BASIC DRILLING TECHNOLOGY

LASER PETROLEUM GEOSCIENCES CENTREFEBRUARY 2013 – LAGOS BATCH THREECOMMITMENT TO ACADEMIC AND

INDUSTRIAL EXCELLENCE 2

TABLE OF CONTENTS• Overview of Oilwell Drilling• Drilling Rig Selection• Rotary Drilling Rig Systems• Well Planning, Procedure and Costs• Formation Pressure• Formation Evaluation• Mechanics of Drilling a Hole• Drilling Problems• Drilling Contracts• Drilling Cost Analysis• Introduction to Directional Drilling• Glossary of Terms

COMMITMENT TO ACADEMIC AND INDUSTRIAL EXCELLENCE 3

OVERVIEW OF OILWELL DRILLING

• Oilwells are being drilled to depths of almost six miles in the continuing search for the lifeblood of the modern world, fossil fuels.

• The first oilwell in the U.S. was a 69-foot hole drilled by Edwin Drake in Pennsylvania in 1859.

• More than 20,000 wells have now been drilled offshore.

• Ocean-floor completions have been made below 1,500 feet of water, and capability exists to complete such wells in 4,500 feet of water or deeper.



• Rotary drilling rig power has increased from 1 horsepower (hp) a hundred years ago to the 10,000-hp equipment now used offshore.

• The essential functions of rotary drilling rigs are hoisting, rotating, circulating and controlling and powering.

• The rigs consist of portable machinery and structures that can be quickly dismantled, moved, and reassembled on a new location.

• Rigs can be mounted on wheels or built on barges and ships to facilitate the transportation of equipment from rig site to rig site.



OVERVIEW OF OILWELL DRILLING• Rotary drill pipe is special upset-end pipe with thread and shoulder end connections (called tool joints).

• The pipe is carefully designed to withstand the tensile, torsional, collapse and burst stresses of rotary drilling.

• Drill collars are heavy-walled steel tubes placed at the bottom of the drill string to provide weight for the bit and hold the drill string in tension.


• Rotary drill bits may be roller cone, diamond or drag types.

• Roller cone bits may be of milled-tooth construction or have tungsten carbide inserts for teeth. They may have plain, lubricated or journal-type bearings.

• Diamond bits have various configurations, but generally they feature fairly large stones held in a matrix that allows the diamonds to be pressed into the bottom of the hole when weight is applied.

• High-pressure fluid streams (jets) are used on roller cone and drag bits to facilitate the drilling process developed by applied weight and rotation.



• The hydraulic system of a drilling rig provides a stream of high-velocity fluid to clean the bottom of the hole and thus to improve the drilling process.

• The fluid also sweeps the cuttings out of the well and up to the surface.

• Drilling fluid may be made of water-base or oil-base mud, water, air or gas.

• Water-base muds are the most common drilling fluids; they are made up of water, clay, inert solids, and chemicals in order to obtain the desired properties of viscosity, gel strength and density.



• Straight-hole drilling is actually a misnomer, since most so-called straight holes are usually within 20 to 30 off vertical.

• They do not change direction abruptly, and they do not have sharp edges or bends in the line of the hole from top to bottom.

• Large-diameter drill collars and properly placed reamers and stabilizers make it possible to drill a straighter hole than an assembly of small-diameter drill collars without stabilizers or centralizers.



• Directional drilling uses the principles of straight-hole drilling to form a wellbore that changes its angle in a desired direction according to a predetermined plan.

• Various types of deflection tools are used to establish the direction and amount of angle away from vertical.

• Downhole measurements and survey instruments are used to determine the direction and amount of angle away from vertical.



• Fishing is a drilling operation that involves recovering small equipment, drill pipe, drill collars, or whole strings of pipe that may be lost or such in an oil-well.

• The operation requires various catch tools, fishing string accessories and wireline devices to survey and separate frozen strings of pipe.

• Blowout prevention involves using the entire hydraulic system of a rotary rig to control formation pressure.



• Preventing oil-well blowouts requires recognizing the preliminary signs of a blowout, utilizing the blowout preventers (BOPs) and circulating fluid of the required density to contain the formation pressure.

• Well logging is used to evaluate oil or gas zones in a well.

• Electric logs can make estimates of what kind and how much production will occur.



• Open-hole logs can give readings of lithology, porosity and hydrocarbon content.

• Acoustic and radioactivity logs make accurate assessments of porosity and estimations of permeability.

• Cased-hole logs can obtain much of the same information through the casing.



• Casing and cementing are the first operations required to complete the well after the hole has been drilled, logged, and tested.

• The purpose of casing is to prevent the wall of the hole from caving in and to provide a means of extracting petroleum if the well is produced.

• Several strings of casing (heavy pipe) are set before a well reaches final depth, but the production string is the casing set from the underground reservoir to the surface.



• The production string may be casing set from total depth of the surface, or it may be a liner set at some intermediate depth.

• Cementing is an operation that prevents fluid flow between the formation and the casing.

• The cement is pumped around the casing to seal the annulus, to protect the casing from corrosion and to prevent pollution of freshwater formations near the surface.



• Well testing involves an early evaluation of the productive capacity of a well.

• It is usually performed in open hole before casing is set.

• Well testing may involve wireline formation test tools, drill stem testing or formation evaluation based on core samples, electric log data, or other methods of down-hole sampling.



• Well completion is the process of setting casing and providing a passageway for fluids to flow to the surface.

• Completing a well may involve setting a screen liner or perforating the production pipe.

• Running and setting a packer and tubing may also be involved in completing a well.

• Deep wells with extremely high pressures usually require special equipment to handle completion tasks.



HISTORY OF OILWELL DRILLING Commercial Drilling for oil and gas started in the US.

The first oil well was drilled by Drake using cable tools in 1859 to 65 feet in Pennsylvania, United States.

However, this method did not originate in the United States but is believed to have been used in China before being used in the US.


ROLE OF DRILLING IN OILFIELD

DEVELOPMENT


OILWELL DRILLING PERSONNEL


PROSPECT SELECTION In case of Production wells, prospect

selection is identified by the need to maintain or increase reservoir production

Exploration wells require geological and geophysical data gathering, processing and evaluation Surface geological study Subsurface mapping Identification of structures e.g. anticlines, salt domes, fault traps, sand bodies lenses

Seismic EvaluationCOMMITMENT TO ACADEMIC AND INDUSTRIAL EXCELLENCE 22

• Exploratory drilling is drilling to locate probable mineral deposits or to establish the nature of geological structures.

• Such wells may not be capable of production unless minerals are discovered.

• The objectives of exploratory wells are:– To determine the presence of hydrocarbons.

– To provide geological data (cores, logs) for evaluation.

– To flow test the well to determine its production potential, and obtain fluid samples.


EXPLORATORY DRILLING

APPRAISAL DRILLING• Appraisal drilling is carried out following the discovery of a new field to determine the physical extent, amount of reserves and likely production rate of the field.

• The objectives of appraisal wells are:– To establish the lateral and vertical extent of (to delineate) reservoirs in the field.

– To determine the amount of petroleum reserves in the field.

– To determine the likely oil production rate in the field.


PRODUCTION DRILLING Also called development drilling. This is drilling to accomplish production of the minerals (including drilling to inject fluids for pressure maintenance and/or secondary and tertiary recovery).


WELL LOCATIONS IN ONSHORE AND OFFSHORE DRILLING


In rotary drilling, the hole is drilled by rotating a bit to which a downward force is applied

The bit is fastened to and rotated by a drill string composed of high quality drill pipe and drill collars with new joints added as drilling progresses COMMITMENT TO ACADEMIC AND


ROTARY DRILLING

Rotary drilling uses a drilling fluid called the drilling mud to lift up cuttings

Drilling mud is circulated through drillstring to the hole and back to surface

At the surface, the mud is channeled through a series of tanks (quiesent time) for cutting removal and mud conditioning

ROTARY DRILLING


DRILLING MUD A mixture of clay, water, chemical additives, and weighting materials

Flushes rock cuttings from a well, lubricates and cools the drill bit, maintains the required pressure at the bottom of the well, prevents the wall of the borehole from crumbing or collapsing.

Prevents other fluids from entering the well bore.


Drilling mud is used by pumping it with mud pumps through the drill string where it sprays out of nozzles on the drill bit.

The mud then travels back up the annular space between the drill string and the sides of the hole being drilled, up through the surface casing, and emerges at the surface.

Cuttings are then filtered out at the shale shaker and the mud enters the mud pits.

DRILLING MUD


FUNCTIONS OF DRILLING FLUID1. Reduce friction between the

drill string and the side of the hole

2. Maintain hole stability

3. Prevent inflow of fluids

4. Form a thin, low permeability,

filter cake which seals pores

and other openings in formations

penetrated by the bit

5. Carry cuttings up to the surface

6. Cool and clean the bit

7. Assist in collection and interpretation of data


ADVANCEMENTS IN ROTARY DRILLING

Directional Drilling

Horizontal Drilling

Multilateral Drilling

Coil Tubing Drilling

Casing Drilling


DRILLING HAZARDSo Tools dropped while Drillingo Stuck Pipe o Increased size of Hole o Lost Circulation Problemso Sloughing Shaleo Bit Washout/Pluggingo Kick/Blow out


TYPES OF RIGS• There are a number of rig types that are used for drilling for oil and gas.

• They are:• Fixed Platformo Land Rigo Bargeo Jack-upo Submersible

• Floating Platformo Semi-submersible Rigo Drill ship

• The rig type depends essentially on:• The environment (land or offshore) as well as• Water depth (for offshore rigs).• Weather conditions(clement or harsh weather)


SUMMARY OF MAIN TYPE OF RIGSLand (Onshore) Rigs

1. Derrick & Mast

Offshore Rigs1. Barges2. Jackup Rigs3. Standalone Platforms4. Submersible Rigs 5. Semi-submersible Rigs6. Drill Ships


LAND RIGSThey are usually transported in section by truck to accessible locations.

They can be derricks or masts.

Nabors 680 near Wamsutter, Wyoming, US


OFFSHORE RIGS• Offshore rigs are rigs used on inland lakes, swamps, shallow water areas adjacent to the coast or deep sea areas of the world.

• The offshore rigs can thus be used in both the shallow and deep water areas of the world.

• Offshore rigs range from barges, semi-submersible rigs, jackup rigs and drill ships.

• A well drilled from an offshore rig is much more expensive than a land well drilled to the same depth.


OFFSHORE RIGS• The increased cost can be attributed to several factors:– specially designed rigs, – subsea equipment, – loss of time due to bad weather,– expensive transport costs (e.g. helicopters, supply boats).

• A typical North Sea well drilled from a fixed platform may cost around $10 million.

• Since the daily cost of hiring an offshore rig is very high, operating companies are very anxious to reduce the drilling time and thus cut the cost of the well.


BARGE A barge is a drilling structure which is used in relatively shallow water, usually 80 feet or less.

It is towed to its location where it is submerged until it sits on the bottom.

The flat bottomed barges are floated to location before being sunk and attached to the ground with pilings (lake and swamp barges).

This submerging serves as its mooring system, although anchors may also be used COMMITMENT TO ACADEMIC AND


JACKUP RIGS• A jack-up rig is a type of mobile offshore oil and gas drilling platform that is able to stand still on the sea floor, resting on a number of supporting legs.

• The most popular design uses 3 legs.

• The supporting columns may be moved up and down by a hydraulic or electrical system.

• The whole rig can also be jacked up when the supporting legs touch the seafloor. COMMITMENT TO ACADEMIC AND


JACKUP RIGS


• During transit, the platform floats on its hull and is typically towed to a new location by offshore tugs.

• Jack-up rigs provide platforms that are more stable than semisubmersible platforms but can only be placed in relatively shallow waters, generally less than 1,000 feet (300 m) of water.

• The rig acts as a kind of platform. This type of rig is almost always used in connection with oil and/or natural gas drilling.


JACKUP RIGS

The obvious limitation with this type of installation is the depth of water it can operate in.

Jackup rigs are found mostly in the North Sea.

LIMITATIONS OF JACKUP RIGS


SUBMERSIBLE RIGS A particular type of floating vessel, usually used as a mobile offshore drilling unit (MODU), that is supported primarily on large pontoon-like structures submerged below the sea surface.

The operating decks are elevated 100 or more feet [30 m] above the pontoons on large steel columns.

Once on the desired location, this type of structure is slowly flooded until it rests on the seafloor.


SUBMERSIBLE RIGS After the well is completed, the water is pumped out of the buoyancy tanks, the vessel refloated and towed to the next location.

Submersibles operate in relatively shallow water, since they must actually rest on the seafloor.


SEMI-SUBMERSIBLE RIGS• A Semi-submersible platform or rig, is a mobile structure used for drilling for oil and natural gas in offshore environments.

• Their superstructures are supported by columns sitting on hulls or pontoons which are ballasted below the water surface.

• They provide excellent stability in rough, deep seas. Semi-submersible rigs can be moved from place to place.


• Semi-submersible rigs can be ballasted up or down by altering the amount of flooding in buoyancy tanks.

• They are generally anchored by cable anchors during drilling operations, though they can also be kept in place by dynamic positioning.

• Semi-submersibles can be used in water depths from 600 up to 35,000 feet (180 to more than 10,600 m).

SEMI-SUBMERSIBLE RIGS


SEMI-SUBMERSIBLE RIGS

Semi-submersible RigsCOMMITMENT TO ACADEMIC AND INDUSTRIAL EXCELLENCE 48

AN ANCHORED SEMI-SUBMERSIBLE RIG

An Anchored Semi-submersible RigCOMMITMENT TO ACADEMIC AND INDUSTRIAL EXCELLENCE 49

DRILL SHIPS• A drillship is a maritime vessel that has been fitted with drilling apparatus.

• It is most often used for exploratory drilling of new oil or gas wells in deep water or for scientific drilling.

• The drillship can also be used as a platform to carry out well maintenance or completion work such as casing and tubing installation or subsea tree installations.


DRILL SHIPS• It is often built to the oil production companies and/or investors design and specifications but it can also be a modified tanker hull and outfitted with a dynamic positioning system to maintain its position over the well.

• The greatest advantage these modern drill ships have is their ability to drill in water depths of more than 2500 meters.


DRILL SHIPS• The valuable time saved sailing between oilfields worldwide as per contractual agreement is also an advantage.

• They are completely independent compared with semi-submersibles and jack-up barges.

• In order to drill, a marine riser is lowered from the drillship to the seabed with a Blow Out Preventer (BOP) at the bottom that connects to the wellhead.


Drill ShipsCOMMITMENT TO ACADEMIC AND


DRILL SHIPS

RIG DYNAMIC POSITIONING (DP) Some latter generations of semi-submersible and drill ships are termed thruster assisted or dynamically positioned.

They use no anchors but require sophisticated computer based control systems.

They operate in any water depth. The disadvantage of DPs is that they can move up & down more (no damping action). COMMITMENT TO ACADEMIC AND


TENDERS A tender is a small mobile unit similar in nature to a drill ship but with no derrick.

The drilling derrick is found on the platform while the rest of the drilling services like mud circulation equipment, mud pumps, accommodation etc. are found on the tender.


Champion West CWDP-01 Smart Field Platform with Tender Assist Rig, West Pelaut, Brunei.

OFFSHORE PRODUCTION PLATFORMS


• Once exploratory wells have confirmed commercial reservoirs of natural gas and/or petroleum deposits, it is economical to build a permanent offshore production platform from which well completion and oil and gas production can be made.

• These permanent structures are often very expensive and generally require large deposits of hydrocarbons to be economical to develop.

