Newbuild offshore drilling rig tilts at Singapore Shipyard

Extracts from Straits Times 4th Dec2012

About 90 workers were injured when a jackup rig at Singapore Shipyard tilted to one side on Monday.

Among them, 22 were quite seriously injured and one was in a critical condition. The rest suffered minor injuries.

The accident happened at one of Singapore shipyard worksite at Tanjong Kling Road.

Preliminary findings showed that the three-legged jackup rig tilted to one side after the jack-up mechanism of one of the legs failed to work.

Officers from MOM's Occupational Safety and Health Inspectorate responded immediately and were investigating the accident on-site .

Thousands of workers were said to be working on the rig at the time of the accident, according to Chinese Shin Min Daily. Some workers said they heard loud bangs and some cables snapped.

According to the Chinese paper, some tried to escape by jumping off the rig into the sea. A worker who spoke to the evening daily said he decided to swim to safety because the gangway bridge linking the rig to the shore were crowded with workers.

Preliminary findings showed that the three-legged jackup rig tilted to one side after the jack-up mechanism of one of the legs failed to work.

 

 

A failed braking system might had caused the oil rig to tilt to one side. Providing an update on the incident to the media, the shipyard initial investigations showed the braking system on one of the movable legs of the rig had failed, causing the platform to slide down the leg on that side. Load tests run on the rig just a day before the accident had shown the three legs of the rig could bear a load of some 9000 tonnes each. The yard is now trying to stabilize the rig so that it can investigate the cause of the brake failure.

 

 

How Rig Tilted

Above Courtesy of Straits Times

 
Earlier, Singapore Minister for Manpower praised evacuation efforts at the yard, saying he was encouraged that all the workers on the rig had been evacuated within 20 minutes.

The new JU3000N design is the result of the combined development efforts of Jurong Shipyard, Noble and Friede and Goldman in creating an enlarged hull that will offer more operational benefits, including ergonomic and efficient accommodation layout, increased deck space and placement of equipment that will allow the crew to efficiently and safely carry out maintenance duties. On completion, the new rigs are capable of operating in waters of 400 feet and drilling depths of 30,000 feet.

The rigs are suitable for operations in many challenging environments, including high temperature areas such as the Middle East and in the North Sea.


General information about a typical offshore drilling jackup :-

The conventional jack-up design has three vertical legs, each leg normally being constructed of a triangular or square framework.

Jack-up basic design involves numerous choices and variables. Typically the most important variables may be listed as stated below.

Support Footing -

The legs of a jack-up are connected to structure necessary to transfer the loadings from the leg to the seafloor. This structure normally has the intended purpose to provide vertical support and moment restraint at the base of the legs. The structural arrangement of such footing may take the following listed forms;

-gravity based (steel or concrete),

-piled

-continuous foundation support, e.g. mat foundations

-individual leg footings, e.g. spudcans (with or without skirts).

Legs -

The legs of a jack-up unit are normally vertical, however, slant leg designs also exist. Design variables for jack-up legs may involve the following listed considerations ;

-number of legs

-global orientation and positioning of the legs

-frame structure or plate structure

-cross section shape and properties

-number of chords per leg

-configuration of bracings

-cross-sectional shape of chords

-unopposed, or opposed pinion racks

-type of nodes (e.g. welded or non-welded (e.g. forged) nodes)

-choice of grade of material, i.e. utilisation of extra high strength steel

Method of transferring loading from (and to) the deckbox to the legs

The method of transferring the loadings from (and to) the deckbox to the legs is critical to design of the jack-up. Typical design are ;

-utilisation and design of guides (e.g. with respect to ; number, positioning, flexibility, supporting length and plane(s), gaps, etc.)

-utilisation of braking system in gearing units

-support of braking units (e.g. fixed or floating systems)

-utilisation of chocking systems

-utilisation of holding and jacking pins and the support afforded by such.

