing of problems 

occurs, thus incapacitating the drilling process. In this process, there is no 

‘small’ or ‘large’ problem, as all problems are intricately linked to each other, 

eventually putting safety and environmental integrity in jeopardy. Any such 

impact has immeasurable financial impact beyond short-term effects on the 

‘time loss’. This chapter discusses some of the generic drilling problems, such 

as H2

S-bearing zones and shallow gas, equipment and personnel, objects 

dropped into the well, resistant beds encountered, fishing operations, 

 junk retrieve operations, and twist-off. It identifies the key areas where we 

encounter drilling problems, their root causes, and solutions related to drill￾ing methods. In well planning, the key to achieving objectives successfully 

is to design drilling programs on the basis of anticipation of potential hole 

problems rather than on caution and containment. The desired process is 

to preempt any problem, because drilling problems can be very costly after 

they occur. The most prevalent drilling problems include pipe sticking, lost 

circulation, hole deviation, pipe failures, borehole instability, mud contami￾nation, formation damage, hole cleaning, H2

S-bearing formation and shal￾low gas, and equipment and personnel-related problems.

2.1 Problems Related to Drilling 

Methods and Solutions

2.1.1 Sour Gas Bearing Zones

During drilling and workover operations, the consequences of leaks with 

sour gas or crude may be devastating. Drilling H2

S-bearing formations poses 

one of the most difficult and dangerous problems to humans and equipment. 

Personnel can be injured or even killed by relatively low concentrations of 

H2

S in a very short period of time. Equipment can experience terrible fail￾ure due to H2

S gas-induced material failure. This risk depends primarily 

on the H2

S content with the formation fluids, formation pressure, and the 

production flow rate. This information is used to assess the level of risk from 

the presence of H2

S. In addition, if this risk is known or anticipated, there 

are very specific requirements to abide by in accordance to International 

Association of Drilling Contractors (IADC) rules and regulations. All infor￾mation will ultimately lead to the requirement for special equipment, layout, 

and emergency procedures for drilling and/or workover operations.

2.1.1.1 How to Tackle H2

S

The presence of H2

S can be anticipated from previous data on the field, or 

from the region. For a wildcat, all precautionary measures should be taken, 

following IADC rules, as if H2

S will be encountered. The following steps 

and the plans should be followed while H2

S gas is encountered.

i) Planning of operations

A study should be done on geological and geographical 

information of the area. This study should include history

      of adjacent wells in order to predict the expected area where 

H2

S may be encountered. Information should be obtained 

and taken into consideration about the area and known field 

conditions, including temperatures, pressures, proposed 

well depth, and H2

S concentrations.

A mud program should be drawn up which will provide dif￾ferent pressures expected to be encountered. However, H2

S 

scavenger should also be included to reduce the reaction of 

H2

S on the drillstring and related equipment to control the 

processing of H2

S at surface. Normal practice is to maintain 

a higher than normal pH (i.e., 10.5–11) and to treat the mud 

with a suitable scavenger as soon as dissolved sulphides are 

analyzed. The contamination of water-based muds due to 

H2

S can deteriorate the mud properties at a fast rate. It is 

advisable to keep the mud moving with immediate treat￾ment to maintain the desired properties.

Maintaining a high pH or using a scavenger is not suitable 

to safeguard drilling equipment against H2

S, since in a kick 

situation the wellbore may become partially/fully devoid 

of drilling fluid, thus reducing or eliminating the ability to 

contact drillstring and wellhead and BOP components with 

scavenger. H2

S resistant materials should be considered 

for this well control condition. The BOPs must be made to 

NACE specifications that conform to the presence of H2

S.

Prior to reaching the H2

S-bearing formations, the emergency 

equipment (blowout preventer, degasser, etc.) and response 

procedures should be tested in an exercise that simulates a kick.