• Some of today’s largest offshore platforms are located in the North Sea, where large structures able to withstand high winds and large waves are necessary.



• There are a number of different types of permanent offshore production platforms, each useful for a particular depth range.

• The types of offshore platforms are:– Fixed Platforms– Compliant Platforms– Seastar Platforms– Floating Production Systems (FPS) – Tension Leg Platforms– Spar PlatformsA 'Statfjord' Gravity base Structure under construction in Norway. Almost all of the structure will end up submerged.



• For non-floating structures (Compliant Towers / Fixed platforms) the deepest water depths are:– Petronius Platform, Water depth 531 meters (1,740 ft)

– Baldpate Platform, Water depth 502 meters (1,650 ft)

– Bullwinkle Platform, Water depth 413 meters (1,350 ft)

– Pompano Platform, Water depth 393 meters (1,290 ft)

– Benguela-Belize Lobito-Tomboco Platform, Water depth 390 meters (1,300 ft)

– Tombua Landana Platform, Water depth 366 meters (1,200 ft)

– Harmony Platform, Water depth 366 meters (1,200 ft)

– Troll A Platform, Water depth 303 meters (990 ft)

– Gulfaks C Platform, Water depth 217 meters (710 ft)

BASIC OFFSHORE RIG COMPONENTS• All offshore rigs have quite a number of components that are similar.

• Some of these features are:• Rig Floor.• Accommodation.• Offices.• Helicopter Deck.


DRILLING RIG SELECTION

DRILLING RIG SELECTION• Rig selection is the process whereby we define our hardware needs to fulfil the well objectives.

• In safe cost-effective drilling operations, it is vital that rig selection be given the highest priority and not left to chance.


DRILLING RIG SELECTION• The rig requirements can be defined within the following groups: – Type of rig– Lifting capacity– Substructure/pipe setback load capacity– BOP size, type, number and rating– Pump output and rating– Tank capacity– Solids treatment equipment– Storage capacity– Accommodation


• Type of Rig:– For land wells the following choices are available:•Trailer Rigs•Package Rigs•Microdrill-type Slim Hole Rigs

SPECIFICATION OF A LAND RIG



Type of Rig UseTrailer rigs:

First choice for wildcat wells.Limited lifted capacity.

Package rigs:

Higher mobilisation cost.Suitable for deep wells and cluster drilling.

Slim hole rigs

Use only in environmentally sensitive areas where limited lifting capacity is not a problem.


• Lifting Capacity:– The rig must be able to handle the heaviest drillstring or casing string with a margin of safety.

– It is not just the hanging weight of the string that must be considered but also the drags and overpulls necessary to free the pipe if it was stuck.



• Lifting Capacity:– Normally, the heaviest string handled by a rig is the production casing string.

– As a rule of thumb, the lifting capacity requirement of the rig should be considered as the heaviest string to be run plus a 25 per cent margin of safety.

– The string weight should be calculated ‘in air’ and no buoyancy factor included in these figures.



• Lifting Capacity:

– This is because if the string gets stuck, the hydrostatic upthrust or buoyancy of the string is lost and to pull it free will require pulling more than its dry weight to free it.



• Substructure/pipe setback load capability :– This must be sufficient to take the full drillstring stood back in the derrick whilst the heaviest string of the casing is being run.

– Again, in most cases, this will be the production string.



• Substructure/pipe setback load capability :

– It is not acceptable to have to lay out drillpipe to allow casing to be run as we never know when the casing might need to be pulled and the hole reconditioned with a bit and BHA.



• BOP size, type, number and rating:

– With the minimum BOP requirements known for each well type, and knowing the well plan and expected pressure regime, the BOP requirements can be specified.

– Since land rigs typically use smaller BOPs than those used offshore, extra care must be taken to ensure that casing and tubing hangers can pass through with reasonable clearance.



• Pump output and rating:– For a given hole size, a given calculation rate is required.

– The normally used minimum annular velocity is about 30 m/min.

– This corresponds to 500 gal/min or 1900 1/min) pump output in 121/4-inch hole using 5-inch drillpipe.

– The pressure loss in a given circulating system can be calculated using a hydraulic slide rule or by computation.



• Pump output and rating:– By knowing the hole sizes and casing setting depths, the pump output capacity and pressure rating can be defined.

– – The rig pumps, therefore, should meet these requirements as a minimum acceptable level.

– The bit nozzle pressure loss is a major part of the overall pressure loss in the circulating system and the use of PDC bits.



• Pump output and rating:

– PDC bits can work efficiently with lower bit hydraulic horsepower (HHP) and have reduced the HHP requirements for given hole sections.

– The mud weights to be used will also influence the HHP requirements and these must be considered.

– As a guide, the following pump requirements can be used:



• Pump output and rating:– Hole: 121/4” to 500 m 81/2” to 1000 m500 gpm and 1500 psi

– Hole: 171/2” to 500 m 121/4” to 2000m 800 gpm and 2000 psi

– Hole: 171/2” to 1500 m 121/4” to 3000 m 1000 gpm and 3000 psi



• Tank Capacity:– The surface mud tank capacity must be sufficient to allow continuous treatment of the mud prior to pumping it downhole.

– Again, as a guide, the following minimum surface tank volume requirements can be used:•Hole: 121/4” to 500 m 81/2 to 1000 m – 60 m3/380 bbl

•Hole: 171/2” to 500 m 121/4 to 2000m – 90 m3/570 bbl

•Hole: 171/2” to 1500 m 121/4” to 3000 m –120 m3/760 bbl



• Solids Treatment Equipment:– Before considering this requirement, we must determine what types of mud systems are to be used on the wells to be drilled.

– Furthermore, the ease with which liquid waste can be disposed must be assessed.

– Simple water-based mud systems can be kept in shape by extensive dumping and diluting.

– This process takes some load off the solids treatment equipment.



• Solids Treatment Equipment:

– However, it does fill the waste pit rather quickly.

– If oil-based muds are in use, then dumping and diluting is not an effective continuous treatment.

– Consequently, a full set of solids treatment equipment will be required.



• Solids Treatment Equipment:– Most land wells can be drilled efficiently with the following equipment when using water-based mud:•2 double-decker shale shakers•1 de-sander 1700 1/min/440 gpm•1 de-silter 1700 1/min/440 gpm

– If oil-based mud is to be used, then in addition to the above mud cleaners, a centrifuge should be installed.



• Storage capacity:– Under storage capacity, we must consider all the consumables involved in drilling a well.

– To operate efficiently, the rig must be capable of keeping the following materials nearby:•Water.•Sack chemicals.•Bulk chemicals.•Cement.•Tubular goods.



• Storage capacity:– Once the basic well design has been completed, a list of the above requirements can be made. No two sites are the same since they have different logistic needs.

– If mains water is available and the supply can be relied upon, then the water storage requirements are minimal.

– If the well is located in an ‘oilfield area’, then chemicals can be procured as needed and not just kept on site. Similarly, casing can be brought to the site only a few days prior to running.



• Accommodation and Offices:

– Company policy will, in most cases, dictate the level of supervision used on the drill site.

– Most land wells will have a Drilling Engineer and possible a Night-shift Drilling Supervisor.

– Each of these must have a place to work, a desk, filing cabinets and shelves to keep files, etc.

– They also need shower facilities, sleeping quarters and a small kitchen where food can be prepared.




– Different companies have different policies regarding whether the Drilling Supervisor can leave the site during drilling operations.

– It is often contended that the Supervisor should never leave the site during these operations.

– If this policy is adopted then the need for good kitchen facilities is increased.




– The accommodation and office requirement for rig selection purposes will be that which meets the particular well’s and operator’s needs.

– This can be easily defined once the basic program has been prepared.



• Type of Rig:– For most offshore wells, the type of rig required will fall into one of three groups:

•Jack-ups, where the water depth is less than 100 m

•Semi-submersibles in hostile waters too rough for drill ships and in depths over 100 m.

•Drill ships in calmer waters with depths over 100 m

SPECIFICATION OF AN OFFSHORE RIG


• Type of Rig:– There are certain situations where any of the three types could be used to meet a well’s needs.

– In these cases each well approach should be costed out to find a clear economic leader.

– If there is no economic leader, then oilfield sense or intuition will probably show you the way to go.



• Type of Rig: Jack Up Rig:•Jack-ups are used for most of the offshore exploration drilling worldwide.

• •They fall into two main categories determined by the equipment used on the bottom of the supporting legs.

•By far the most common type of jack-up is the ‘spud can’ type. This rig has spud or tanks mounted on the base of the legs.



• Type of Rig: Jack Up Rig:•These are usually round and are equipped with a jetting system to allow them to be jetted into the seabed.

•Additional jetting systems are installed on the top of the spud cans to allow the can to be pulled out of the formation, should penetration into the seabed be too great.

•The second type of jack-up is ‘mat’ supported.



• Type of Rig: Jack Up Rig:

• This type of rig has a large single mat connected to the base of each leg.

• This is lowered with the legs and, since it has a larger area than individual spud cans, it applies less pressure on the seabed for a given jack-up weight.

• Consequently, it is used mainly in areas where the seabed is very soft and spud cans would penetrate too far into the seabed if they were used, or where seabed pipeline congestion precludes the use of spud can type jack-ups.



• Type of Rig: Jack Up Rig:•Only when operating in these types of areas should mat supported jack-ups be considered. In all other applications use spud can type jack-ups.

•Most modern jack-ups are of the cantilever design.

•This means that the derrick and substructure can be skidded inboard on the rig for rig tows and skidded out over a cantilever during drilling operations.



• Type of Rig: Jack Up Rig:

•The safe working load of the derrick and substructure is affected by the amount of extension along the cantilever that is being used.

•Consequently, when lifting, substructure and setback capacity requirements are being considered for cantilever jack-ups, the position that the derrick will be on the cantilever must be known or fixed.



• Type of Rig: Semi-submersible Rigs:

•In areas where water depths exceed 100 m and heavy weather can be expected, then semisubmersibles must be used.

•The choice will, in most cases, come down to using either second generation or third generation semis.

•Second generation semis appeared in the mid-70s and incorporated a log of the lessons learned by the first generation of semis and submersible rigs.




•A major influence in their design was the increasing exploration activity in the North Sea.To make a rig pay in the North Sea meant operating it for 12 months of the year.

•This in turn meant that the rig had to be able to withstand 100 knot winds and 20 m seas on a regular basis.

•Typical second generation semis are rig designs such as the Aker H3 or Sedco 700.



• Type of Rig:Semi-submersible Rigs:

•These rigs typically have a variable deck load of 1500 - 2000 tons and can be moored in up to 300 m of water.

•Some second generation semis have been ‘upgraded’ over the years usually by the addition of extra columns from the submerged pontoons up to the main deck.

•This modification has the effect of increasing the variable deck load, which in turn allows the rig to carry more anchor chain and therefore moor in deeper water.




•(The anchor chain or line must be four to five times the water depth to achieve a good mooring line catenary).

•In most cases, these ‘upgraded’ second generation semis look awful but work OK, so they can be used a s a substitute for some third generation semi-submersible applications.

•Third generation semis evolved from a desire to go conventionally moored into deeper waters and to carry greater deck loads.




•Typical third generation semi’s are designs such as the F & G Pace Setter, the Aker H4, the GVA 5000 and the Bingo.

•These rigs typically have a variable deck load of over 3000 tons and can be moored in water depths of up to 600 m.

•As with all things in life, you do not get something for nothing when it comes to choosing a semisubmersible rig.



• Type of Rig: Drill Ships:•Drill ships are the rigs to use when drilling in calm waters which are too deep for jackup operations.

•They can be used in very shallow water (± 30 m) in very calm conditions but are usually used in water depths of over 100 m.

•Drill ships come in two main groupings: conventionally moored and dynamically positioned (DP).



• Type of Rig: Drill Ships:•Conventionally moored drill ships are rigs moored with bow and stern anchors (typically four at each end of the vessel).

•As such, they are restricted to water depths of up to 500 m only because there is a limit to the anchor chain or cable that they can carry.

•The heading that the ships are given into the prevailing seas is important since it is fixed once the anchors are set.



• Type of Rig: Drill Ships:•Dynamically positioned drill ships use a series of hull mounted propellers (thrusters) to keep them in position over the well.

•They hold their position by tracking geostatic satellites and transmitting interpreted data to the thrusters, which fine-tune the rig position constantly.

•Since the rig is not anchored up, the bow can be turned into the current prevailing seas.



• Type of Rig: Drill Ships:•DP drill ships will operate in water depths of 100 m up to several thousand meters and are the favoured tool for drilling wells off the Continental Shelf.

•When specifying a rig type, it is also necessary to specify the deck load requirements that the rig must meet.

•The deck load requirements are the amount of drill pipe, tools, casing, cement, chemicals, mud and fluids to be carried during the drilling operation.



• Type of Rig: Drill Ships:•The greater the deck load then the less logistic support a rig needs

•A drill ship can carry on board most of the equipment required to drill two wells.

•Generally speaking for drill ships, the deck load is never a problem.

•For jack-ups and semis however, there is never enough deck load capability.



• Type of Rig: Drill Ships:

•As a guide, most wells of up to 4000 m can be drilled with deck load of less then 2000 tonnes.

• Wells deeper that this or in deeper water with chain moored semis will require additional deck load capabilities.



• Type of Rig: Lifting Capacity:•The same criteria for lifting capacity apply equally to offshore rigs and to land rigs.

•Typically, offshore rigs will routinely handle larger casing sizes than land rigs and therefore will need a higher rating on their lifting capacity.

•Floating rigs use large seabed-placed BOP units which must be handled at surface initially by means of bridge cranes and then finally lowered to the seabed either on drillpipe or on riser.



• Type of Rig: Lifting Capacity:•The weights involved in this operation are considerable and could in some cases exceed the normal expected drilling loads.

•Furthermore, modern floating rigs are all fitted with a heave compensation system, which is mounted either on the travelling block or the crown block.

•These will have a rated capacity of around 500000 lbs., which will be a lot, less than the total lifting capacity of the rig.



• Type of Rig: Lifting Capacity:• When specifying a floater, compensated capacity requirement should also be determined.

• For jack-ups the rig in its working position must satisfy the lifting capacity requirements.

• Any cantilever jack-ups must skid the derrick out on the cantilever to gain access over the well or jacket.

• The further out along the cantilever that the derrick must go to be above on the well, the lower the rigs lifting capacity will be.



• Type of Rig:– Site Conditions and Considerations:•The culmination of the sometimes arduous and complex task of geologic evaluation of a potential offshore play is for the exploration geologist to put a finger on the map and say “drill here.”

•This decision sets in motion a series of actions that will eventually lead to the drilling of an offshore well. The first major step is to select a rig to drill the well.



• Type of Rig:– Site Conditions and Considerations:•Certain data must be known about the drillsite and surrounding area.

•Basic offshore rig selection criteria consist of: – water depth, – expected environmental conditions during the forecasted drilling period (wind, waves, current profile, and climatological conditions),

– distance from nearest dock facility, and

– availability of consumable supplies (such a drilling mud, cement, pipe, rental tools and spare parts).



• Type of Rig: Water Depth:•A rough idea of the water depth is an important criterion for rig selection.

•If the water depth does not exceed approximately 350 ft, any of the three major rig types can be considered.

•Jackups can handle a water depth range from their shallow draft limit of 20 to 30 ft to a maximum depth of 350 ft.

•The maximum strains, such as wind, wave, and current conditions at the site.



• Type of Rig: Water Depth:•Severe conditions tend to lower the jackup rig’s maximum water-depth capacity. Drillship water depths range from approximately 100 to 8,000 ft with today’s technology.