Deckbox -

The deckbox is normally designed from stiffened panel elements. The shape of the deck structure may vary considerably from being triangular in basic format to rectangular and even octagonal. The corners of the deckbox may be square or they may be rounded. Units intended for drilling are normally provided with a cantilever at the aft end of the deckbox, however, even this solution is not without exception and units with drilling derricks positioned in the middle of the deckbox structure are not unknown.

Below are some news from the web as of 13th Dec 2012, that Dalian Shipbuilding Industry Corporation Offshore and Shanghai Waigaoqiao Shipbuilding have received notifications from F&G to stop work on the jacking systems of eight JU2000E units, according to news sources.  Work has been put on hold on six jack-ups being built at Dalian under contracts awarded by Norwegian rig giant Seadrill and Houston-based drilling start-up Prospector Offshore Drilling.  

CIMC Raffles is building two F&G JU2000E jack-ups, including one for new drilling start-up Varada HVR, but it has not received any correspondence from F&G to halt work on the units.

The jacks for the JU2000E are believed to be from South Korea manufacturer where the JU3000N are sourced from a Chinese supplier. All jacks ordered by Chinese yards are believed to be fabricated under the joint efforts of the South Korean manufacturer and Chinese yard operator ZPMC, which bought F&G for $125 million in 2010.

Below video downloaded with courtesy of youtube which shows typically the sequence of jacking the rig up and down to test the smooth functioning of jacking system.

 

Refer below links in my previous posts for more of drilling jack-up relevant information  :-

http://kimwhye.blogspot.sg/2011/05/jackup-terminologies-and-types.html

http://kimwhye.blogspot.sg/2010/10/insights-of-jack-up-drilling-rig.html

http://kimwhye.blogspot.sg/2011/09/more-on-drilling-jack-up-and-some-of.html

RIG BOOK

More about Drilling Rig components

The main functions of the offshore rotary drilling rig are as follows:

- Penetrating operations. The drill bit breaks down rock at the bottom-hole by the rotation under the weight. The rotating force of the rotary table is transmitted through the drill string to the bit. Some portion of the weight of drill collars is applied to the bit as the bit weight to push the bit against the rock.

- Hoisting operations. The drill string with the bit is lowered and lifted by the hoisting system, eg. Drawworks. The casing is also handled by the hoisting system.

- Conditioning and circulating the drilling fluids by the circulation system, eg. the mud pumps providing the high pressure mud to the well bore and return of the mud is being processed, filtered and clean through the shakers. The drill cuttings are contained into containers and shipped back to shore.

- Preventing the formation fluids from entering into the wellbore and controlling them to prevent collapse of the well.  More serious consequence, after the collapse of well, will be kicks and subsequently well blowout. The highly potential gas contained in the mud return will likely causes ignition of the gas on board and creating serious fire during the blowout.

The drilling fluids, conventionally known as muds, have lots of important functions in the offshore rig drilling. Main functions are as follows:

- Removal of cuttings from the bottom of the hole to the surface. Cuttings are separated from the mud at the shale shaker. The cuttings and samples of the mud may be further analyzed to study geological properties of the rocks penetrated, and to find out the indication of oil and gas in the formations.

- Controlling hydraulic pressure in the hole by adjusting the density of the mud to prevent collapse of the wall of the borehole, and to contain formation fluids in the formations.

- Cooling and lubricating the bit and the drill stem.

In the conventional system of the offshore drilling, the rotary table rotates the drill stem, but the down-hole mud motor and the top drive device are applied to rotate the bit in the directional and horizontal well drilling, or to improve operations in the vertical well drilling. The technical advancement of the measurement-while-drilling tools (MWD) and the logging-while-drilling tools (LWD) has contributed to the almost real-time acquisition of the down-hole information. Owing to these tools it has become easy to drill directional and horizontal wells.

Terminology :-

Casing: Steel pipe lowered into a hole drilled and bonded to formation by cement to keep the well safe.