Wind direction should be considered for the layout of equip￾ment such as shale shakers, choke manifold, mud tanks, and 

particularly vents such as flare lines, degasser vents, mud-gas 

separator vents, and diverter lines. Wind socks on the site or 

platform should enable identification of upwind assembly 

points. For offshore operations, each assembly point should 

allow easy evacuation from the installation.

ii) Drilling equipment selection

Equipment should be selected after consideration of metallurgical proper￾ties, thus reducing the chances of failure from H2

S-induced corrosion. The 

following recommendations are to be followed for H2

S designated wells:

a. BOP stack

Metallic materials for sour-gas service should be employed.

                                         All pressure containing components of the BOP stack with 

the potential to be exposed to H2

S should be manufactured 

with the material, which meets the standard of the NACE 

MR-01-75 and API RP 53. These components include annu￾lar preventer, rams, drilling spools, the hydraulic operated 

choke line valve, and gaskets, etc.

Non-metallic materials for sour service.

Non-metallic materials for sour service should conform to 

API RP 53, Section 9. A.8. Fluoropolymers, such as Teflon 

or Ryton and fluoroelastomers, such as viton or Kalrez are 

acceptable materials.

Welding should conform to sour-gas service.

Where welding is required for component fabrication, the 

welding and the heat affected zone of the welded compo￾nents should possess essentially the same chemical and 

physical properties as the parent metals of the subcompo￾nents. These include hardness properties and impact prop￾erties where appropriate. The welding is also required to be 

free of linear defects such as cracks, undercutting, and lack 

of fusion.

Sour-gas service identification should be performed.

Components should be marked in a manner that shows their 

suitability, under NACE MR-01-75, for sour service.

Identification stamping procedures as detailed in NACE 

MR-01-75, Section 5.4 should be followed.

Transportation, rigging up, and maintenance should con￾form to sour-gas requirements.

During transportation, rigging up, and maintenance of BOP 

stacks, operating practices should be used to avoid cold tem￾perature that might induce hardening of equipment compo￾nents. Material control for replacement parts for the BOP 

stack should have specifications and quality control equiva￾lent to the original equipment.

b. Flange, bonnet cover, bolting, and nut material

Each of these intended for H2

S use should meet require￾ments prescribed in API Specification 6A section 1.4 (14th

edition).

c. Choke manifold

Piping, flanges, valves, fittings, and discharge lines (flare 

lines) used in the composition of the choke manifold 

                  assembly should contain metals and seals in accordance 

with API RP 53.

d. Degassers/mud-gas separator

The degasser should be capable of effectively removing 

entrained gases from contaminated drilling fluid circu￾lated back to the surface. The vent outlet on the degasser 

should be extended so that the extracted gas can be routed 

to a remote area for flaring or connected into the choke flare 

line. A mud-gas separator is used to extract gas containing 

H2

S from drilling fluids. This separator should be tied into a 

vent line for burning so that it cannot release the gas into the 

atmosphere close to the rig side area.

e. Flare lines

Flare lines should be installed from the degasser, choke 

manifold, and mud-gas separator according to API RP 49. 

All flare lines should be equipped with the means for con￾stant or automatic ignition.

f. Drillpipe

Because of the direct contact of drillpipe with H2

S in the 

wellbore where various temperature and pressure conditions 

exist, the lower grades of pipe should be used so as to mini￾mize hydrogen embrittlement or sulphide stress corrosion 

cracking (SSCC). Means of control to minimize hydrogen 

embrittlement and SSCC of drillpipe can also be found in 

API RP 49. Consideration may be given to the use of a drill￾string equipped with special tool joint material.

g. Monitoring equipment

Each drilling rig operating in an area known or suspected to 

produce H2

S gas should have adequate H2

S monitoring and/or 

detection equipment. It is recommended that this equipment 

should be installed 350 meters and/or one week prior to drilling 

into the H2

S zone. H2

S concentrations should be continuously 

monitored at strategic sampling positions, e.g., shale shaker, 

mud ditch, mud tank area, etc., and results transmitted both to 

the driller’s console and to the toolpusher’s office. Audible and 

visible alarms should indicate both locally and remotely when 

H2

S concentration reaches 10 ppm. Sulphide tests should be 

carried out as part of the mud testing program in areas where 

hydrogen sulphide gas (H2

S) might be encountered.