•The shallow side is limited by clearance between the bottom of the hull and the subsea blowout preventer (BOP) equipment.

•Maximum water-depth limits occur because of riser-system limitations and other constraints.



• Type of Rig: Water Depth:•Semisubmersible water depths range from approximately 150 to 8,000 ft.

• •The semisubmersible must stay in slightly deeper water than a ship because of the clearance between the submerged hull (60 to 90 ft below the water sea BOP equipment.

•Until 1978, semisubmersible maximum water depth was limited by the practical depth of conventional mooring systems - approximately 2,200 ft.



• Type of Rig:– Expected Environmental Conditions:

•Wind, waves and current are all important site-specific data to help in rig selection and in determination of vessel headings, mooring pattern, mooring line tensions, riser tensions, subsea equipment selection, and equipment operational limits.

•Wind, wave, current and climatological data are generally the responsibility of an oceanographic consulting firm or your own company’s oceanographer.




•Many sources of environmental data are available-the marine climatic atlas, ship observations, U.S. Navy publications, privately funded oceanographic studies, and university-sponsored research.

•Converting these data into useful site-specific wind, wave, and current information is the scientific specialty of oceanography.




•The oceanographer must have specified coordinates of the location and the time of they year (with some cushion on both ends) in which operations are expected.

•With that he can develop the expected wind, wave, and current conditions for the location.

•For an exploratory location, the oceanographer may provide environmental data for operational weather, seasonal one-year storm and seasonal 10-year storm.




•With that information, the drilling engineer and technical support staff can accomplish several tasks necessary in planning the well:– A preliminary rig selection can be made based on water depth, wind, wave and current information.

– A preliminary estimate of vessel heading can be determined.

– Before final headings is specified, however, local knowledge of the area should be considered.




– Local conditions such as swell, tide-generated currents, and rapidly changing wind directions-frequently can affect the optimum vessel heading significantly.

– The primary objective of optimum vessel heading is to minimize vessel motion (primarily pitch, roll, and heave) while keeping the vessel’s mooring line forces within acceptable limits and providing a lee side (calm-water side) for supply and crew boats to tie up.




– After the vessel is selected, mooring and riser analyses can be run to determine whether the vessel is adequately equipped for the location.

– In addition, both mooring and riser operating tensions can be determined.

– Both are necessary after the rig arrives on location.

– Typically, the mooring system is analyzed on location.

– Typically, the mooring system is analyzed with a one-year seasonal storm to determine what operating tensions should be pulled on the anchor lines.




– A 10-year storm can be analyzed to determine the level of proof test, to pull on each mooring line.

– With reasonable risk considered, if each line can withstand a 10-year storm proof test, normal operations should be safe without the fear of slipping an anchor or breaking a mooring line.

– Drilling riser top tensions are developed to minimize ball-joint angles and riser sag while keeping riser-pipe stresses within acceptable limits.




•For jack up rig evaluation, comparing water depth, current, wind, and tides with the maximum recommended criteria established by the rig designer is extremely important.

•In water depths nearing the rig’s maximum capability, strong current or other environmental factors may reduce the acceptable water depth.

•Soil or foundation competency at the site must be known for jackup operations also.




•At an exploratory location with unknown soil consistency, soil borings generally will be required before the rig’s arrival on location.

•They are useful in determining depth of leg penetration and to ensure that the soil can adequately support the rig.



• Type of Rig:– Logistics Consideration:

•Logistics must also be considered in rig selection.

•Remote locations require substantially more planning and preparation than do locations adjacent to established bases and supplies.

•Consideration must be given to:– frequency of consumable supply – distance from supply base (length of boat run

– number of people the rig can accommodate;

– availability of spare parts – shipment delays caused by customs regulations.




•Floating rig’s (ships and semisubmersibles) variable deck-load capacity must be considered and compared with frequency of consumable supplies required.

•Ships have much greater variable deck-load capacity than semisubmersible drilling rigs (1500 vs. 3000 tons).

•If the location is extremely rough environment, however, the semisubmersible is more stable in rough seas than the ship.

•Trade-off and compromises are necessary ingredients in rig selection.




•Availability of pipe, mud, fuel, water and other consumables must be carefully determined during the planning effort.

•Helicopters to transport personnel and light equipment in routine and emergency situations are a necessary part of most floating drilling operations.

•Those located within a few minutes of the coastline and support bases are sometimes exceptions.




•Climatological conditions have a major effect on helicopter operations.

•Fog and impaired visibility conditions will ground flight operations and depending on their extent, can have a major effect on the resupply of consumables, transportation of crews to and from support bases, and overall rig operations.



• Type of Rig:– Seismic and Other Location Studies:•Preparations to drill and exploratory location will include running and evaluating a suite of location surveys.

•Site surveys generally are run by seismic companies specializing in prespud site studies.

•These companies will conduct the surveys, evaluate the data, and prepare formal reports that present the data that will be useful in selecting the exact location, in preparing the mooring plan, and in determining how the top hole will be drilled.



ROTARY DRILLING RIG SYSTEMS


ROTARY DRILLING RIG• The main function of rotary drilling rig is to make hole.

• The moving of the rig from site to site depends on weight and size of each rig component.

• Each unit assembly is limited in weight because of truck and highway limitations on gross weight.

• Rotary drilling rigs must be disassembled into many components so that weight limits are not exceeded.


ROTARY DRILLING RIG• Rotary rig design should:

Allow for rapid erection and take-down, and consist of few pieces as possible.

Not require special cranes for assembly (rig-up) or disassembly (tear-down).

Enable drill pipe to be run into the hole or pulled out with minimum time wasted.

Provide the maximum amount of available power for the circulating fluid to the bit.


ROTARY DRILLING RIG• Many factors determine a rig’s portability:Wheel-mounted rigs can be used for drilling to depths of 10,000 feet or more and for completion/workover service on 15,000-foot wells.

These rigs have self-erecting, telescoping masts; and the mast, drawworks and engines are built on a trailer or self-propelled unit.

Equipment such as mud pumps must be handled as packages.

Therefore, efficient planning and design are necessary. COMMITMENT TO ACADEMIC AND


• The drilling rig consists of six major systems:– Hoisting System

– Rotating System

– Fluid Circulating System

– Power System– Well Control System

– Well Monitoring System

ROTARY DRILLING RIG Rotary Drilling

Rig.


HOISTING SYSTEMDERRICKThe function of a derrick is to provide vertical clearance to the raising and lowering of drill string into and out of boreholeTwo type of DerricksStandard Derricks - it is of bolted construction and assembled part by partMast – a portable derrick, one capable of being erected as a unit


CROWN BLOCKThe fixed set of pulleys (called sheaves) located at the top of the derrick or mast over which the drilling line is threaded. TRAVELLING BLOCK A pulley (sheave) assembly that connects the drilling line to the hook and swivel

HOISTING SYSTEM


DRAWWORKS It is the control center from which the driller operates the rig. It contains clutches, chains and other controls

It houses the drum which spools drilling line during hoisting and allows feed off during drilling

HOISTING SYSTEM


• The hoisting system is used to raise and lower the drill stem.

• It is also used to support and lower pipe that is used for casing and tubing.

• A mast or derrick supports the hook by means of the travelling block, wire rope, crown block and drawworks.

• The drawworks is powered by two or three engines (called prime movers) to raise or lower the drill stem so that the bit can drill.

HOISTING SYSTEM


• The drill stem is the whole assembly from the swivel to the bit, including the kelly, drill pipe, drill collars and bit sub.

HOISTING SYSTEM

Hoisting SystemCOMMITMENT TO ACADEMIC AND


• Standard drilling rig derricks are tall steel structures with four supporting legs standing on a square base.

• The derrick and substructure plays an important role in drilling operations.

• The derrick provides the vertical height necessary for the hoisting system to raise and lower the pipe.

• The derrick is assembled piece by piece at the drilling site.

• A drilling mast, which is partially assembled when it is manufactured, usually has a smaller floor area.

DERRICK, MAST & SUBSTRUCTURE


• It can be raised from a horizontal to a vertical position in as shown below.

• The standard derrick has become rare today except for extremely deep wells and offshore drilling.


Raising a MastCOMMITMENT TO ACADEMIC AND INDUSTRIAL EXCELLENCE 135

• The mast has almost completely replaced the conventional derrick for drilling on land because:– It can be quickly dismantled and erected on another location by the regular rig crew

– The mast can be moved in large units without complete disassembly.

– Masts 135 to 145 feet in height are the most common size.

• The rig floor, rotary table, casing and drill pipes rest on a substructure.

• The rig floor provides an area for handling the drill stem and related equipment.



• Blowout preventers and wellhead fittings are located under the substructure.

• Drill pipe is suspended from the rotary table, which is supported by the beams of the substructure.

• Heavy-duty masts and substructures can stand a load of 1,200,000 pounds.

• The normal capacity is in excess of 500,000 pounds.



• The derrick and the substructure must have enough strength to withstand:– Load suspended from a hook.– Pipes set in the derrick.– Wind loads.

• The API has developed size classifications for the derrick as shown on the next slide.




Derrick Size Classifications (Courtesy API)COMMITMENT TO ACADEMIC AND


DERRICK, MAST & SUBSTRUCTUREGeneral Dimensions of Derrick Sizes


• The derrick and substructure must be able to support the force imposed by pipe weight on the block by a portion of the drillstring standing in the derrick.

• Due to the manner in which the hook load is distributed over the derrick, the effective load may exceed the actual.

• When heavy casing strings are run, it may be necessary to lay down some drill pipe initially so the derrick loading capacity is not exceeded.




Free Body Diagram of the Block, Fast and Dead LinesCOMMITMENT TO ACADEMIC AND


• The derrick load resulting from a hook load can be evaluated with the free body diagram (FBD) on the previous slide.

• The force on the derrick (FD) includes the hook load (L), the tension in the fast line (TF) and the tension in the dead line (TD).

• The tension in the fast line in a non-ideal friction is given by:



– where:•EB = efficiency factor of block system•L = hook load, lb•N = number of lines strung over the block system

•TF = fast-line tension, lb• Since the dead line does not move, the tension is in the dead line is given by:



• FD can now be written as:

• The total force on the derrick (FD) is not evenly distributed over each of the four legs.

• The fast-line tension is distributed evenly between legs C & D, since the drawworks is commonly positioned between the legs.



• The dead-line tension is near a leg. • The force on each leg can be summarized as follows:


Load Source Total Load

Load on each Derrick Leg

A B C D

Hook Load L L/4 L/4 L/4 L/4

Fast Line

L/NEB - - L/2NEB L/2NEB

Dead Line L/N L/N - - -

TotalL + L/NEB +

L/NL((N+4)/

4N) L/4L((NEB+2)/

4NEB)L((NEB+2)/

4NEB)



C

A

D

B

Lines to Block Fast line

Dead line

Derrick Leg

Typical Rig Floor for Distribution of Forces


• The load on leg A is greater than any other leg if EB > 0.5.

• Therefore, the maximum derrick load can be defined as four times the strength of the weakest leg:

– where:• FDE = effective derrick load.

• The derrick will be exposed to loads created by wind acting horizontally on pipe set back in the derrick.



• The Wind Load (Lw) is calculated from:

– where:•Lw = wind load, lb/ft, and•V = wind velocity, mph.



• The hoisting system is a vital component of the rig equipment.

• It provides a means for vertical movement of pipe in the well, i.e., to lower and raise the drillstring and casing.

• The principal items in the hoisting system are as follows:– drawworks.– crown and travelling blocks.– wireline.– ancillary equipment such as elevators, hooks and bails.

DRAWWORKS


• The hoisting system, in conjunction with the circulating equipment, consumes a portion of the rig’s power.

• A drawworks on a rig is known in other industries as a hoist.

• The main purpose of the drawworks is to lift and lower pipe in and out of the hole.

DRAWWORKS


• The hoisting drum either reels in wire rope to pull the pipe from the hole or lets out wire rope to lower the travelling block and attached drill stem, casing or tubing.

• The drawworks includes a transmission, which uses chains, sprockets and gears to allow speed changes of the hoisting drum.

• Often, the drawworks has a drive sprocket to power the rotary table.

• This arrangement is common, even on diesel-electric rigs.

DRAWWORKS


A Rotary Rig Hoisting System

DRAWWORKS


The Drawworks consists of a revolving drum around which the wire rope is spooled

DRAWWORKS


• The drawworks brake system makes it possible for the driller to control a load a several hundred tons of drill pipe or casing.

• Most rigs are equipped with two brake systems for the drawworks hoisting drum: one that is mechanical and one that is hydraulic or electric.

• The mechanical system consists of compounded levers to tighten brake bands to bring the drum to full stop.

DRAWWORKS


• The hydraulic or electric brake can control the speed of descent of a loaded travelling block, although it is not capable of stopping the drum completely.

• Another of component of the drawworks is the catheads.

• The makeup, or spinning, cathead is located on the driller’s side of the drawworks and is used to tighten the drill pipe joints.

DRAWWORKS


• The other cathead, located opposite the driller’s position, is the breakout cathead.

• It is used to loosen the drill pipe when it is pulled from the hole.

• Air hoists are provided on many rigs for handling light loads.

DRAWWORKS


The Friction Cathead

DRAWWORKS


• The travelling block, crown block and drilling line within the derrick raise and lower loads of pipe out of and into the hole.

• During drilling operations, these loads usually consist of drill pipe and drill collars.

• The blocks and drilling line must also support casing while it is being run in the hole.

BLOCKS AND DRILLING LINE


• This casing is often heavier than the drill stem.

• Drilling line is reeved around sheaves (pulleys) in the crown block at the top of the derrick or mast and in the travelling block.

• The blocks and drilling line assembly must have great strength to support the heavy loads.

• The number of sheaves is determined by the weight to be supported.



• Five is the most common, but deeper wells often require six or seven.

• Friction is minimized in the blocks by heavy duty bearings.

• Large-diameter sheaves are provided to lessen wear on the drilling line, which is usually a multistrand steel cable, 1 ¼ to 1 ½ inches in diameter.



• The block system is not a frictionless system, i.e., its efficiency factor is less than 1.0.

• It is often assumed that the efficiency factor is computed from:

– where n is the number of sheave pairs.• The following Table indicates EB for various pulley systems.

Number of Lines EB

6 0.8868 0.8510 0.81712 0.785COMMITMENT TO ACADEMIC AND



• Drilling rigs have many applications for wire ropes.

• The more common uses for wire ropes are as drilling lines and guideline tensioners.

• The drilling line connects to the drawworks and the dead-line anchor.



• It is pulled through the crown and travelling block sheaves so that the travelling block can be raised or lowered as necessary.

• Wire rope is made from cold drawn carbon steel of various grades, depending on the strength required.

• The API classifies the various grades as follows:– extra improved plow steel (EIPS).– improved plow steel (IPS).– plow steel (PS).– mild plow steel (MPS).



• Generally, the first two higher-strength grades, EIPS and IPS, are used currently for drilling lines due to the rugged service encountered.

• The primary element of wire rope is the individual wires.

• Wires are carefully selected, sized, and layered into strands. After stranding, the strands are layered together around a core to form wire rope.



• The core may be a fiber rope (either natural grown fibers or man-made fibers), a plastic core, a spring steel core, a multiple-wire strand, or an independent wire rope (IWRC).

• The independent wire rope is the most widely used because it resists crushing and distortion.

• The wire rope is usually described by type of core, the number of strands wrapped around the core, and the number of individual wires per strand.



• For example, a 6 x 19 with an independent IWRC is a typical type of rope used as drilling line.

• It contains one independent wire rope core, six strands, with nineteen separate wires per strand.