Christmas tree: An assembly of valves installed at the top of a well to control the flow of oil and gas after the well has been completion.

Drill stem: A drilling assembly of tubulars, to rotate a bit at the bottom of the hole from the surface, which comprises of the kelly,the drill pipe, and drill collars.

Riser: Any pipe with the fluid flow upward in it. In offshore drilling a marine riser system is used to establish a connection between the rig and the seabed. In offshore petroleum production, production riser systems extend from the seabed to the deck of the production platform.

Well completion: A series of work to make a well ready for production after it has been drilled and tested. Although there are wide variations, it typically involves installing the production (deepest) casing, perforating the casing and installing tubing and the Christmas tree. A subsea completion or subsea-completed well is a well that sits entirely, that is, up to its Christmas tree, on the seabed.

RIG Components Guide

Insights into Subsea deepwater operation

Floaters in deep water normally use dynamic positioning system to keep the position above the well, and make use of a guideline-less drilling system. Drilling from a floater also means vertical floater movement (heave) due to sea waves. Introduction of a heave compensation system reduces the relative movement between the drill string and the sea floor. This heave system improves the drillbit performance and reduces wear between the drill string and the well. Most of the time the drill string is free to move relative to the well. That may however not be the case during well testing and landing of the BOP, meaning that the system is vulnerable to heave compensation failures.

Drilling can start when the bit located at the bottom of the drill string reaches the seabed or the bottom of the hole. Drilling requires weight on bit (WOB), bit rotation and mud circulated through the drill string and out through nozzles in the bit. The mud controls the bit temperature, provides bottom hole cleaning and transports cuttings to surface through the annulus. The driller and mud logger must have full volum control of the mud (volume going in and volume coming out of the well) for early detection of kick or lost circulation.

Running the subsea BOP and marine riser consist of :-
 
The upper part of the subsea BOP is called the lower marine riser package (LMRP) and contains (from the top):

Flex joint

Annular preventer

Hydraulic connector

The lower part of the subsea BOP is called the BOP stack and contains (from the top):

Annular preventer

Blind shear ram

Pipe rams

Wellhead connector

The BOP stack also have a more kill and choke line 'outlets' controlled by choke and kill valves.

Choke and kill valves

Typical diagram of a subsea BOP system :-



The LRMP also includes two redundant subsea control pods (one is back-up) with hydraulic pilot valves which are connected to a common power fluid supply at the floater. The hydraulic pilot valves are activated by a signal from the floater (hydraulically or electrically) to open and close and thus open and close the LMRP and BOP valves. The pods are normally retrievable. Subsea accumulators are located on the LMRP and the BOP and applied to reduce the closing time for the valves. The hydraulic oil return from the valves are normally vented to the sea.

The subsea BOP's are also frequently equipped with back-up control systems like:

Acoustic system
Auto disconnect system
Autoshear system
Deadman system
Emergency disconnect system (EDS)
ROV intervention system

The back-up control system is is typically used when the primary control system has failed during an emergency sistuation. Several scenarios, like accidental riser disconnect, means that the hydrostatic wellhead pressure will drop and that formation the fluid may starts to flow from the reservoir. The flow of formation fluids often starts slowly but increases rapidly. Fast response from the back-up system is therefore highly important. It is also important that the back-up system is independent of the primary system. The auto disconnect, autoshear, deadman and emergency disconnect systems are automatically actuated back-up systems. Note that the auto disconnect, autoshear and deadman need to be armed to be operational. Any back-up system should be reliable and not too complex so that the rig crew does not fear using the system.

The LMRP is connected on the top of the subsea BOP at the cellar deck, which is the lower deck on the drilling rig. The LRMP/BOP stack assembly is functional tested and skidded on rail-beams to the well center of the cellar deck where there is a large hole in the deck called the moon pool. The LMRP is connected to the marine riser coming down from the rotary table in the drill floor above. The LMRP/BOP stack assembly and the marine riser are then run through the moon pool, the splash zone, further through the sea, landed and hydraulically latched on the wellhead by the wellhead connector. The BOP is then overpull- and pressure tested.