                           Mud logging unit

The mud logging unit and equipment should be located 

away from the shaker tank and a minimum of 50 meters dis￾tance should be kept from the well head.

i. Venting system

Weatherized rigs equipped with partitions permanent in 

nature should be provided with a ventilation system suffi￾cient for the removal of accumulated H2

S.

iii) Training

When drilling in an area where H2

S gas might be encountered, training of 

personnel must be carried out on the subject matter. The action should be 

taken in the event of alarm, the use of safety equipment, and escape proce￾dures whatever the likelihood of encountering H2

S. Emergency procedures 

must be practiced regularly, using realistic emergency drills.

iv) H2

S contingency planning

A contingency plan should be drawn up when H2

S is anticipated while 

drilling. The contingency plan should be developed prior to the com￾mencement of drilling operations and should include the following:

Information on the physical effects or exposure to H2

S and 

sulphur dioxide (SO2

).

Safety and training procedures should be followed and safety 

equipment will be used.

Procedures for operations when the following conditions 

exist:

pre-alarm condition

moderate danger to life

extreme danger to life

Responsibilities and duties of personnel for each operating 

condition.

Briefing areas or locations for assembly of personnel during 

extreme danger condition should be designated. At least two 

briefing areas should be established on each drilling facility. 

Of these two areas, the one upwind at any given time is the 

safe briefing area.

Evacuation plan should be in place and well rehearsed.

Plan must be in place as to who would notify the authority 

and at what stage of the incident.

    A list of emergency medical facilities, including locations 

and/or addresses and telephone numbers must be in place.

In a pre-spud meeting, the company drilling supervisor 

should review the drilling program with the drilling contrac￾tor and service contractors, outlining each party’s responsi￾bility in drilling a well, where H2

S may be encountered.

All personnel should be fully trained and the H2

S-related 

equipment should be in place when drilling at 350 meters 

above and/or one week prior to encountering a hydrogen 

sulphide zone.

Available literature should be carefully studied before draw￾ing up H2

S procedures. Recommended references are: API 

RP49 “Safe Drilling of Wells Containing Hydrogen Sulphide.”

2.1.2 Shallow Gas-Bearing Zones

Shallow gas-bearing zone is defined as any hydrocarbon-bearing zone, 

which may be encountered at a depth close to the surface or mudline. In 

generally, it is not possible to close in and contain a gas influx from a shal￾low zone because weak formation integrity may lead to breakdown and 

broaching to surface and/or mudline. This situation is particularly hazard￾ous when drilling operations continue from a fixed installation or jack￾up rig. Shallow gas-bearing zones are usually in a pressured condition. 

However, the effective increase in pore pressure due to gas gradient can 

lead to underbalance when a shallow gas zone is first penetrated.

Shallow gas may be encountered at any time in any region of the world. 

The only way to control this problem is that we should never shut in the 

well. It is also needed to divert the gas flow through a diverter system at 

the BOP. High-pressure shallow gas can be encountered at depths as low 

as a few hundred feet where the formation-fracture gradient is very low. 

The danger is that if the well is in shut-in condition, formation fracturing 

is more likely to occur. This will result in the most severe blowout problem, 

and ultimately an underground blow.

The identification and avoidance of shallow gas will be a principal objec￾tive in well planning and site survey procedures. All drilling programs shall 

contain a clear statement on the probability and risk of encountering shal￾low gas. This will be based on seismic survey and interpretation together 

with offset geological and drilling data. For onshore operations, consid￾eration should be given for carrying out shallow seismic surveys in areas 

of shallow gas risk. In the absence of such surveys, assessment should be 

based on the exploration seismic data, historical well data, and the geo￾logical probability of a shallow gas trap. If shallow 

gas is a likelihood at 

                            

the proposed drilling location, a shallow gas plan specific to company 

and the drilling contractor must be prepared prior to spudding the well. 