• Wire rope is usually furnished preformed but can be furnished non-preformed upon special request.



• A preformed rope has the strands shaped to the helical form they assume in the finished rope before the strands have been fabricated in to the rope.

• The strands of the preformed rope will not spring from the normal position when the sizing bands are removed.




Typical wire-rope construction with correct ordering descriptions COMMITMENT TO ACADEMIC AND


• The lay of the rope describes the direction of the strand wrap around the core and the direction of the wire rope around within the strands.

• The strands may be right or left lay. • The individual wires can be regular or lang lay.

• The length of the lay is usually 7.25-8 times the nominal diameter.


Lay of the RopeCOMMITMENT TO ACADEMIC AND INDUSTRIAL EXCELLENCE 170

• The nominal strength of the wire rope depends on the material used in construction, the number of strands and wires, and the size of the rope.

• The API has published Tables for breaking strengths of various wire ropes.

• As an example, the nominal strength of 13/8”, 6 x 37 drawn galvanized IWRC rope is 192,000 lb.



• The API has established minimum design factors for wire ropes operating under oilfield conditions.

• These design factors are specified in API Recommended Practice 9B.

• When working near the minimum design factor, consideration should be given to the efficiencies of wire rope bent around sheaves, fittings or drums.



• The minimum design factors are as follows:

• The primary function of the wire rope in conjunction with other components of the hoisting system is to provide a mechanical advantage (M) for raising or lowering the drillstring or casing.

• If the tension line in the fast line attached to the drawworks is defined as TF, then the mechanical advantage is as follows:


Type of Service Minimum Design FactorCable tool line 3Sand line 3Hoisting service other than rotary drilling 3Mast hoisting and lowering 2.5Rotary drilling line when setting casing 2Pulling on stuck pipe and similar infrequent operations 2


– where:• L = hook load, lb• TF = fast-line tension, lb• M = mechanical advantage

• The fast-line tension can be computed, if an ideal system is considered:

– where N = number of lines strung over the block system.



• Since block efficiency (EB) must be considered in a non-ideal case, the fast-line tension is as follows:

• The horsepower (HP) required to lift a load, L, at some velocity is given by:

– where :• V = velocity in ft/min, and• 33,000 = ft-lb/min/hp

• This equation is very useful in determining the amount of input horsepower requirements from the prime movers.




Breaking Strengths of various Wire RopesCOMMITMENT TO ACADEMIC AND INDUSTRIAL EXCELLENCE 176

• Example: A 13/8”, 6 x 37 galvanized IWRC rope (EIPS) is to be used when running a 425,000 lb casing string. The company intends to rig-up a 10 line system. Determine if the rope meets the design factor criteria of 2.0. Assume an efficiency of 0.98 per sheave.

• Solution:– The efficiency factor (EB) for a 10 line system is:EB = (0.98)n = (0.98)10 = 0.817

– The fast-line tension (TF ) is computed from:

= (425,000 lbs)/(10)(0.817) = 52,019 lbs

– The load factor is given by:Load factor = 192,000/52,019 = 3.69

– Therefore, the rope meets the design factor of 2.0.



• Block system and drawworks efficiency must be considered:

– where:• HPB = block horsepower,• HPE = engine horsepower,• EB = block efficiency, and• ED = drawworks efficiency.

• Wire rope requires lubrication to extend its life.

• The strands rub against one another as the rope flexes over sheaves in the travelling and crown blocks.



• Because wire rope eventually becomes too worn for use, it is an expensive item in the drilling process.

• The usual practice is to evaluate the number of ton-miles of work performed by the wire rope.

• A ton-mile is defined as the amount of work needed to move a 1-ton load over a distance of 1 mile.

• After a rope has reached a specific ton-mile limit, it is removed from service.



• The limits vary for different operations and may range from about 500 for 1.0” rope to about 1,800 for 13/8” rope.

• Drilling line is cut (a portion is retrieved) before any critically strenuous job.

• The major factors affecting ton-mile wear on the wire rope are:– round trips.– setting casing.– drilling.



• The following equation computes ton-miles during a round trip:

– where:•TR = ton-miles during a trip.•D = hole depth, ft.•LS = length of drill pipe stand, ft.•WM = effective weight per foot of drill pipe, lb/ft.



•M = total weight of travelling block-elevator assembly.

•C = effective weight of drill-collar assembly minus the effective weight of the same length of drillpipe, lb/ft.

• Similar equations are provided in API RP 9B for coring, drilling and setting casing.

• M is the weight of the travelling block assembly.



• It includes the travelling block, hook, links and elevators.

• If the actual weight of the travelling block assembly is unknown, the following approximate values may be used:


Travelling Block Capacity, tons

Assembly Weight, lb

100 6,000150 9,000250 12,000350 19,000500 28,000650 35,000750 48,000COMMITMENT TO ACADEMIC AND


• In addition to fatigue wear from accumulated ton-miles of service, the wire rope will wear more at lap and pickup points.

• The pickup points are on the top side of the crown block when the weight of the drill string is lifted from the supports in the rotary table during tripping operations.

• The lap points on the draw works drum occur when the line begins to new wrap.



• Slip and cut programs are designed to avoid excessive wear at the lap and pickup points.

• Slipping involves loosening the deadline anchor and placing a few more feet of line into service from the storage reel.



• Cutting requires that the line on the draw works reels be loosened and a section cut and removed.

• Slipping changes the pickup points, and cutting changes the lap points.

• A line is usually slipped several times before it is cut.



KELLY A Kelly is a square or hexagonal length of pipe that fits into a bushing in the rig's rotary table. As the rotary table turns to the right, the Kelly turns with it.

The main function of a Kelly is to transfer energy from the rotary table to the rest of the drill string.

SWIVEL It suspends the drill string and allows rotation at the same time.

KELLYROTARY TABLE

RAT HOLE

ROTATING SYSTEM


DRILL PIPESDrill pipes furnish the necessary length for the drill string and serves as a conduit for the drilling fluid

DRILL COLLARSProvides weight and stability to the drill bit, maintain tension on the drill pipe and help keep the hole on a straight course

ROTATING SYSTEM


• HEAVY WALL DRILL PIPES provides additional hole stability and aids in directional control

• STABILIZERS centralize the drill

collars, help maintain the hole at full-gauge diameter

• JARS provide sharp upward

or downward impact to free stuck pipe

• REAMERS helps to maintain a

full-gauge hole diameter• CROSSOVER SUBS which join components

having different types of connections.

ROTATING SYSTEM


BITS:•Most critical component in rotary drilling operations. Different types of bits.

•Two main type of bits:•Rolling cutter bits - consist of cutting elements arranged on cones (usually three cones, but sometimes two) that rotate on bearings about their own axis as the drill string turns the body of the bit. These bits can have teeth or buttons

ROTATING SYSTEM


• Fixed cutter bits - also known as drag bits, consist of stationary cutting elements that are integral with the body of the bit and are rotated directly by the turning of the drill string.

• The principal types of fixed cutter bits are:

• natural diamond • polycrystalline diamond compact (PDC)

ROTATING SYSTEM


• The rotating system includes all the equipment used to achieve bit rotation.

• A principal feature of the rotating system is the rotary table, or rotary.

• The rotary table is powered by the prime movers to rotate the kelly, which is raised or lowered through the kelly drive bushing.

ROTATING SYSTEM


• The rotation of the kelly causes the drill stem and bit to turn and thus “make hole” as the bit grinds away the rock formation.

• The kelly is supported by the hoisting system.

• Drilling fluid is pumped down the drill pipe to the bit and then up the annulus.

ROTATING SYSTEM


ROTATING SYSTEM

The Rotating

System


• The rotary is the piece of equipment that gives the rotary drilling rig its name.

• It is the machine that turns the drill stem and the bit in order to make hole.

• A rotary table is fitted with a drive bushing.

ROTARY, KELLY AND SWIVEL


• The three-, four-, six-, or eight-sided kelly fits through the bushing and is thus turned by the rotary.

• The rotary is a basic yet extremely rugged machine that is distinguished by its ability to withstand hard service.

• The drive bushing may fit in a square opening in the rotary tale, or four pins that fit in the openings of the table may drive it.



• The drive bushing permits vertical movement of the kelly as the hole is deepened, at the same time rotating the drill stem.

• The rotary serves two main functions:– to rotate the drills stem; and– to hold friction-grip devices called slips to support the drill stem or casing.



• A sprocket and chain may mechanically drive the rotary from the drawworks.

• However, many drilling rigs provide power to an electric motor that drives the rotary directly.

• In some cases, an independent engine is used to drive the rotary.



• The kelly is the top member of the drill stem.

• It is about 40 feet long and may be either triangular-, square-, hexagon- or octagon-shaped to fit its drive bushing.

• The kelly can move freely up and down through the drive bushing while the rotary is turning it.



• The swivel hangs from a hook under the travelling bloc, and serves several vital functions.

• It supports the weight of the drill stem.

• It allows rotation of the drill stem.

• It provides a passageway for drilling fluid to enter the drill stem.



• The rotary hose is connected to a gooseneck-fitting on the swivel.

• Drilling fluid is pumped into the gooseneck, through the swivel, and down the kelly.

• This fluid may be under pressure exceeding 3,000 psi.



• A drilling bit is the cutting or boring tool which is made up on the end of the drillstring.

• The bit drills through the rock by scraping, chipping, gouging or grinding the rock at the bottom of the hole.

• Drilling fluid is circulated through passageways in the bit to remove the drilled cuttings.

DRILLING BITS


• There are however many variations in the design of drillbits and the bit selected for a particular application will depend on the type of formation to be drilled.

• The drilling engineer must be aware of these design variations in order to be able to select the most appropriate bit for the formation to be drilled.

DRILLING BITS


• The engineer must also be aware of the impact of the operating parameters on the performance of the bit.

• The performance of a bit is a function of several operating parameters, such as: – weight on bit (WOB).– rotations per minute (RPM). – mud properties.– hydraulic efficiency.

• There are basically three types of bit:– Drag Bits.– Roller Cone Bits.– Diamond Bits.

DRILLING BITS


• Drag bits were the first bits used in rotary drilling, but are no longer in common use.

• A drag bit consists of rigid steel blades shaped like a fish-tail which rotate as a single unit.

• These simple designs were used up to 1900 to successfully drill through soft formations.

DRAG BITS


• The introduction of hardfacing to the surface of the blades and the design of fluid passageways greatly improved its performance.

• Due to the dragging/scraping action of this type of bit, high RPM and low WOB are applied.

DRAG BITS


DRILLING BITS

Types of Drilling Bit


• The decline in the use of drag bits was due to:– The introduction of roller cone bits, which could drill soft formations more efficiently

– If too much WOB was applied, excessive torque led to bit failure or drill pipe failure

– Drag bits tend to drill crooked hole, therefore some means of controlling deviation was required

– Drag bits were limited to drilling through uniformly, soft, unconsolidated formations where there were no hard abrasive layers.

DRAG BITS


• Roller cone bits (or rock bits) are still the most common type of bit used worldwide.

• The cutting action is provided by cones which have either steel teeth or tungsten carbide inserts.

• These cones rotate on the bottom of the hole and drill hole predominantly with a grinding and chipping action.

• Rock bits are classified as milled tooth bits or insert bits depending on the cutting surface on the cones.

ROLLER CONE BITS


• The first successful roller cone bit was designed by Hughes in 1909.

• This was a major innovation, since it allowed rotary drilling to be extended to hard formations.

• The first design was a 2 cone bit which frequently balled up since the teeth on the cones did not mesh.

• This led to the introduction of a superior design in the 1930s which had 3 cones with meshing teeth.

ROLLER CONE BITS


• The same basic design is still in use today although there have been many improvements over the years.

• The cones of the 3 cone bit are mounted on bearing pins, or arm journals, which extend from the bit body.

• The bearings allow each cone to turn about its own axis as the bit is rotated.

• The use of 3 cones allows an even distribution of weight, a balanced cutting structure and drills a better gauge hole than the 2 cone design.

ROLLER CONE BITS


• The major advances in rock bit design since the introduction of the Hughes rock bit include:– Improved cleaning action by using jet nozzles– Using tungsten carbide for hardfacing and gauge protection

– Introduction of sealed bearings to prevent the mud causing premature failure due to abrasion and corrosion of the bearings.

ROLLER CONE BITS

Milled Tooth Bit

Insert BitCOMMITMENT TO ACADEMIC AND


ROLLER CONE BITS

Elements of a Rock Bit COMMITMENT TO ACADEMIC AND


• Diamond has been used as a material for cutting rock for many years.

• Since it was first used however, the type of diamond and the way in which it is set in the drill bit have changed.

• There are three types of diamond bits:– Natural Diamond Bits.– PDC Bits.– TSP Bits.

DIAMOND BITS


• The hardness and wear resistance of diamond made it an obvious material to be used for a drilling bit.

• The diamond bit is really a type of drag bit since it has no moving cones and operates as a single unit. Industrial diamonds have been used for many years in drill bits and in core heads.

• The cutting action of a diamond bit is achieved by scraping away the rock.

NATURAL DIAMOND BITS


• The diamonds are set in a specially designed pattern and bonded into a matrix material set on a steel body.

• The major disadvantage of diamond bits is their cost (sometimes 10 times more expensive than a similar sized rock bit).

• Despite its high wear resistance diamond is sensitive to shock and vibration and therefore great care must be taken when running a diamond bit.



• Effective fluid circulation across the face of the bit is also very important to prevent overheating of the diamonds and matrix material and to prevent the face of the bit becoming smeared with the rock cuttings (bit balling).

• There is also no guarantee that these bits will achieve a higher ROP than a correctly selected roller cone bit in the same formation.

• They are however cost effective when drilling formations where long rotating hours (200-300 hours per bit) are required.



• Since diamond bits have no moving parts they tend to last longer than roller cone bits and can be used for extremely long bit runs.

• This results in a reduction in the number of round trips and offsets the capital cost of the bit.

• This is especially important in areas where operating costs are high (e.g. offshore drilling).

• In addition, the diamonds of a diamond bit can be extracted, so that a used bit does have some salvage value



• A new generation of diamond bits known as polycrystalline diamond compact (PDC) bits were introduced in the 1980’s.

• These bits have the same advantages and disadvantages as natural diamond bits but use small discs of synthetic diamond to provide the scraping cutting surface.

• The small discs may be manufactured in any size and shape and are not sensitive to failure along cleavage planes as with natural diamond. PDC bits have been run very successfully in many areas around the world.

PDC BITS


• PDC Bits have been particularly successful (long bit runs and high ROP) when run in combination with turbodrills and oil based mud.

PDC BITS

Polycrystalline Diamond Compact (PDC) Bits


• A further development of the PDC bit concept was the introduction in the later 1980’s of Thermally Stable Polycrystalline (TSP) diamond bits.

• These bits are manufactured in a similar fashion to PDC bits but are tolerant of much higher temperatures than PDC bits.

TSP BITS


FLUID CIRCULATING SYSTEM


• Mud Cycle at a Wellsite:

• Most of the mud used in a drilling operation is re-circulated in a continuous cycle:

– Mud is mixed and kept in the mud pit. – A pump draws it out of the mud pit and sends it, through the hollow center of the drill pipe, down into the borehole.

– Mud emerges from the drill pipe at the bottom of the borehole where the drill bit is grinding away at the rock formation.



– Now the mud begins the return trip to the surface carrying the pieces of rock, called cuttings, that have been scraped off the formation by the bit.

– The mud rises in the annulus, the space between the drill pipe and the walls of the borehole.

– The typical diameter of a drill pipe is about 4 inches (10 centimeters).