A floater will always move up and down and sideways due to waves and sea currents. The floater will thus also move up and down and sideways relative to the marine riser, since the marine riser is fixed to the wellhead at the seabed. After being tested, the marine riser is disconnected from the topdrive and from now on kept in tension and heave compensated through a dedicated riser heave and tension system. The marine riser will have an upper assembly which is fixed to the floater, consisting of (from the top):

Diverter

Flex joint

Male part of the slip joint

This upper assembly will move with the rig and relative to the rest of the riser. The slip joint is a telescopic joint that allows movement up and down while maintaining a hydraulic seal. The flex joint allows sideways movements. There is also a flex joint on the riser bottom just above the BOP. The diverter has an annular preventer that can be used to control returning fluids that have escaped the BOP and entered the riser. E.g., it may be difficult to detect gas escaping the BOP when drilling in deep waters with a high hydrostatic pressure at the BOP, since the expansion of gas is restricted. The gas may however expand in the riser due to reduced pressure. This will be detected by increased mud return at the surface. This gas will be stopped by the annular preventer and diverted to flare. A simple illustration of the floater after the marine riser is in place is given in figure 1.

One of the annular preventers is closed if a kick is detected. The well must be killed by circulating heavy mud into the well. To make this possible there is a kill and choke line from the BOP and up to the platform. These lines are connected outside the riser. Kill mud is circulated into the well through the drillpipe if possible and the return through the choke line with 'outlet' below the annular preventer. If not, kill mud has to be pumped into the well through the kill line. The return is directed to the choke and kill manifold. The gas may be separated in the poorboy degasser or burned without separation. The diverter on the top of the riser may also be used in a kick situation.

Subsea operation1

Well completions

Once an oil/gas well is being drilled and commercially viable quantities of oil/gas are present for extraction, the well must be 'completed' to allow for the flow of petroleum out of the formation and up to the surface. This process includes strengthening the well hole with casing, evaluating the pressure and temperature of the formation and installing proper equipment to ensure an efficient flow of oil/gas out of the well.

Condensate wells are wells that contain natural gas, as well as a liquid condensate. This condensate is a liquid hydrocarbon mixture that is often separated from the natural gas either at the wellhead, or during the processing of the natural gas. It is important to remember that natural gas, being lighter than air, will naturally rise to the surface of a well. Because of this, in many natural gas and condensate wells, lifting equipment and well treatment are not necessary.

Completing a well consists of a number of steps: installing the well casing, completing the well, installing the wellhead, and installing lifting equipment or treating the formation should that be required.

Installing well casing is an important part of the drilling and completion process. Well casing consists of a series of metal tubes installed in drilled hole. Casing strengthens the sides of the well hole, ensures that no oil or natural gas seeps out of the well hole as it is brought to the surface. A good deal of planning is necessary to ensure that the proper casing for each well is installed. The type of casing used depends on the subsurface characteristics of the well, including the diameter of the well and the pressures and temperatures experienced throughout the well. The diameter of the well hole depends on the size of the drill bit used. In most wells, the diameter of the well hole decreases the deeper it is drilled, leading to a type of conical shape that must be taken into account when installing casing.

There are five different types of well casing. They include:

-Conductor Casing

-Surface Casing

-Intermediate Casing

-Liner String

-Production Casing

-Conductor Casing

Conductor casing is installed first, usually prior to the arrival of the drilling rig. The hole for conductor casing is often drilled with a small auger drill, mounted on the back of a truck. Conductor casing is usually no more than 20 to 50 feet long. It is installed to prevent the top of the well from caving in and to help in the process of circulating the drilling fluid up from the bottom of the well. Onshore, this casing is usually 16 to 20 inches in diameter, while offshore casing usually measures 30 to 42 inches. The conductor casing is cemented into place before drilling begins.