Special consideration should be given to: crew positions, training, evacu￾ation plan, and emergency power shut down. For offshore operations, the 

presence of shallow gas can be extremely hazardous especially if no spe￾cific plan of action is prepared prior to spudding of the well. The driller 

will be instructed in writing on what action should be taken if a well kick 

should be noticed while drilling. The problem of drilling a shallow hole is 

that normal indications of a kick are not reliable. For example, penetration 

rates vary tremendously, and mud volume is continuously being added to 

the active system. The most reliable indicator is the differential flow sen￾sor. Due to the difficulties of early detection and the depth of shallow gas 

reservoirs, reaction time is minimal. In such case, extreme caution, and 

alertness are required.

2.1.2.1 Prediction of Shallow Gas Zone

Although the location of gas pockets is difficult to predict, high-resolution 

seismic data acquisition, processing and interpretation techniques increase 

the reliability of the shallow gas prognosis. Therefore, surveys are to be 

recommended. Well proposals should always include a statement on the 

probability of encountering shallow gas, even if no shallow gas is pres￾ent. This statement should not only use the “shallow gas survey”, but also 

include an assessment drawn from the exploration seismic data, historical 

well data, the geological probability of a shallow cap rock, coal formations, 

and any surface indications/seepages. The shallow gas procedures based 

on the shallow gas statement in the well proposal, and practical shallow 

gas procedures should be prepared for that particular well. The following 

guidelines should be adhered to avoid influx and kick: i) avoid shallow 

gas where possible; ii) optimize the preliminary shallow gas investigation; 

iii) the concept of drilling small pilot holes for shallow gas investigation 

with a dedicated unit is considered an acceptable and reliable method of 

shallow gas detection and major problem prevention; iv) surface diverter 

equipment is not yet designed to withstand an erosive shallow gas flow for 

a prolonged period of time. Surface diverters are still seen as a means of 

“buying time” in order to evacuate the drilling site; v) diverting shallow 

gas in subsea is considered to be safer as compared to diverting at surface, 

vi) dynamic kill attempt with existing rig equipment may only be success￾ful if a small pilot hole (e.g., 9 7/8” or smaller) is drilled and immediate 

pumping at maximum rate is applied in the early stage of a kick; and vii) 

riserless top hole drilling in floating drilling operations is an acceptable 

and safe method.

                     Identification of Shallow Gas Pockets

While drilling at shallow depth in a normally pressured formation, no 

indication of a gas pocket can be expected other than higher gas readings 

in the mud returns. Since the overbalance of the drilling fluid at shallow 

depths is usually minimal, pressure surges may cause an underbalanced 

situation which could result in a kick. Therefore, every attempt should be 

made to avoid swabbing. Some definitions are used to describe the risk 

in shallow gas assessment, such as i) high: an anomaly showing all of the 

seismic characteristics of a shallow gas anomaly, that ties to gas in an offset 

well, or is located at a known regional shallow gas horizon, ii) moderate: 

an anomaly showing most of the seismic characteristics of a shallow gas 

anomaly, but which could be interpreted not to be gas and, as such rea￾sonable doubt exists for the presence of gas, iii) low: an anomaly showing 

some of the seismic characteristics of a shallow gas anomaly, but that is 

interpreted not to be gas although some interpretative doubt exists, and 

iv) negligible: either there is no anomaly present at the location or anomaly 

is clearly due to other, nongaseous, causes.

There are two factors that make shallow gas drilling a difficult challenge. 

First, unexpected pressure at the top of the gas-bearing zone, most often 

due to the “gas effect” dictated by zone thickness and/or natural dip, can 

be significant. This pressure is usually unknown, seismic surveys being 

often unable to give an idea either about thickness or in-situ gas concen￾tration. In more complex situations, deep gas may migrate upwards along 

faults. For example, the influx in Sumatra could not be stopped even with 

10.8 ppg mud at very shallow depth because the bit had crossed a fault 

plane. Second, low formation fracture gradients are a predominant factor 

in shallow gas operations.

These two factors result in reduced safety margin for the driller. Minor 

hydrostatic head loss (e.g., swabbing, incorrect hole filling, cement slurry 

without gas-blocking agent), any error in mud weight planning (e.g., gas 

effect not allowed for), or any uncontrolled rate of penetration with sub￾sequent annulus overloading will systematically and quickly result in well 

bore unloading. Shallow gas flows are extremely fast-developing events. 