– At the bottom of a deep well, the borehole might be 8 inches (20 centimeters) in diameter.At the surface the mud travels through the mud return line, a pipe that leads to the shale shaker.



– The shale shakers consist of a series of vibrating metal screens which are used to separate the mud from the cuttings.

– The mud drips through the screens and is returned to the mud pit.The rock cuttings slip down the shale slide to be disposed of.

– Depending upon environmental and other considerations, they may be washed before disposal.Some of the cuttings are taken to be examined by geologists for clues about what is going on deep down inside the well.



MUD PUMPS Their function is to

circulate the drilling fluid at the desired pressure and volume.

The pumps normally used for this service is reciprocating piston, double acting and duplex type.

STANDPIPE A rigid metal conduit that

provides the high-pressure pathway for drilling mud to travel approximately one-third of the way up the derrick where it connects to a flexible high-pressure hose (kelly hose)

Many large rigs are fitted with dual standpipes so that downtime is kept to a minimum if one standpipe requires repair



• The circulating system sends drilling fluid from a mud pit through the mud pump, standpipe, rotary hose, swivel, kelly, drill pipe, drill collars, bit, annulus and back to the pit.

• The hydraulic power of the drilling fluid passing through the bit cleans the bottom of the hole and produces more effective drilling.

• Under special circumstances, a mud motor or turbodrill is used to turn the bit. In this case, hydraulic power of the drilling fluid (instead of rotation of the drill stem) turns the bit.



• If rigs did not require mobility and quick rig-up and tear-down capability, they could be designed to require less power for hoisting, pumping and other jobs.

• • Hydraulic rigs have been built, but they are heavy, slow and troublesome to operate.

• The best means of hoisting drill pipe is the block-and-tackle arrangement that is generally employed.



• An essential feature of the rotary drilling process is the circulating system, commonly called the mud system. In order for rotary drilling to proceed, the drilled cuttings must be lifted out of the hole.

• Fluid must be pumped down through the annulus (the space outside the drill string).

• The principal purposes of circulating fluid are:– cleaning the bottom of the hole by washing the cuttings back up to the surface;

– cooling the bit;– supporting the walls of the well; and– preventing entry of formation fluid into the borehole.



• The circulation fluid is usually a liquid, but it may be air or gas. Water is the usual base, though occasionally oil is used.

• A pump forces the drilling fluid up through a standpipe hose into the swivel, down through the drill stem, and back to the surface again (where it returns to the mud pits).

• The mud pits or tanks are usually fitted with solids-control equipment, which removes cuttings and other solid material in mud brought up from the hole before it is recirculated into the well by the mud pump.



• When air is used as drilling fluid, compressors replace the mud pump and there is no need for storage pits and settling tanks.

• Compressed air is forced down the drill stem to the bit and up the annulus by air pressure.

• Most mud pumps currently used in the drilling industry are duplex or triplex positive displacement pumps.



The Circulating System



PRIME MOVERS These are used to supply power to drilling operations.

These can be steam engines, electric motors or internal combustion engines

The bulk of rig power is consumed in two operations namely: circulation of

fluid. and hoisting.


POWER SYSTEM

• Drilling rigs, and their support vessels in the case of barge and floating vessels, have high power requirements.

• Some of the equipment requiring power includes the drawworks, mud pumps, rotary system and life-support system.

• The power loading may be continuous or intermittent.

• The power system on a drilling rig usually consists of a prime mover as the source of raw power and some means to transmit the raw power to the end-use equipment.

• The prime movers used in the current drilling industry are diesel engines.

POWER SYSTEM


The Diesel Engines in use on this rig are located on the ground, some distance away from the rig

POWER SYSTEM


• Steam is no longer a source of rig power, since natural gas (which was used to fire the boilers) has increased dramatically in cost.

• Internal-combustion engines and electricity now power most drilling rigs.

• Large rigs and most wheel-mounted assemblies are generally powered by diesel engines.

POWER SYSTEM


• Most prime movers are diesel engines, although engines that use natural gas or liquefied petroleum gas (LPG) in the form of propane or butane drive some rigs.

• Drilling rig engines range from 250 to 2,000 horsepower (hp) each; total rig power may be 500 to 5,000 hp.

• On a mechanical-drive rig, a means of transmitting the power from the engines to the drawworks, pumps, and rotary must be provided.

POWER SYSTEM


• This transmission is usually accomplished through an assembly known as the compound, which consists of clutches, couplings, shafts, chains and sprockets.

• The most widely used system on new rigs or large marine rigs is the AC-SCR system.

• The mechanical horsepower requirement for the prime movers must be determined from an evaluation of the loads and the overall system efficiency.

POWER SYSTEM


• Mechanical Efficiency is given by:

o where the efficiency is less than 1.0.• Although the above equation is straight forward,

it is difficult to implement due to problems in establishing the load and efficiency factor.

• The efficiency factor (E) describes the power losses from the prime movers to the end use equipment.

• It can be calculated from:

POWER SYSTEM


o where output is from the prime mover and input is the amount remaining for actual usage after some losses.

• The system losses result from friction, gears and belt line losses.The efficiency factors range from 0 – 1.

• Some oilwell drilling personnel assume that efficiency for oilwell drilling machinery are 0.98 per shaft and chains.

• If more than engine is used, an average value is calculated.

POWER SYSTEM


• The mechanical horse power requirements must be modified for harsh temperature environments or altitudes.

• According to API Standard 7B-11c, approximate conversions for altitude temperature of naturally aspirated engines may be made as follows:

• deduct 3 % of the standard brake horsepower for each 1000 ft rise in altitude above sea level.

• deduct 1 % of the standard brake horsepower for each 100 rise in temperature above 850 oF or add 1 % fall below 850 oF

• The engine manufacturer should be consulted for specific variances.

POWER SYSTEM


BLOWOUT PREVENTERS (BOP)

If the formation pressure is more than the imposed by drilling fluid, in this case formation fluids flow into borehole and eventually to the surface.

This effect is called blowout.

The main function of blowout preventers is to close the annular space between the drill pipe and casing.

WELL CONTROL SYSTEM


• Drilling fluid in the hole helps prevent formation fluid from entering the borehole.

• If formation fluid does enter the well, it may rise to the surface and cause some of the drilling fluid to flow out of the hole.

• If the drilling crew cannot control the flow, it is called a kick.

• If the flow is continuous and cannot be controlled, a blowout has occurred.

• A blowout preventer (BOP), in conjunction with other equipment and techniques, is used to shut off and control a kick before it becomes a blowout.

WELL CONTROL SYSTEM


• Several BOPs are usually installed on top of a well, with an annular preventer above and two or more ram preventers below.

• An annular preventer has a resilient sealing element.

• When activated by fluid pressure, the sealing element closes on the kelly, drill pipe or drill collars.

BLOWOUT PREVENTERS


• Ram preventers have two steel ram segments that are pushed together from both sides to seal around drill pipe.

• Both annular and ram preventers are operated by hydraulic fluid pressure.

• Blind ram preventers can be used to close an open hole (hole with no drill pipe in it).

• Blowout preventers are opened and closed by hydraulic power.

BLOWOUT PREVENTERS


• The fluid is stored under pressure in an accumulator.

• High-pressure lines carry the hydraulic fluid from the accumulator to the BOP stack.

• When the driller turns the proper valves, the fluid operates the BOPs.

• Because the preventers must be able to close quickly, the hydraulic fluid is put under 1,500 to 3,000 psi of pressure by nitrogen gas in the accumulator unit.

BLOWOUT PREVENTERS


BLOWOUT PREVENTERS

Blowout Preventers


Depth ROP Hook load Rotary speed Rotary torque Pump rate Pump pressure

Mud density Mud temperature Mud salinity Mud gas content Hazardous air gas content

Pit level Mud flow rate

WELL MONITORING SYSTEM Safety and efficiency considerations require constant monitoring of the well to detect drilling problems quickly.

Devices record or display parameters such as:


ANALOG AND DIGITAL MONITORING PANELS

Monitoring Panels


• Good historical records of various aspects of the drilling operation:– assists the driller to detect drilling problems.

– aids geological, engineering and supervisory personnel.

• In some cases, a centralized well-monitoring system housed in a trailer is used.

• The centralized well-monitoring system provides detailed information about:– formation being drilled.– fluids being circulated to the surface in the mud.

WELL MONITORING SYSTEM


• The mud logger carefully inspects rock cuttings taken from the shale shaker at regular intervals and maintains a log describing their appearance.

• Additional cuttings are labelled according to their depth and are saved for further study by the paleontologist.

• Gas samples removed from the mud are analyzed by the mud logger using a gas chromatograph.

• There have been significant advances in sub-surface well-monitoring and data-telemetry systems.

• These systems are especially useful in monitoring hole direction in non-vertical wells.



• The control panel for operating the BOP stack usually is placed on the derrick floor for easy access by the driller

• When the drillstring is in the hole, the BOP stack can be used to stop only the flow from the annulus

• Additional valves which can be used to prevent flow from inside the drillstring include:– kelly cocks.– internal kelly cocks.– internal blowout preventers.



• Electric Generators:– Modern rotary rigs provide power for auxiliaries with AC generators that are usually diesel-powered.

– Most of these generators have capacities of 50 to 100 kilowatts, although larger units are sometimes installed.

– The generators have enough capacity to carry the main power load of the rig (excluding hoisting, pumping, and rotating functions).

– A second engine and generator unit are held in ready reserve.

– AC electricity is used for rig lighting, shale shaker motors, mud pit stirrers, centrifugal pumps, rig instruments, engine cooling fans, air conditioning for bunkhouses and other purposes.

AUXILIARIES


• Air Compressors:– A small compressor is usually mounted on the engine compound for supplying air to the pneumatic controls and clutches.

– The compressor has a volume tank to allow reserve storage of compressed air.

– Large rigs usually have another electrically powered compressor to furnish high-pressure air for other purposes, such as starting the main engines and operating air-powered hoists, air slips, BOP equipment, water wells and air-operated tools.

AUXILIARIES


• Water Pumps:– Water supply is an important item for drilling rig operations. Water is usually obtained from a well, stream, lake or pipeline from a remote source.

– A stored supply of several hundred barrels is maintained at the rig.

– This may be in a pit or tank(s) of sufficient capacity to maintain operations for a short time if the primary supply is interrupted. Low-pressure water pumps are usually provided for wash down and for cooling the brakes of the drawworks.

– High capacity pumps are generally used for mud and cement mixing and mud transfer.

AUXILIARIES


• Other Equipment:– Drilling rigs also include such facilities as fuel storage tanks, a house for changing work clothes, a doghouse (a small structure on the rig floor that serves as an office for the driller), a place to store parts for the pumps and other equipment, and other facilities.

– Most large rigs are provided with an office trailer where the supervisors can maintain communications with the head office.

AUXILIARIES


WELL PLANNING, PROCEDURES AND COSTS


WELL PLANNING• Well Planning involves the preparation of good drilling programmes for safe and effective oilwell drilling, testing and completion.

• The well planner must collate all available data and technology and apply same to meet the well objectives as cheaply, efficiently and safely as possible


WELL PLANNING PROCESS• Well Planning can be broken down into:– Definition of Well Objectives– Obtaining Consent to drill from Authorities

– Collection and Scrutiny of Data– Estimation of Formation Pressure Regimes

– Estimation of Formation Fracture Gradients

– Drilling Programme Preparation– Rig Specification– Authorization for Expenditure (AFE) Preparation


DEFINITION OF WELL OBJECTIVES• Wells can be exploratory, appraisal or development

• Planning of the first two groups is initiated by the exploration departments which will also define objectives

• Planning of development wells is usually initiated by the production departments which will also define objectives COMMITMENT TO ACADEMIC AND


OBTAINING CONSENT TO DRILL FROM AUTHORITIES

• The energy authorities in each country of operation award exploration licenses to operators

• The responsibility of each operator is to comply with all the local rules and regulations

• The well programme must accommodate all the rules and regulations


COLLECTION AND SCRUTINY OF DATA• The formation pore pressure must be estimated as

accurately as possible

• The two sources of well pressure data are:– geophysical/geological data– offset well data

• Structure maps are produced by the geologists from seismic and offset well data.

• Interpretation of the seismic data can enable the geologist to identify subsurface structures that have the potential to trap hydrocarbon accumulations.

• By correlating formation tops from the lithological columns of offset wells and interpolating at the point of interest, a geological prognosis can be made of the proposed well. COMMITMENT TO ACADEMIC AND


ESTIMATION OF FORMATION PRESSURE REGIMES

• Most sediments naturally have a pressure profile similar to that of seawater since they were laid down in a marine environment.

• Such sediments are said to have hydrostatic pressures.

• Higher pressure can be encountered due to: – artesian wells, – gas caps, – salt beds, – sediment compression, – mineralization, and – surcharged formations.COMMITMENT TO ACADEMIC AND


• Formations can also be sub-normally pressured due to:– depletion,– faulting, and– artesian wells.

• Formation pressures can be estimated:– from local and regional geology,– using production well data, and– using offset well data.

ESTIMATION OF FORMATION PRESSURE REGIMES


ESTIMATION OF FORMATION FRACTURE GRADIENTS

• It is vital to have a good estimate of the formation fracture gradient so that the casing design can be done in an effective manner

• Prediction can be based on anticipated geology and offset well records. Most rocks of a certain type will exhibit typical characteristics

• Once a leak off test has been carried out in the well, equations such as Daines’ are used by employing values of Poisson’s ratio for given formations to estimate probable fracture gradients at other depths in the wellCOMMITMENT TO ACADEMIC AND


DRILLING PROGRAMME PREPARATION• Drilling Programmes can be broken into 14 main sections:

– Well Details– Well Objectives– Casing Design– Wellhead Selection– BOP Requirements– Cementing Programme– Deviation Programme– Survey Requirements– Mud Programme


DRILLING PROGRAMME PREPARATION– Bits and Hydraulics Programme– Evaluation Requirements– Operational Procedure and Time-Depth Graph Construction

– Site Plan– Reporting Requirements and Contact Numbers

• All drilling programmes will contain the above information in some form.

• Specialized wells could also contain other relevant data.


WELL DETAILS• This is a brief summary of the well location, type,

depth, operatorship and ownership• A typical layout of this is given below:

– Well Name: Gondwana 3– Well Type: Appraisal– Country: Moldavia– Block: 20/12– Surface Co-ordinates: N:225,710 m; E:364,800 m– Target Size: 200 ft radius– Target Depth TVDSS: 10, 000 ft– Target Depth AHSS: 10, 000 ft– Water Depth: 200 ft– Operator: Alpha Oil Co. (60 %)– Partner Interest: Beta Oil Co. (40 %)– Name of Rig: Humble 12– Type of Rig: 15M Jack-up– Seabed Condition: Sand/Silt Flat– Expected Spud Date: 3rd Quarter, 2007


• A typical format for setting out the well objectives is as follows:– The Gondwana 3 is an appraisal well whose objective is to establish the presence of the Heuy, Louey and Doney sandstones at about 10, 000 ft.

– All three sands will be cored and depending on findings, be production and injectivity tested.

– After testing, the well will be either plugged back and abandoned or suspended for later use as an injection well.

WELL OBJECTIVES


CASING DESIGN• A major part of the design work involves

the construction of the Pressure Profile Chart showing expected pore pressures and fracture gradients

• The following minimum data is required:– The prognosed lithological column– Offset wells pore pressure data– Offset wells fracture gradient data– Wellhead selection

• The pressures obtained must be depth matched to the relevant information on the prognosed geological column


• The final hole size for logging and the likely production string must both be given consideration.

• The gradient of the fluid within the reservoir is important during casing burst design.

• A gas gradient is always used in the reservoir.

• The general criterion for the selection of casing shoe depths is that the formation above it can be drilled safely and successfully.

CASING DESIGN


• The following are the criteria which must be considered when carrying out detailed casing design: – Burst– Collapse– Tension– Compressional effects

• Burst is pipe failure which occurs when the pressure inside the pipe is greater than the internal yield of the pipe plus the pressure outside the pipe.

CASING DESIGN


• Collapse will occur when the external force on the pipe is greater than the combination of the internal forces plus the collapse rating. It occurs as a result of either or a combination of:– Reduction in hydrostatic head exerted by the fluid inside the pipe

– Increase in hydrostatic head exerted by the fluid outside the pipe

– Mechanical forces created by plastic formations, squeezing salts

• Tensile failure will occur if the pull exerted on the pipe is too great for the tensile strength of the pipe or coupling

• Compressional forces occur in casing due to temperature in landed casing and because of the weight of other inner casing strings which must be supported by the outer strings.

CASING DESIGN


WELLHEAD SELECTION• When the casing design is completed, we have all the information to select the wellhead

• The wellhead must be of the correct pressure rating, designed for the desired service (H2S or whatever) and be capable of accommodating all designed and contingent casing sizes

• The final choice is made based on:– Cost – Ease of operation– Operator’s personal preferences

• After the choice is made, its specification should be included in the Drilling Programme along with a sectional view of its component stack up.


BOP SELECTION• The BOP requirements for a given well depends on company policy and anticipated bottomhole pressures.

• The information should be presented in a format such as:

Hole size (inches)

BOP Requirements

Rating (psi)

26 Nil171/2 Nil121/4 2x Rams 10,000

1x Shear 10,0001x Annular 5,000COMMITMENT TO ACADEMIC AND


CEMENTING PROGRAMME• Cement is used for zonal isolation in the well.

• The effectiveness of this zonal isolation depends on:– Slurry design – Displacement methods– Casing accessories selection

• All the three factors must be considered at the planning stage.


WELL DEVIATION PROGRAMME• To decide on the correct option for a deviated well, the first consideration is how much drift from the surface location is required.

• High drift wells need to be kicked off high in the hole to achieve extended reach without having too high a hole angle.

Downhole Motor SystemCOMMITMENT TO ACADEMIC AND


WELL DEVIATION PROGRAMME• Small drift wells should be kicked off deeper in the well due to the difficulty encountered in trying to hold hole direction with a hole direction of less than 15o.

• The most common method in both shallow and deep kick-offs is the use of a drilling motor mounted on a bent sub.

• Hole angles in the range of 15 - 65o

are common. Build-up rates are usually around 21/2o/100 ft.


• Surveying is done to determine exactly where the hole is.

• Surveying is done for two main reasons:– Reservoir management – Relief well planning

• In each country, the energy authorities set the minimum survey requirements which must be met by the operating company.

SURVEY REQUIREMENTS


MUD PROGRAMME• Mud Programming is broken down into:

– Determination of mud weight requirements to maintain primary well control

– Determination of suitable ‘trip margin’ which is added to the primary well control weight to give a programmed mud weight

– Confirmation that this mud does not exceed formation strengths when considered in a dynamic (circulated mode)


– Analysis of formations to be drilled and the likely reaction of these to available drilling fluid alternatives

– Determination of fluid loss requirements

– Determination of pH requirements– Determination of viscosity requirements– Determination of temperature stability requirements

– Analysis of rig mud treatment equipment to meet hole requirements with selected mud types

MUD PROGRAMME


BIT AND HYDRAULICS• To select a bit the following factors are considered:

– Formation drillability and characteristics.

– Mud system in use.– Directional implications.– Bit drive methods.– Bit availability and cost.


EVALUATION REQUIREMENTS• The well evaluation requirements necessary to meet the well objectives should treated under the following headings:

– Drilling log requirements.– Mud logging requirements. – Coring requirements.– Testing requirements.– Electric logging requirements.– Measurement-while-drilling (MWD) requirements.


OPERATIONAL PROCEDURES AND TIME-DEPTH GRAPH CONSTRUCTION

• If the Drilling Operations Manual is comprehensively written, then no operational procedures need be included in the Drilling programme.

• If there is no manual available or the quality is poor, then the operational procedure section of the drilling programme should be a step-by-step guide to what has to be done in the well.

• The Time-Depth graph is a tool used to show the expected well status at any time from spud to completion or plug back and abandon.


OPERATIONAL PROCEDURES AND TIME-DEPTH GRAPH CONSTRUCTION• The time-depth graph uses time along the x-axis (usually in days) and depth along the y-axis with zero depth at the upper end of the axis.

• Both axes should be approximately 20 per cent longer than initial time and depth estimates would indicate to allow programme changes.

Drilling Time-Depth Graph


• The phases of most exploration wells can be listed along the following lines:S/N Phase Time1 Pre-spud preparation2 Drilling top hole3 Run and set surface casing4 Drill5 Set intermediate casing6 Drill7 Core8 Drill9 Log10 Test11 Plug back and abandon

OPERATIONAL PROCEDURES AND TIME-DEPTH GRAPH CONSTRUCTION


SITE PLAN• A site plan should be included in each programme showing the following features:

– For all wells: The licence area in which the well is being drilled. The position of the well relative to other outstep wells.

– For land wells: Access roads and instructions on how to reach the site.

– For offshore wells: Details of any seabed obstructions, pipelines, etc., in the area that the well is being drilled in.

• In practice, to satisfy the above requirements, two plans will need to be included in most Drilling Programmes.

• Some operators include a reservoir map in this section.


REPORTING REQUIREMENTS AND CONTACT NUMBERS

• In this section, the reporting requirements are listed.

• This lays down clearly who should receive what information or samples, by what means, when and how often.

• All relevant phone numbers and addresses must be included in this section.


DRILLING COST• To optimize drilling operations, we have to specify the yardstick by which performance is measured

• The most relevant yardstick is cost per foot drilled

• Overall cost must be looked at since individual costs can be misleading

• To optimize drilling economics, we must achieve the objectives of the well as economically as possible

• To do this, we must understand the cost allocations and proportions in drilling operations and use our technology to fine-tune these to reduce expenditure without affecting safety or efficiency


DRILLING COST SPECIFICATIONS• Drilling costs can be broken down into three:– Fixed.– Daily.– Unit.

• Fixed costs are those which are determined mainly by the nature of the well:– Wellheads.– Site preparation.– Casing, cement, packers and tubing.

• Effecting economics in fixed costs is the direct responsibility of the Drilling Manager and the Drilling Engineers who plan the well.

• The Drilling Supervisor has little impact on fixed costs.


• Daily costs are related to the time spent on the operation.

• On offshore rigs, there are usually the largest items of expenditure and are listed below:– Payments to drilling contractors (rig time).

– Tool rental.– Payment to specialist services.– Salaries and wages.– Fuel.– Lubricating oil and grease.– Drilling consumables (dope, rope and soap).– Transport of materials.

• The Drilling Supervisor on site, the Drilling Manager and Drilling Engineers can all have an effect on daily costs.

DRILLING COST SPECIFICATIONS


• Unit costs are the price of a unit of a commodity such as the price of a tonne of baryte or bentonite.

• Unit costs can usually be optimized during the tendering process, which is usually the responsibility of the Drilling Manager.

• Good site supervision can ensure that consumption is not excessive.

DRILLING COST SPECIFICATIONS


COST BREAKDOWN OF DRILLING OPERATIONS

• A typical average cost comparisons between rig types is as follows:

Total daily drilling costsRig Type Drilling Costs

($/day)Land rig (shallow) 15,000

Land rig (deep) 25,000

Platform rig 50,000

Jack-up rig 95,000

Semi-submersible 75,000COMMITMENT TO ACADEMIC AND


• For offshore wells, it is better to look at a typical cost breakdown for a 1990 UK North Sea exploratory well.

• This is based on a TD of 3500 m with 7-inch casing to TD and includes 4 days of coring and 4 days of testing.

• The total time spent on the well was 60 days.

COST BREAKDOWN OF DRILLING OPERATIONS


Cost Group Cost in US $ (‘000)

% of Well Cost

Location Survey 160 3.0Rig Mob/Demob 270 5.1Rig Positioning 8 0.2Casing 570 10.8Wellheads 180 3.4Rig Costs 1,400 26.6Drilling Equipment Rental

50 0.9

Fishing Tools 9 0.2Drill Bits 140 2.7Mud 220 4.2Cementing 170 3.2Electric Logging 320 6.1MWD 14 0.3Mod Logging 160 3.0

COST BREAKDOWN


Cost Group Cost in US $ (‘000)

% of Well Cost

Coring 60 1.1Directional Control 240 4.5Supply Boats 370 7.0Standby Boats 160 3.0Helicopters 212 4.0Diving/ROV 130 2.5Weather Forecasting 4 0.1Medical Services 3 0.1Testing Equipment 100 1.9Storage/onshore Transport

26 0.5

Contract Staff 250 4.8Base Office 41 0.8TOTAL 5,267 100.0

COST BREAKDOWN


FIXED ITEMS COST BREAKDOWNFixed Item Cost in US $

(‘000)% of Well

CostLocation Survey 160 3.0Rig Mobilization / Demobilization

270 5.1

Casing 570 10.8Wellheads 180 3.4Drill Bits 140 2.7Cementing 170 3.2Electric Logging 320 6.1Coring 60 1.1Testing Equipment 100 1.9Fixed Items Total 1,970 37.3


DAILY ITEMS COST BREAKDOWNDaily Item Cost in US $

(‘000)% of Well

CostRig (56 days @ 25,000) 1,400 26.6Drilling Equipment Rental

50 0.9

Mud Logging 160 3.0Directional Control 240 4.5Supply Boats 370 7.0Standby Boats 160 3.0Helicopters 212 4.0Diving/ROV 130 2.5Storage/onshore Transport

26 0.5

Contract Staff 250 4.8Base Office 41 0.8MWD 14 0.3Daily Items Total 3,053 58.1


UNIT ITEM COST BREAKDOWNUnit Item Cost in US $

(‘000)% of Well

CostMud 220 4.2Unit Item Total 220 4.2


AUTHORIZATION FOR EXPENDITURE (AFE)

• The AFE is the tool that is used to predict the cost of a proposed well.

• Its accuracy depends on the amount of available information used to construct it.

• The AFE is normally broken down into sections to allow operators see at a glance how the various well options compare financially.

• It is normal for most operators to have a 100-point AFE for both onshore and offshore wells.


• Onshore and offshore AFEs are broken down into the following items:– Preparation.– Drilling and Abandonment.– Testing.– Completion.

• Preparation:– It covers the costs incurred to the point at which the rig is brought to location.

– It also includes the costs required to bring the location back to its original condition.



• Drilling and Abandonment:– It assumes drilling to TD, logging and finding nothing of interest.

– The well is proposed for abandonment and costed accordingly.

• Testing:– This covers the additional cost incurred by a testing programme.

– It also includes all the ongoing daily costs associated with the rig.

– The Time Depth Graph created for the Drilling Programme provides an estimate of the days to be spent on the well.



– By costing in the charges for these days, the AFE begins to take form.

– It is good practice to list the assumptions which have been made in the preparation of the AFE.

• Completion:– This is the additional cost incurred once the decision to complete the well has been made.



• Estimating Costs:– If there are similar, recent wells in the area to be drilled, most costs can be estimated fairly readily.

– If you are planning a well in a new area, then the task is much harder.

– By calling up service companies and asking for budgetary figures, the main cost centres can be addressed.



FORMATION PRESSURE

INTRODUCTION• The magnitude of the pressure in the pores of a formation, known as the formation pore pressure (or simply formation pressure), is an important consideration in many aspects of well planning and operations.

• It will influence the casing design and mud weight selection and will increase the chances of stuck pipe and well control problems.

• It is particularly important to be able to predict and detect high pressure zones, where there is the risk of a blow-out.

• In addition to predicting the pore pressure in a formation it is also very important to be able to predict the pressure at which the rocks will fracture.


INTRODUCTION• These fractures can result in losses of large volumes of drilling fluids and, in the case of an influx from a shallow formation, fluids flowing along the fractures all the way to surface, potentially causing a blowout.

• When the pore pressure and fracture pressure for all of the formations to be penetrated have been predicted the well will be designed, and the operation conducted, such that:– the pressures in the borehole neither exceed the fracture pressure,

– nor fall below the pore pressure in the formations being drilled.COMMITMENT TO ACADEMIC AND


FORMATION PORE PRESSURES• During a period of erosion and sedimentation, grains of sediment are continuously building up on top of each other, generally in a water filled environment.

• As the thickness of the layer of sediment increases, the grains of the sediment are packed closer together, and some of the water is expelled from the pore spaces.

• However, if the pore throats through the sediment are interconnecting all the way to the surface the pressure of the fluid at any depth in the sediment will be same as that which would be found in a simple column of fluid.COMMITMENT TO ACADEMIC AND


FORMATION PORE PRESSURES• The pressure in the fluid in the pores of the sediment will only be dependent on the density of the fluid in the pore space and the depth (equal to the height of the column of liquid).

• The pressure of the fluid in the pore space (the pore pressure) can be measured and plotted against depth as shown on the right.

• This type of diagram is known as a P-Z diagram.


P-Z Diagram representing pore pressures

FORMATION PORE PRESSURES• The pressure in the formations to be drilled is often expressed in terms of a pressure gradient.

• This gradient is derived from a line passing through a particular formation pore pressure and a datum point at surface and is known as the pore pressure gradient.

• The reasons for this will become apparent subsequently.

• The datum which is generally used during drilling operations is the Drill Floor Elevation (DFE) but a more general datum level, used almost universally, is Mean Sea Level (MSL).COMMITMENT TO ACADEMIC AND


FORMATION PORE PRESSURES• When the pore throats through the sediment are interconnecting, the pressure of the fluid at any depth in the sediment will be same as that which would be found in a simple column of fluid and therefore the pore pressure gradient is a straight line.

• The gradient of the line is a representation of the density of the fluid.

• Hence the density of the fluid in the pore space is often expressed in units of psi/ft.

• This is a very convenient unit of representation since the pore pressure for any given formation can easily be deduced from the pore pressure gradient if the vertical depth of the formation is known.


FORMATION PORE PRESSURES• Representing the pore pressures in the formations in terms of pore pressure gradients is also convenient when computing the density of the drilling fluid that will be required to drill through the formations in question.

• If the density of the drilling fluid in the wellbore is also expressed in units of psi/ft then the pressure at all points in the wellbore can be compared with the pore pressures to ensure that the pressure in the wellbore exceeds the pore pressure.

• The differential between the mud pressure and the pore pressure at any given depth is known as the overbalance pressure at that depth.


FORMATION PORE PRESSURES• If the mud pressure is less than the pore pressure then the differential is known as the underbalance pressure.

• Fracture pressure gradient of the formations is also expressed in units of psi/ft.

• Most of the fluids found in the pore space of sedimentary formations contain a proportion of salt and are known as brines.


Mud density compared to pore pressure gradient

FORMATION PORE PRESSURES• The dissolved salt content may vary from 0 to over 200,000 ppm.

• Correspondingly, the pore pressure gradient ranges from 0.433 psi/ft (pure water) to about 0.50 psi/ft.

• In most geographical areas the pore pressure gradient is approximately 0.465 psi/ft (assumes 80,000 ppm salt content).

• This pressure gradient has been defined as the normal pressure gradient.

• Any formation pressure above or below the points defined by this gradient are called abnormal pressures.


FORMATION PORE PRESSURES• The mechanisms by which these abnormal pressures can be generated will be discussed below.