Surface casing is the next type of casing to be installed. It can be anywhere from a few hundred to 2,000 feet long, and is smaller in diameter than the conductor casing. When installed, the surface casing fits inside the top of the conductor casing. The primary purpose of surface casing is to protect fresh water deposits near the surface of the well from being contaminated by leaking hydrocarbons or salt water from deeper underground. It also serves as a conduit for drilling mud returning to the surface, and helps protect the drill hole from being damaged during drilling. Surface casing, like conductor casing, is cemented into place.

Intermediate casing is usually the longest section of casing found in a well. The primary purpose of intermediate casing is to minimize the hazards that come along with subsurface formations that may affect the well. These include abnormal underground pressure zones, underground shale, and formations that might otherwise contaminate the well, such as underground salt-water deposits. In many instances, even though there may be no evidence of an unusual underground formation, intermediate casing is run as insurance against the possibility of such a formation affecting the well.

Liner strings are sometimes used instead of intermediate casing. Liner strings are commonly run from the bottom of another type of casing to the open well area. However, liner strings are usually attached to the previous casing with 'hangers', instead of being cemented into place.

Production casing, alternatively called the 'oil string' or 'long string,’ is installed last and is the deepest section of casing in a well. This is the casing that provides a conduit from the surface of the well to the petroleum-producing formation. The size of the production casing depends on a number of considerations, including the lifting equipment to be used, the number of completions required, and the possibility of deepening the well at a later time.

Installing Well Casing

Well casing is a very important part of the completed well. In addition to strengthening the well hole, it provides a conduit to allow hydrocarbons to be extracted without intermingling with other fluids and formations found underground. It is also instrumental in preventing blowouts, allowing the formation to be 'sealed' from the top should dangerous pressure levels be reached.

Well completion commonly refers to the process of finishing a well so that it is ready to produce oil or natural gas. In essence, completion consists of deciding on the characteristics of the intake portion of the well in the targeted hydrocarbon formation. There are a number of types of completions, including:

Open Hole Completion

Conventional Perforated Completion

Sand Exclusion Completion

Permanent Completion

Multiple Zone Completion

Drainhole Completion

Well Head

It is the philosophy that during the drilling, - testing, completion water injection and workover of an oil or gas well, any work undertaken should be executed in such a manner that:

1. Loss of human life and injury to crewmembers shall be avoided

2. Pollution of the surrounding environment shall be avoided

3. Loss of rig and damage to equipment shall be avoided.

If all of the aforementioned conditions are fulfilled then the economic and ecological result shall be successful. It is also the philosophy :

1. That detection and controlling a kick takes a team effort from all members of the rig crew. Each member must be completely familiar with his duties so that any well control operation can proceed smoothly and efficiently

2. To maintain all well control equipment in first class condition and ready for use whenever required

3. To ensure that all personnel directly involved in well control situation shall be educated to a standard that ensures complete understanding of any situation that may arise.

However, for any other Well Control procedures and guidelines to take precedence over the ones shown in the ”Well Control Manual”, the following is a must and can not be deviated:

1. At least two tested Safety Barriers shall be present in drilling and producing wells. If for some reason only one Safety Barrier is present, all activities shall cease until two Safety Barriers are reestablished

2. All Safety Barriers must be tested in accordance with approved procedures, or as specified in the programme prepared for the specific operation

3. Activity Typical Independent Barriers:

• Drilling: A sufficient amount of mud or fluid of adequate density to control the well bore pressure; certified and tested BOP stack dressed with suitable rams; unperforated, cemented and pressure tested casing or liner; tested downhole plug; back pressure valve (BPV)

• Casing: A sufficient amount of mud or fluid of adequate density to control the well bore pressure; certified and tested BOP stack dressed with suitable Casing rams

• Snubbing: BOP stack; back pressure valve in the work string; independent safety shear seal immediately on top of Christmas tree; wireline set plug

• Production: Christmas tree; surface controlled subsurface safety valve (SCSSV); downhole plug

• Wireline: Christmas tree valves; wireline BOP; wireline lubricator.

For Jack-Ups Operating under the API Standard

Frequency :  -  All blow out prevention components that may be exposed to well pressure shall be function and pressure tested as follows:

1. When installed

2. After casing has been run, cemented and BOP nippled-up; but prior to drilling out of the shoe

3. Prior to production testing or completion

4. At any time the integrity of the BOP and casing becomes suspect

5. Function test BOP with low manifold pressure, flush kill - and choke lines each week, unless well operations prevent testing

6. Or at least every 21 days (API RP 53 Third Edition section 17.3.3), unless well operations prevent testing. Well operations that may prevent testing are stuck pipe and kick control. If a period greater than 21 days has elapsed since the previous test the reason for the test postponement must be entered on the drilling report.


Well Control

Offshore Drilling Mud solids control

The drilling fluid called mud only looks like mud. Actually, it is a complex mixture of water or oil, clays, and chemicals. It's composition and properties have been carefully studies and tested. The study is closely associated with chemistry, math, and physics. The term mud refers technically to a suspension of solids in water or oil, while drilling fluid is a broader term including air, gas, water, and mud.

Drilling fluid is the more appropriate term for including all types of fluid used, but term mud is preferred the field for in naming the most common type. The drilling mud basically perform the following functions:-

1. Removal of Cuttings

2. Control Formation Pressure

3  Prevent Caving

4. Caking off Per. Formations

5. Suspension of Cuttings

6. Release of Cuttings

7. Cooling & Lubrication

8. Formation Damage

9. Formation Evaluation

10. Corrosion

Common types of mud used are :

1. Polymer Muds - incorporating generally long-chain, high-molecular-weight polymers are utilized to either encapsulate drill solids to prevent dispersion and coat shales for inhibition increasing reducing loss inhibition, or for viscosity and fluid loss.

Various polymers are available for these purposes, including acrylamide,cellulose and natural gum-based products. Frequently, inhibiting salts, such as KCl or NaCl, are used to provide greater shale stability. These systems normally contain a minimum amount of bentonite. Most polymers have temperature limits below 300°F, but under certain conditions, may be used in wells with appreciably higher BHTs.

2. Oil-based muds. Oil-based systems are used for a variety of applications, where fluid stability and inhibition are necessary, such as high-temperature wells, deep holes, and where sticking and hole stabilization are problems. They consist of two types of systems:

a. Invert emulsion muds are water-in-oil emulsions, typically with calcium chloride brine as the emulsified phase and oil as the continuous phase. They may contain as much as 50% brine in the liquid phase. Relaxed, invert emulsion muds are a “relaxed” emulsion, and have lower electrical stabilities and higher fluid-loss values. Concentration of additives and brine content/salinity are rheological, filtration and varied to control emulsion stability.

b. Oil-based muds are formulated with only oil as the liquid phase and are often used as coring fluids. Although these systems pick up water from the formation, no additional water or brine is added. All oil systems require higher additional gelling agents for viscosity. Specialized oil-based mud additives include: emulsifiers and wetting agents (commonly fatty acids and amine derivatives) for high molecular weight viscosity; high-molecular-soaps; surfactants; amine treated organic materials; organo clays and lime for alkalinity.

3. Synthetic muds. Synthetic fluids are designed to mirror oil-based mud performance, without the environmental hazards. Primary types of synthetic fluids are esters, ethers poly alpha olefins and isomerized alpha olefins They are esters, ethers, olefins. environmentally friendly, can be discharged offshore, and are non-sheening and biodegradable.

Mud weight, or density, is the weight per unit volume of the mud. With simple water base mud a mud, density can be regarded as measure of the suspended solids.

Excessive solids can:
􀂾 cause wear on pumps bits drill strings; and 􀂾retard penetration rates;
􀂾cause a thick filter cake to be deposited on permeable formations;
􀂾cause fluids loss to the formation;
􀂾causes unnecessary work for the pump, having to push unwanted weight in the circulating fluids.


Solids Control

Knowing to "Kill" an offshore well....

DIVERTER PROCEDURE WHILE DRILLING ON A FIXED RIG

Where shallow casing strings or conductor pipe are set, fracture gradients will be low. It may be impossible to close the BOP on a shallow gas kick without breaking down the formation at the shoe. If a shallow gas kick is taken while drilling top hole then the kick should be diverted.

Drilling shallow sand too fast can result in large volumes of gas cut mud in the annulus and cause the well to flow, also fast drilling can load up the annulus increasing the mud density leading to lost circulation and if the level in annulus drops far enough then well may flow.

When drilling top hole a diverter should be installed and it is good practice to leave the diverter installed until 13 3/8" casing has been run.

SHUT-IN PROCEDURE WHILE DRILLING ON A FLOATING RIG

1. Stop drilling

2. Pick drill string off bottom to predetermined shut in point. Stop the mud pump. If flow is excessive begin next step immediately and strip drill string to close in predetermined point once well is secured.

3. Close upper annular and open choke line fail-safe valves.

4. Ensure well is shut in and begin recording shut in pressures.

5. Pass word to the OIL COMPANY REP and DRILLING CONTRACTOR REP of the well condition.

6. Pick up circulating kill assembly if it is to be used.

7. Check space out then close upper pipe rams.

8. Adjust BOP closing pressure as required for stripping and landing drill string on upper pipe rams.

9. Close hang off rams with reduced pressure. Reduce annular pressure.
(Note: there will be pressure trapped between annular and rams)

10. Land drill string on upper pipe rams, adjust BOP closing pressure and down weight on upper pipe rams to prevent the hydraulic effect on the drill string

11. Close wedge locks and adjust compensator to support drillstring weight to BOP plus 20,000 lbs.

12. Bleed off any trapped pressure between the annular and rams.

13. Open annular.

14. Complete recording of shut in pressure build up and pit gain.

15. Decide kill programme. 

SHUT-IN PROCEDURE WHILE TRIPPING ON A FLOATING RIG

1. Set slips below top tool joint.

2. Install full opening safety valve, torque connection and close safety valve.

3. Close upper annular and open choke line fail-safe valves.

4. Ensure well is shut in and begin recording shut in pressures.

5. Pass word to the OIL COMPANY REP and SENIOR DRILLING CONTRACTOR REP of the well condition.

6. Make up the top drive or circulating kill assembly.

7. Open safety valve.

8. Complete recording of shut in pressure build up and pit gain.

9. Decide kill programme.

KILL METHODS - GENERAL

The objective of the various kill methods is to circulate out any invading fluid and circulate a satisfactory weight of kill mud into the well without allowing further fluid into the hole. Ideally this should be done with the minimum of damage to the well.

If this can be done, then once the kill mud has been fully circulated around the well, it is possible to open up the well and restart normal operations.

Generally, a kill mud which just provides hydrostatic balance for formation pressure is circulated.

This allows approximately constant bottom hole pressure which is slightly greater than formation pressure to be maintained as the kill circulation proceeds because of the additional small circulating friction pressure loss.

After circulation, the well is opened up again and the mud weight may be further increased to provide a safety or trip margin.

CONSTANT BOTTOM HOLE PRESSURE KILL METHODS

There are three ‘constant bottom-hole pressure’ kill methods in common use today which are:

• Driller’s Method
• Wait & Weight Method (also known as the ‘Engineer’s Method’)
• Concurrent Method

These three techniques are very similar in principle, and differ only in respect of when kill mud is pumped down.

Shutting a Well