There is a short transition time between influx detection and well unload￾ing, resulting in much less time for driller reaction and less room for 

error. Poor quality and reliability of most kick-detection sensors worsen 

problems.

Previous history has disclosed the magnitude of severe dynamic loads 

applied to surface diverting equipment, and consequent high probability of 

failure. One of the associated effects is erosion, which leads to high poten￾tial of fire hazards and explosion from flow impingement on rig facilities.

The risk of cratering is a major threat against the stability of bottom￾supported units. As it is impossible to eliminate them (i.e., most shallow 

gas-prone areas are developed from bottom supported units), emphasis 

should be put on careful planning and close monitoring during execution.

2.1.2.3 Case Study

Description: Four new wells were drilled at an offshore platform with cas￾ing on the surface section in batch-drilling mode. 13⅜-in casing shoes 

were set as per plan in a range from 1,800 to 2,000 ft for the four wells 

(Figure 2.1). All the risk-control measures resulting from the risk-analysis 

exercise were implemented when drilling the section. In the first well, 

logging-while-drilling tools were included in the bottomhole assemblies 

(BHA). There were no indications of a shallow gas zone.

Drilling Plan: The plan was to use seawater for the four wells because the 

drilling fluid was for the casing-drilling operation.

Drilling Operations and Potential Problems: Pumping sweeps were 

performed at every connection to help with hole cleaning. Following the 

plans, the first of the four wells was drilled with seawater and sweeps. Soon 

after drilling out of the conductor, fluid losses were experienced.

First Aid Remedy and Consequences: Loss-control material was pumped 

downhole and drilling continued, expecting the coating effect to contribute 

in building a mudcake that would eventually cease the losses. Drilling-fluid 

      

losses decreased but did not stop until section total depth (TD) was reached

and casing was cemented. In addition, when drilling the first well, accurate

position surveys were taken, which required several attempts at every sur￾vey station. These attempts were due to the poor data transmission from

measurement-while-drilling (MWD) tools. The result was an increase of

10% non-productive (e.g., off-bottom) drilling time compared with other

wells. The problems with the MWD transmission also affected the resistiv￾ity and gamma ray data that were planned to provide early information of

any shallow gas accumulation. As a result, it was difficult to interpret the

real-time data provided by the logging tool.

Final Solution: The engineering team decided to change the drilling fluid

from seawater to a low-viscosity mud. They were expecting to build a better

mudcake and to improve fluid-loss control. To improve the MWD transmis￾sion, a low telemetry rate was set on the tools to reduce the time required to

take a survey. These measures contributed to drill the next three wells with

no drilling-fluid losses and with no delays from a lengthy survey procedure.

Lesson Learned: The seawater-and-sweeps system was replaced with a low

viscosity water-based-mud drilling fluid after the problems that had been

faced in the first well. As a result, the three remaining wells were drilled

with improved drilling practices. Severe fluid losses were not observed, and

the quality of the telemetry signal improved substantially. A possible expla￾nation for the problems with the use of seawater are: i) drilling fluid does

not have the required properties to create a consistent mudcake around

the wellbore wall, ii) the use of seawater also induced turbulent flow, which

may give good hole cleaning but would increase the hole washouts in shal￾low formations. An enlarged wellbore and the inability to create an opti￾mum mudcake might have eliminated the coating effect and the expected

improvements in terms of loss control. Problems with the telemetry-signal

quality were attributed to the telemetry rate setup and the noise created by

the drilling fluid. Setting a low telemetry rate in the MWD proved useful

for adapting to the particular condition of casing drilling, where the inter￾nal diameter in the drillstring experiences great variations, such as 2.8 in.

at the BHA and 12.6 in. for the rest of the string.

Personal Experiences: The following are the field experience for diverter

procedures while drilling a top hole. At first sign of flow,

1. Do not stop pumping.

2. Open diverter line to divert/close diverter (both functions

should be interlocked).
                        

            Increase pump strokes to a maximum limit (DO NOT 

exceed maximum pump speed recommended by the manu￾facturer or maximum pressure allowed by relief valve).