• When the pore fluids are normally pressured the formation pore pressure is also said to be hydrostatic. COMMITMENT TO ACADEMIC AND


Abnormal formation pressures plotted against depth for 100 US wells

OVERBURDEN PRESSURES• The pressures discussed above relate exclusively to the pressure in the pore space of the formations.

• It is however also important to be able to quantify the vertical stress at any depth since this pressure will have a significant impact on the pressure at which the borehole will fracture when exposed to high pressures.

• The vertical pressure at any point in the earth is known as the overburden pressure or geostatic pressure.

• The overburden gradient is derived from a cross plot of overburden pressure versus depth.

• The overburden pressure at any point is a function of the mass of rock and fluid above the point of interest.


OVERBURDEN PRESSURES• In order to calculate the overburden pressure at any point, the average density of the material (rock and fluids) above the point of interest must be determined.

• The average density of the rock and fluid in the pore space is known as the bulk density of the rock.


Pore Pressure, Fracture Pressure and Overburden Pressures and Gradients for a Particular Formation

OVERBURDEN PRESSURES• The overburden pressure is given by:

– where:• ρb = bulk density of porous sediment,• ρm = density of rock matrix,• ρf = density of fluid in pore space, and• Ø = porosity.

• Since the matrix material, porosity and fluid content vary with depth, the bulk density also varies with depth.

• The overburden pressure at any point is therefore the integral of the bulk density from surface down to the point of interest.

• The specific gravity of the rock matrix may vary from 2.1 (sandstone) to 2.4 (limestone). COMMITMENT TO ACADEMIC AND


OVERBURDEN PRESSURES• Therefore, using an average of 2.3 and

converting to units of psi/ft, it can be seen that the overburden pressure gradient exerted by a typical rock, with zero porosity would be:

• This figure is normally rounded up to 1 psi/ft and is commonly quoted as the maximum possible overburden pressure gradient, from which the maximum overburden pressure, at any depth, can be calculated.

• It is unlikely that the pore pressure could exceed the overburden pressure.

• The overburden pressure may vary with depth, due to compaction and changing lithology and so the gradient cannot be assumed to be constant.


ABNORMAL PRESSURES• Pore pressures which are found to lie above or below the “normal” pore pressure gradient line are called abnormal pore pressures.

• These formation pressures may be either subnormal (i.e. less than 0.465 psi/ft) or overpressured (i.e. greater than 0.465 psi/ft).

• The mechanisms which generate these abnormal pore pressures can be quite complex and vary from region to region.

• In order for abnormal pressures to exist the pressure in the pores of a rock must be sealed in place i.e. the pores are not interconnecting.

• The seal prevents equalization of the pressures which occur within the geological sequence.


ABNORMAL PRESSURES


Overpressured Formation

Underpressured (Subnormally pressured) Formation

ABNORMAL PRESSURES• The seal is formed by a permeability barrier resulting from physical or chemical action.

• A physical seal may be formed by gravity faulting during deposition or the deposition of a fine grained material.

• The chemical seal may be due to calcium carbonate being deposited, thus restricting permeability.

• Another example might be chemical diagenesis during compaction of organic material.

• Both physical and chemical action may occur simultaneously to form a seal (e.g. gypsum-evaporite action).COMMITMENT TO ACADEMIC AND


ORIGIN OF SUBNORMAL PRESSURES• (a) Thermal Expansion

– As sediments and pore fluids are buried the temperature rises.

– If the fluid is allowed to expand the density will decrease, and the pressure will reduce.

• (b) Formation Foreshortening– During a compression process there is some bending of strata.

– The upper beds can bend upwards, while the lower beds can bend downwards.

– The intermediate beds must expand to fill the void and so create a subnormally pressured zone.

– This is thought to apply to some subnormal zones in Indonesia and the US.

– Notice that this may also cause overpressures in the top and bottom beds.COMMITMENT TO ACADEMIC AND


ORIGIN OF SUBNORMAL PRESSURES• (c) Depletion

– When hydrocarbons or water are produced from a competent formation in which no subsidence occurs a subnormally pressured zone may result.

– This will be important when drilling development wells through a reservoir which has already been producing for some time.

– Some pressure gradients in Texas aquifers have been as low as 0.36 psi/ft.

• (d) Precipitation– In arid areas (e.g. Middle East) the water table may be located hundreds of feet below surface, thereby reducing the hydrostatic pressures.


ORIGIN OF SUBNORMAL PRESSURES• (e) Potentiometric Surface

– This mechanism refers to the structural relief of a formation and can result in both subnormal and overpressured zones.

– The potentiometric surface is defined by the height to which confined water will rise in wells drilled into the same aquifer.

– The potentiometric surface can therefore be thousands of feet above or below ground level.


The effect of the potentiometric surface in relationship to the groundsurface causing overpressures and subnormal pressures

ORIGIN OF SUBNORMAL PRESSURES• (f) Epeirogenic Movements

– A change in elevation can cause abnormal pressures in formations open to the surface laterally, but otherwise sealed.

– If the outcrop is raised this will cause overpressures, if lowered it will cause subnormal pressures.


Section through a sedimentary basin showing two potentiometricsurfaces relating to the two reservoirs A and B

ORIGIN OF OVERPRESSURED FORMATIONS

• These are formations whose pore pressure is greater than that corresponding to the normal gradient of 0.465 psi/ft.

• As shown in on the right these pressures can be plotted between the hydrostatic gradient and the overburden gradient (1 psi/ft).

• The following examples of overpressures have been reported:– Gulf Coast: 0.8 - 0.9 psi/ft

– Iran: 0.71 - 0.98 psi/ft– North Sea: 0.5 - 0.9 psi/ft

– Carpathian Basin: 0.8 - 1.1 psi/ft



• There are numerous mechanisms which cause such pressures to develop.

• Some, such as potentiometric surface and formation foreshortening have already been mentioned under subnormal pressures since both effects can occur as a result of these mechanisms.

• The other major mechanisms are summarized below:

• (a) Incomplete Sediment Compaction– Incomplete sediment compaction or undercompaction is the most common mechanism causing overpressures.

– In the rapid burial of low permeability clays or shales there is little time for fluids to escape.



• (a) Incomplete Sediment Compaction (contd.)– Under normal conditions the initial high porosity (+/- 50 %) is decreased as the water is expelled through permeable sand structures or by slow percolation through the clay/shale itself.

– If however the burial is rapid and the sand is enclosed by impermeable barriers, there is no time for this process to take place and the trapped fluid will help to support the overburden.


Barriers to flow and generation of overpressured sand

ORIGIN OF OVERPRESSURED FORMATIONS• (b) Faulting

– Faults may redistribute sediments, and place permeable zones opposite impermeable zones, thus creating barriers to fluid movement.

– This may prevent water being expelled from a shale, which will cause high porosity and pressure within that shale under compaction.

• (c) Repressuring from Deeper Levels– This is caused by the migration of fluid from a high to a low presssure zone at shallower depth.

– This may be due to faulting or from a poor casing/cement job.

– The unexpectedly high pressure could cause a kick, since no lithology change would be apparent.

– High pressures can occur in shallow sands if they are charged by gas from lower formations.COMMITMENT TO ACADEMIC AND



• (d) Phase Changes during Compaction– Minerals may change phase under increasing pressure, e.g. gypsum converts to anhydrite plus free water.

– It has been estimated that a phase change in gypsum will result in the release of water.

– The volume of water released is approximately 40 % of the volume of the gypsum.

– If the water cannot escape then overpressures will be generated.

– Conversely, when anhydrite is hydrated at depth it will yield gypsum and result in a 40 % increase in rock volume.

– The transformation of montmorillonite to illite also releases large amounts of water.COMMITMENT TO ACADEMIC AND



• (e) Massive Rock Salt Deposition– Deposition of salt can occur over wide areas. Since salt is impermeable to fluids the underlying formations become overpressured.

– Abnormal pressures are frequently found in zones directly below a salt layer.

• (f) Salt Diaperism– This is the upwards movement of a low density salt dome due to buoyancy which disturbs the normal layering of sediments and produces pressure anomalies.

– The salt may also act as an impermeable seal to lateral dewatering of clays.



• (g) Tectonic Compression– The lateral compression of sediments may result either in uplifting weathered sediments or fracturing/faulting of stronger sediments.

– Thus formations normally compacted at depth can be raised to a higher level.

– If the original pressure is maintained the uplifted formation is now overpressured.

• (h) Generation of Hydrocarbons– Shales which are deposited with a large content of organic material will produce gas as the organic material degrades under compaction.

– If it is not allowed to escape the gas will cause overpressures to develop.


DRILLING PROBLEMS ASSOCIATED WITH ABNORMAL PRESSURES

• When drilling through a formation sufficient hydrostatic mud pressure must be maintained to:– Prevent the borehole collapsing, and– Prevent the influx of formation fluids.

• To meet these 2 requirements the mud pressure is kept slightly higher than formation pressure.

• This is known as overbalance. • However, if the overbalance is too great this

may lead to:– Reduced penetration rates (due to chip hold down effect).

– Breakdown of formation (exceeding the fracture gradient) and subsequent lost circulation (flow of mud into formation).

– Excessive differential pressure causing stuck pipe.



• The formation pressure will also influence the design of casing strings.

• If there is a zone of high pressure above a low pressure zone the same mud weight cannot be used to drill through both formations otherwise the lower zone may be fractured.

• The upper zone must be “cased off”, allowing the mud weight to be reduced for drilling the lower zone.

• A common problem is where the surface casing is set too high, so that when an overpressured zone is encountered and an influx is experienced, the influx cannot be circulated out with heavier mud without breaking down the upper zone.COMMITMENT TO ACADEMIC AND



• Each casing string should be set to the maximum depth allowed by the fracture gradient of the exposed formations.

• If this is not done an extra string of protective casing may be required.

• This will not only prove expensive, but will also reduce the wellbore diameter.

• This may have implications when the well is to be completed since the production tubing size may have to be restricted.

• Having considered some of these problems it should be clear that any abnormally pressured zone must be identified and the drilling programme designed to accommodate it. COMMITMENT TO ACADEMIC AND


TRANSITION ZONES• The pore pressure profile in a region where overpressures exist will look something like the P-Z diagram shown on the right.

• It can be seen that the pore pressures in the shallower formations are “normal”.

• There is then an increase in pressure with depth until the “overpressured” formation is entered.

• The zone between the normally pressured zone and the overpressured zone is known as the transition zone.


Transition from normal pressures to overpressures

TUTORIAL 1• The following pore pressure information has been

supplied for the well you are about to drill.

– (a) Plot the following pore pressure/depth information on a P-Z diagram. Calculate the pore pressure gradients in the formations from surface to 8000 ft; to 8500 ft and to 9500 ft. Plot the overburden gradient (1 psi/ft) on the above plot. Determine the mud weight required to drill the hole section: down to 8000 ft; down to 8500 ft and down to 9500 ft. Assume that 200 psi overbalance on the formation pore pressure is required.


Depth below Drillfloor (ft) Pressure (psi)0 01000 4656800 23258000 37208500 68009000 68509500 6900

TUTORIAL 1– (b) If the mud weight used to drill down to 8000 ft

were used to drill into the formation pressures at 8500 ft what would be the over/underbalance on the formation pore pressure at this depth?

– (c) Assuming that the correct mud weight is used for drilling at 8500 ft but that the fluid level in the annulus dropped to 500 ft below drillfloor, due to inadequate hole fill up during tripping, what would be the effect on bottom hole pressure at 8500 ft ?

– (d) What type of fluid is contained in the formations below 8500 ft?

• Note that 1 psi/ft = 19.22 ppg.


SOLUTION TO TUTORIAL 1


0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

Pore Pressure Profile Plots

Pressure (psi)

Dept

h (f

t)

1 psi/ft. Overburden Gradient

0.465 psi/ft. "Normal Pressure"

Gradient

(a)

Mud Weight designed for 8500 ft

Mud Weight designed for 9500 ft

Gas Gradient

SOLUTION TO TUTORIAL 1• (a) (contd.) The pore pressure gradients in the

formations from surface are:– 0 - 8000 ft: 3720 - 0/8000 - 0 = 0.465 psi/ft– 0 - 8500 ft: 6800 - 0/8500 - 0 = 0.800 psi/ft– 0 - 9500 ft: 6900 - 0/9500 - 0 = 0.726 psi/ft The required mud weights are as follows:– At 8000 ft:

• 3720 + 200 = 3920 psi• 3920/8000 = 0.49 psi/ft = 9.42 ppg

– At 8500 ft:• 6800 + 200 = 7000 psi• 7000/8500 = 0.82 psi/ft = 15.77 ppg

– At 9500 ft:• 6900 + 200 = 7100 psi• 7100/9500 = 0.75 psi/ft = 14.42 ppg


SOLUTION TO TUTORIAL 1• (b) If the mud weight of 9.42 ppg were used to

drill at 8500 ft the underbalance would be:– 6800 - (8500 x 9.42 x 0.052) = 2636 psi.– Hence the borehole pressure is 2636 psi less than the

formation pressure.• (c) If, when using 0.82 psi/ft (or 15.77 ppg) mud

for the section at 8500 ft, the fluid level in the hole dropped to 500 ft the bottom hole pressure would fall by:– 500 x 0.82 = 410 psi.– Hence the pressure in the borehole would be 210 psi

below the formation pressure.• (d) The density of the fluid in the formation

between 8500 and 9500 ft is:

– The fluid in the formations below 8500 ft is therefore gas.


PREDICTION AND DETECTION OF ABNORMAL PRESSURES

• The techniques which are used to predict (before drilling), detect (whilst drilling) and confirm (after drilling) overpressures are summarized:


Source of Data Parameters Time of Recording

Geophysical Methods

Formation Velocity (Seismic)

Prior to spudding Well

GravityMagnetics

Electrical ProspectingMethods

Drilling Mud

Gas Content

During Drilling

Flowline Mudweight KicksFlowline TemperatureChlorine VariationDrillpipe Pressure

Pit VolumeFlowrate Hole Fillup


• The techniques which are used to predict (before drilling), detect (whilst drilling) and confirm (after drilling) overpressures are summarized (contd.):



Drilling Parameters

Drilling Rate During Drilling.Delayed by the

Timerequired for Mud

Return

d and dc exponentsDrilling Rate Equations

TorqueDrag

Drilling Cuttings

Shale Cuttings

During Drilling.Delayed by the

Timerequired for Sample Return

Bulk DensityShale Factor

Electrical ResistivityVolume

Shape and SizeNovel Geochemical and Physical Techniques


• The techniques which are used to predict (before drilling), detect (whilst drilling) and confirm (after drilling) overpressures are summarized (contd.):



Well Logging

Electrical Survey

After Drilling

ResistivityConductivity

Shale Formation FactorSalinity VariationsInterval Transit Time

Bulk DensityHydrogen Index

Thermal Neutron Capture Cross Section

Downhole Gravity DataNuclear Magnetic Resonance

Direct Pressure Measuring Devices

Pressure Bombs During Well Testing or Completion

Drill Stem Test (DST)Wireline Formation Test

(WFT)

PREDICTION TECHNIQUES• The predictive techniques are based on

measurements that can be made at surface, such a geophysical measurements, or by analysing data from wells that have been drilled in nearby locations (offset wells).

• Geophysical measurements are generally used to identify geological conditions which might indicate the potential for overpressures such as salt domes which may have associated overpressured zones.

• Seismic data has been used successfully to identify transition zones and fluid content such as the presence of gas.

• Offset well histories may contain information on mud weights used, problems with stuck pipe, lost circulation or kicks.

• Any wireline logs or mudlogging information is also valuable when attempting to predict overpressures.


DETECTION TECHNIQUES• Detection techniques are used whilst drilling the well.

• They are basically used to detect an increase in pressure in the transition zone.

• They are based on three forms of data:– Drilling parameters - observing drilling parameters (e.g.ROP) and applying empirical equations to produce a term which is dependent on pore pressure.

– Drilling mud - monitoring the effect of an overpressured zone on the mud (e.g. in temperature, influx of oil or gas).

– Drilled cuttings - examining cuttings, trying to identify cuttings from the sealing zone.COMMITMENT TO ACADEMIC AND


CONFIRMATION TECHNIQUES• After the hole has been successfully drilled certain electric wireline logs and pressure surveys may be run to confirm the presence of overpressures.

• The logs which are particularly sensitive to undercompaction are the sonic, density and neutron logs.

• If an overpressured sand interval has been penetrated then the pressure in the sand can be measured directly with a repeat formation tester or by conducting a well test.


FRACTURE PRESSURE GRADIENT• When planning the well, both the formation pore pressure and the formation fracture pressure for all of the formations to be penetrated must be estimated.

• The well operations can then be designed such that the pressures in the borehole will always lie between the formation pore pressure and the fracture pressure.

• If the pressure in the borehole falls below the pore pressure then an influx of formation fluids into the wellbore may occur.

• If the pressure in the borehole exceeds the fracture pressure then the formations will fracture and losses of drilling fluid will occur.


FORMATION INTEGRITY TESTS• The pressure at which formations will fracture when exposed to borehole pressure is determined by conducting one of the following tests:– Leak-off Test.– Limit Test.– Formation Breakdown Test.

• The basic principle of these tests is to conduct a pressure test of the entire system in the wellbore and to determine the strength of the weakest part of this system on the assumption that this formation will be the weakest formation in the subsequent open hole.


• The wellbore is comprised of (from bottom to top): the exposed formations in the open hole section of the well (generally only 5-10 ft of formation is exposed when these tests are conducted); the casing (and connections); the wellhead; and the BOP stack.

• The procedure used to conduct these tests is basically the same in all cases.

• The test is conducted immediately after a casing has been set and cemented.

• The only difference between the tests is the point at which the test is stopped.


FORMATION INTEGRITY TESTS


The Configuration during Formation Integrity Tests


• The procedure is as follows:– Run and cement the casing string.– Run in the drillstring and drillbit for the next hole section and drill out of the casing shoe.

– Drill 5 - 10 ft of new formation below the casing shoe.

– Pull the drillbit back into the casing shoe (to avoid the possibility of becoming stuck in the openhole).

– Close the BOPs (generally the pipe ram) at surface.

– Apply pressure to the well by pumping a small amount of mud (generally 1/2 bbl) into the well at surface. Stop pumping and record the pressure in the well. Pump a second, equal amount of mud into the well and record the pressure at surface. Continue this operation, stopping after each increment in volume and recording the corresponding pressure at surface.



• The procedure is as follows (contd.):– Plot the volume of mud pumped and the corresponding pressure at each increment in volume.

– Note: the graph shown on the graph represents the pressure all along the wellbore at each increment. This shows that the pressure at the formation at leak off is the sum of the pressure at surface plus the hydrostatic pressure of the mud).

– When the test is complete, bleed off the pressure at surface, open the BOP rams and drill ahead.

• It is assumed in these tests that the weakest part of the wellbore is the formations which are exposed just below the casing shoe.

• When these tests are conducted, the pressure at surface, and throughout the wellbore, initially increases linearly with respect to pressure.



• At some pressure the exposed formations start to fracture and the pressure no longer increases linearly for each increment in the volume of mud pumped into the well (see point A in the Figure on the right).

• If the test is conducted until the formations fracture completely (see point B in the figure), the pressure at the surface will often drop dramatically, in a similar manner to that shown in the figure.



P-V Behaviour of a Rock during Formation Integrity Tests

• The “Leak-off test” is used to determine the pressure at which the rock in the open hole section of the well just starts to break down (or “leak off”).

• In this type of test the operation is terminated when the pressure no longer continues to increase linearly as the mud is pumped into the well.

• In practice the pressure and volume pumped is plotted in real time, as the fluid is pumped into the well.

• When it is seen that the pressure no longer increases linearly with an increase in volume pumped (Point C) it is assumed that the formation is starting to breakdown.


THE LEAK-OFF TEST

• When this happens a second, smaller amount of mud (generally 1/4 bbl) is pumped into the well just to check that the deviation from the line is not simply an error (Point D).

• If it is confirmed that the formation has started to “leak off” then the test is stopped and the calculations below are carried out.


P-V Behaviour during a Leak-off Test.

THE LEAK-OFF TEST

• The “Limit Test” is used to determine whether the rock in the open hole section of the well will withstand a specific, predetermined pressure.

• This pressure represents the maximum pressure that the formation will be exposed to whilst drilling the next wellbore section.

• The pressure to volume relationship during this test is shown in Figure 25.

• This test is effectively a limited version of the leak-off test.


P-V Behaviour during a Limit Test.

THE LIMIT TEST

• The “Formation Breakdown Test” is used to determine the pressure at which

• the rock in the open hole section of the well completely breaks down. If fluid is

• continued to be pumped into the well after leak off and breakdown occurs the pressure

• in the wellbore will behave as shown on the right.


P-V Behaviour during a Formation Breakdown Test.

THE FORMATION BREAKDOWN TEST

• In a Leak-Off test the formation below the casing shoe is considered to have started to fracture at Point A.

• The surface pressure at Point A is known as the leak off pressure and can be used to determine the maximum allowable pressure on the formation below the shoe.

• The maximum allowable pressure at the shoe can subsequently be used to calculate:– The maximum mud weight which can be used in the subsequent openhole section

– The Maximum Allowable Annular Surface Pressure (MAASP).


LEAK-OFF TEST CALCULATIONS

• The maximum allowable pressure on the formation just below the casing shoe is generally expressed as an equivalent mud gradient (EMG) so that it can be compared with the mud weight to be used in the subsequent hole section.

• Given the pressure at surface when leak off occurs just below the casing shoe, the maximum mud weight that can be used at that depth, and below, can be calculated from:

• Usually a safety factor of 0.5 ppg (0.026 psi/ft) is subtracted from the allowable mudweight.


LEAK-OFF TEST CALCULATIONS

TUTORIAL 2• While performing a leak off test the surface pressure at leak off was 940 psi. The casing shoe was at a true vertical depth of 5010 ft and a mud weight of 10.2 ppg was used to conduct the test. Calculate the Maximum bottom hole pressure during the leak-off test and the maximum allowable mud weight.


SOLUTION TO TUTORIAL 2• The Maximum Bottomhole Pressure during the leakoff test can be calculated from:– Hydrostatic Pressure of Mud Column + Leak-off Pressure at Surface

– = {(0.052)(10.2)(5010) + 940} psia– =3597 psia.

• The Maxximum Allowable Mud Weight at this Depth is therefore:– =3597 psi/5010 ft = 0.718 psi/ft = 13.8 ppg

• Allowing a Factor of Safety of 0.5 ppg, the Maximum Allowable Mud Weight is (13.8 – 0.5) ppg = 13.3 ppg.


FORMATION EVALUATION


FORMATION EVALUATION• Experience over the years has led to a fairly consistent evaluation philosophy for designing programs to estimate recoverable hydrocarbons.

• The usual objective is for the most economic array of measurements that will give estimates of satisfactory accuracy for thickness, porosity, permeability and water saturation of all zones of potential economic interest in the well.COMMITMENT TO ACADEMIC AND


• The choice of specific measurements depends on the particular problem and the accuracies required.

• The basic approach to setting up an evaluation program is to:

– Use wireline logs as the basic device where possible.

– Supplement the wireline logs with cutting samples and perhaps borehole fluid logs

– Use cores for calibration of logs and for needed geologic data.

– Add productivity tests as necessary for help in important borderline cases that cannot be satisfactory resolved.COMMITMENT TO ACADEMIC AND



• Borehole measurements are used for the:

– Determination of recoverable hydrocarbon volumes

– Location of reservoir fluid contacts– Development of reservoir quality maps– Determination of water salinities– Projection of bottomhole fluid pressures while drilling

– Monitoring of reservoir fluid movement– Checking of feasibility of waterfloods and other enhanced oil recovery mechanisms



S/N Borehole Measurement

Results

1 Cutting Samples

Lithology, oil and gas shows, rock type

2 Mud Logging Measurement of hydrocarbon components within the drilling mud

3 Acoustic Devices

Transit time, amplitude, cement bond logs, wave form displays, variable intensity, shear wave velocity, borehole televiewer

4 Radioactivity Devices

Natural gamma ray emission, neutron density, chlorine, nuclear magnetism, neutron lifetime, spectral logging




Results

5 Spontaneous Potential (SP) Device

Self-potential, water resistivity, shale content

6 Resistivity Devices

Electrical resistivity, focused resistivity, induction, conductivity, resistivity and conductivity of flushed and uninvaded zones

7 Production Logging

Measurement of pressure in the borehole, fluid flow rates, reservoir fluid composition, borehole temperature




Results

8 Dip Meter Devices Dip angle and direction of formations penetrated by the borehole

9 Coring Lithology, porosity, permeability, grain density, formation factor, saturation exponent and other basic rock parameters



MECHANICS OF DRILLING A HOLE


PREPARING THE DRILL SITE• The drill site must be prepared to accommodate the rig and equipment.

• At the exact spot on the surface where the well will be, the crew digs a rectangular pit called a cellar or drives a culvert-like pipe into the ground.

• In the middle of the cellar, the crew starts the top of the well.

• The conductor hole is large in diameter (as large as 36 inches or more) and about 20 to 100 feet (6 to 30 metres).

• The conductor hole is lined with pipe called conductor pipe or conductor casing.


A Cellar

PREPARING THE DRILL SITE


• Usually, the crew also digs another hole smaller in diameter than the conductor hole next to the cellar.

• Called the rathole, it is used to store the kelly when it is temporarily out of the main hole during certain operations.

• On small rigs, the crew digs a third hole called the mousehole.

• It is used to hold a joint of pipe ready for makeup.

PREPARING THE DRILL SITE


RIGGING UP• Rigging up begins with centering the substructure over the conductor pipe in the cellar.

• If the rig uses a mast, the crew places the mast into the substructure in a horizontal position and hoists it upright.

• If the rig uses a derrick, the crew assembles it piece by piece on the substructure.


RIGGING UP• Other rigging-up operations include erecting stairways; handrails and guardrails; installing auxiliary equipment to supply electricity, compressed air and water; and setting up storage facilities and living quarters for the tool pusher and company representative.

• Finally, the contractor must bring drill pipe, drill collars, bits, mud supplies and many other pieces of equipment and supplies to the site before the rig can make hole.


DRILLING SURFACE HOLE• To begin drilling, the crew attaches a large bit, say 171/2 inches in diameter to the first drill collar

• It lowers the bit into the conductor pipe by adding drill collars and drill pipe one joint at a time until the bit reaches the bottom

• With the kelly attached to the top joint of pipe, the driller begins making hole by:– Starting the pump to circulate mud,– Engaging the rotary table or top drive to rotate the drill stem, and

– Setting the drill stem down with the drawworks to apply weight on the bit


• As the bit drills ahead, the kelly moves downward through the kelly bushing

• At some time, the entire length of the kelly reaches a point just above the bushingTo drill the hole deeper, the crew adds more pipe to the string to make it longer

• To add pipe, the driller uses the hoisting system to pick up the kelly and attached drill string off bottom.

• When the tool joint of the topmost joint of pipe clears the rotary, the crew sets the slips around the pipe and into the opening in the master bushing

DRILLING SURFACE HOLE


Crewmen grasp the slips by the handles as they set them in the master bushing



• The slips grip the pipe and keep it from falling back into the hole while the crew unscrews the kelly from the drill string (breaks out).

• To break out the kelly requires two sets of tongs. The rotary helpers latch one set (breakout tongs) around the bottom of the kelly.

• The helpers latch the other set (backup tongs) around the tool joint of the drill pipe. The crew removes the tongs and the driller spins the drill pipe out of the kelly by turning the rotary table and move the kelly over to a 30-foot joint of drill pipe resting in the mousehole.



• The crew then stab the pin of the kelly into the box of the new joint and screw them together, or make them up.

• The driller picks them up and moves them from the mousehole to the rotary table.

• The crew stabs the bottom of the new joint of pipe into the top of the joint of pipe coming out of the borehole and again make up the joints.

• With the new joint made up, they pull the slips and the driller lowers the pipe until the bit nears the bottom.



• The driller starts the pumps, begins rotation, applies weight to the bit and drills another 40 feet or so of hole, depending on the length of the kelly

• At a depth that could range from hundreds of feet to a few thousand feet, drilling comes to a temporary halt

• The crew pulls the drill stem from the hole for surface casing to be run and cemented in place.

• Cementing is the process of placing cement between the casing and borehole in a well immediately after the casing is run.



• The main objectives of cementing are:

• to seal the annulus.• to obtain zonal isolation.• to support axial load of casing strings and tubing strings to be run later.

• to bond the casing to the formation.• to protect the wellbore in the event of problems.

• to seal off troublesome zones.• to protect casing from corrosive fluids in the formations.

• Zonal isolation is accomplished if cement in the annulus prevents the flow of formation fluids from the well into the wellbore.



DRILLING INTERMEDIATE HOLE• To resume drilling, the crew begins tripping the drill stem and a new, smaller bit that fits inside the surface casing back into the hole.

• When the bit reaches bottom, the driller resumes circulation resumes circulation and rotation.

• The bit drills through the small amount of cement left in the casing, the plugs and the guide shoe and into the new formation below the cemented casing.

• As drilling progresses and hole depth increases, formation tends to get harder.

• As a result, the crew will need to make several round trips (trips in and out of hole) to replace worn bits.COMMITMENT TO ACADEMIC AND


• At a predetermined depth, drilling stops again in order to set another string of casing.Depending upon the depth of the hydrocarbon reservoir, this string of casing may be the final or the intermediate one.

• In general, wells in relatively shallow reservoirs, say 10,000 ft (3,048 m) or less, only require one more casing string.

• Wells where the reservoir is deep, perhaps up to 20,000 ft (6,096 m) or more, usually need at least one intermediate casing string. The crew runs and cements it in much the same way as surface casing.

DRILLING INTERMEDIATE HOLE


DRILLING TO FINAL DEPTH• Using a still smaller bit that fits inside the intermediate casing, the crew drills the next part of the hole. The crew trips in the bit and drill stem, drill out the intermediate string shoe and resume drilling.

• The crew drills with the pay zone in mind, a formation capable of producing enough oil gas or oil to make it profitable for the operating company to complete the well.

• After the operator has evaluated the formations, the company decides whether to set the final string of casing, the production casing or to plug and abandon the well.


• If the evaluation reveals that commercial amounts of hydrocarbons exist:

– Casing will be hauled in.– The drilling crew will pull the drill stem from the well and lay it down one joint at a time so that they can easily be transported to the rig’s next drilling location.

– A cementing company will run and cement the production casing in the well.

• The drilling contractor’s job is nearly finished after drilling the hole to total depth and setting and cementing production casing.

• Sometimes, the rig and crew remain on the location and complete the well.

DRILLING TO FINAL DEPTH


• In other cases, the drilling contractor moves the rig and equipment to the next location after cementing the production casing.

• In such cases, the operator hires a special completion rig and crew to finish the job.

• Completion involves:– Running tubing (a string of small-diameter pipe inside the casing through which the hydrocarbons flow out of the well)

– