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 conventional practice in the oil industry is to use robust drillstring assembly
for which large capital expenses are required. However, during any drilling 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 drilling 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 contamination, formation damage, hole cleaning, H2
S-bearing formation and shallow 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 failure 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 information 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 different 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 treatment 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 equipment 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 properties, 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 annular 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 components should possess essentially the same chemical and
physical properties as the parent metals of the subcomponents. These include hardness properties and impact properties 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 conform to sour-gas requirements.
During transportation, rigging up, and maintenance of BOP
stacks, operating practices should be used to avoid cold temperature that might induce hardening of equipment components. Material control for replacement parts for the BOP
stack should have specifications and quality control equivalent to the original equipment.
b. Flange, bonnet cover, bolting, and nut material
Each of these intended for H2
S use should meet requirements 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 circulated 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 constant 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 minimize 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 drillstring 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 distance 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 sufficient 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 procedures 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 commencement 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 contractor and service contractors, outlining each party’s responsibility 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 drawing 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 shallow zone because weak formation integrity may lead to breakdown and
broaching to surface and/or mudline. This situation is particularly hazardous when drilling operations continue from a fixed installation or jackup 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 objective in well planning and site survey procedures. All drilling programs shall
contain a clear statement on the probability and risk of encountering shallow gas. This will be based on seismic survey and interpretation together
with offset geological and drilling data. For onshore operations, consideration 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 geological 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, evacuation plan, and emergency power shut down. For offshore operations, the
presence of shallow gas can be extremely hazardous especially if no specific 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 sensor. 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 present. 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 successful 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 reasonable 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 concentration. 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 subsequent 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 unloading, 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 potential of fire hazards and explosion from flow impingement on rig facilities.
The risk of cratering is a major threat against the stability of bottomsupported 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 casing 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
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and casing was cemented. In addition, when drilling the first well, accurate
position surveys were taken, which required several attempts at every survey 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 resistivity 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 transmission, 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 explanation 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 shallow formations. An enlarged wellbore and the inability to create an optimum 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 internal 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 manufacturer 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 preparing pit with heavier mud. When all mud has been consumed, 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 connections (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 drilling 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 formation 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 drilling 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 pressure can be obtained using a 1300–1600 HP pump with 3
14/32” nozzles installed in the bit. By using 3 18/32” nozzles, 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 probable shallow gas. Top hole drilling operations in these areas
should be simple and quick to minimize possible hole problems. 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
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