4. Switch suction on mud pumps to heavy mud in the reserve 

pit. Zero stroke counter.

5. Raise alarm and announce emergency using the PA system 

and/or inform the rig superintendent. Engage personnel to 

look for gas (Jack-up).

6. If the well appears to have stopped flowing after the heavy 

mud has been displaced stop pumps and observe well.

7. If the well appears to continue to flow after the heavy mud 

has been pumped, carry on pumping from the active system 

and prepare water in a pit for pumping and/or consider pre￾paring pit with heavier mud. When all mud has been con￾sumed, switch pumps to water. Do not stop pumping for as 

long as the well continues to flow.

General Guidelines for Drilling Shallow Gas: The following guidelines 

shall be adhered to while drilling:

Consideration shall be given to drilling a pilot hole with the 

8 ½” or smaller bit size when drilling explorations wells. The 

BHA design shall include a float valve and considerations 

should be given to deviation and subsequent hole opening. 

The major advantages of a small pilot hole are: i) the Rate of 

Penetration (ROP) will be controlled to avoid overloading 

the annulus with cuttings and inducing losses, ii) all losses 

shall be cured prior to drilling ahead. Drilling blind or 

with losses requires the approval from head of operations, 

iii) pump pressure shall be closely monitored and all con￾nections (on jack-up) shall be flow checked, iv) pipe shall be 

pumped out of hole at a moderate rate to prevent swabbing.

General Recommended Drilling Practices in Shallow Gas Areas: 

Common drilling practices, which are applicable for top hole drill￾ing in general and diverter drilling in particular are summarized below. 

Recommendations are made with a view to simplify operations, thereby 

minimizing possible hole problems.

A pilot hole should be drilled in areas with possible shallow 

gas, because the small hole size will facilitate a dynamic well 

killing operation.

      The penetration rate should be restricted. Care should be 

taken to avoid an excessive build-up of solids in the hole that 

can cause formation breakdown and mud losses. Drilling 

with heavier mud returns could also obscure indications of 

drilling through higher pressured formations. The well may 

kick while circulating the hole cleaning. Restricted drilling 

rates also minimize the penetration into the gas-bearing for￾mation which in turn minimizes the influx rate. An excessive 

drilling rate through a formation containing gas reduces the 

hydrostatic head of the drilling fluid, which may eventually 

result in a flowing well.

Every effort should be made to minimize the possibility of 

swabbing. Pumping out of the hole at optimum circulating 

rates is recommended for all upward pipe movements (e.g., 

making connections and tripping). Especially in larger hole 

sizes (i.e., larger than 12”), it is important to check that the 

circulation rate is sufficiently high and the pulling speed is 

sufficiently low to ensure that no swabbing will take place. 

A top drive system will facilitate efficient pumping out of 

hole operations. The use of stabilizers will also increase the 

risk of swabbing; hence the minimum required number of 

stabilizers should be used.

Accurate measurement and control of drilling fluid is most 

important in order to detect gas as early as possible. Properly 

calibrated and functioning gas detection equipment and a 

differential flowmeter are essential in top hole drilling. Flow 

checks are to be made before tripping. At any time, a sharp 

penetration rate may increase or tank level anomaly may be 

observed. When any anomaly appears on the MWD log, it 

is recommended to flow check each connection while drill￾ing the pilot hole in potential shallow gas areas. Measuring 

mud weight in and out, and checking for seepage losses are 

all important practices which shall be applied continuously.

A float valve must be installed in all BHAs which are used 

in top hole drilling in order to prevent uncontrollable flow 

up the drillstring. The float valve is the only down-hole 

mechanical barrier available. The use of two float valves in 

the BHA may be considered in potential shallow gas areas.

Large bit nozzles or no nozzles and large mud pump liners 

should be used to allow lost circulation material (LCM) to be 

pumped through the bit in case of losses. Large nozzles are 

                                    also advantageous during dynamic killing operations, since 

a higher pump rate can be achieved. For example, a pump 

rate of approximately 2,700 l/min at 20,000 kPa pump pres￾sure can be obtained using a 1300–1600 HP pump with 3 

14/32” nozzles installed in the bit. By using 3 18/32” noz￾zles, the pump rate can be increased to around 3,800 ltr/min 

at 20,000 kPa. The use of centre nozzle bits will increase the 

maximum circulation rate even further and also reduces the 

chance of bit balling.

Shallow kick-offs should be avoided in areas with prob￾able shallow gas. Top hole drilling operations in these areas 

should be simple and quick to minimize possible hole prob￾lems. BHAs used for kick-off operations also have flow 

restrictions which will reduce the maximum possible flow 

through the drillstring considerably. A successful dynamic 

well killing operation will then become very unlikely

                                                      

Tarner’s Prediction Method

 Tarner (1944) suggested an iterative technique for predicting cumulative oil produc￾tion Np and cumulative gas production Gp as a function of reservoir pressure. The

method is based on solving the MBE and the instantaneous GOR equation simulta￾neously for a given reservoir pressure drop from a known pressure Pi 1 to an

assumed (new) pressure Pi. It is accordingly assumed that the cumulative oil and gas

production has increased from known values of (Np)i 1 and (Gp)i 1at reservoir

pressure Pi 1 to future values of (Np)i and (Gp)i at the assumed pressure Pi. To

simplify the description of the proposed iterative procedure, the stepwise calculation

is illustrated for a volumetric saturated oil reservoir; however, this method can be

used to predict the volumetric behavior of reservoirs under different driving

mechanisms.

Tarner’s method was preferred to Tracy and Muskat because of the differential

form of expressing each parameter of the material balance equation by Tracy. Also,

Tarner and Muskat method use iterative approach in the prediction until a conver￾gence is reached.

Furthermore, a first approach of the Cumulative Oil Production is needed before

the calculation is performed; a second value of this variable is calculated through the

equation that defines the Cumulative Gas Production, as an average of two different

moments in the production life of the reservoir; this expression, as we will see, is a

function of the Instantaneous Gas Oil Rate, then we need also to calculate this value

in advance from an equation derived from Darcy’s law, this is a very important

relationship since it is strongly affected by the relative permeability ratio between oil

and gas. Finally, both values are compared, if the difference is within certain

predefined tolerance, our first estimate of the Cumulative Oil Production will be

considered essentially right, otherwise the entire process is repeated until the desire

level of accuracy is reached (Tarner 1944).

Tarner’s Prediction Algorithm

Step 1: Select a future reservoir pressure Pi below the initial (current) reservoir

pressure Pi 1 and obtain the necessary PVT data. Assume that the cumulative oil

production has increased from (Np)i 1 to (Np)i. It should be pointed out

that (Np)i 1 and (Gp)i 1 are set equal to zero at the bubble-point pressure

(initial reservoir pressure).

Step 2: Estimate or guess the cumulative oil production (Np)i at Pi.

Step 3: Calculate the cumulative gas production (Gp)i by rearranging the MBE to

give:

Tracy Prediction Method

Tracy (1955) developed a model for reservoir performance prediction that did not

consider oil reservoirs above bubble-point pressure (undersaturated reservoir) but

the computation starts at pressures below or at the bubble-point pressure. To use this

method for predicting future performance, it is pertinent therefore to select future

pressures at desired performance. This means that we need to select the pressure step

to be used. Hence, Tracy’s calculations are performed in series of pressure drops that

proceed from a known reservoir condition at the previous reservoir pressure (Pi 1)

to the new assumed lower pressure (Pi). The calculated results at the new reservoir

pressure becomes “known” at the next assumed lower pressure. The cumulative gas,

oil, and producing gas-oil ratio are calculated at each selected pressure, so the goal is

to determine a table of Np, Gp, and Rp versus future reservoir static pressure.

Tracy’s Prediction Algorithm

Step 1: Select an average reservoir pressure (Pi) of interest

Step 2: Calculate the values of the PVT functions ɸo, ɸg & ɸw where

Schilthuis Prediction Method

Schilthuis develop a method of reservoir performance prediction using the total

produced or instantaneous gas-oil ratio which was defined mathematical as: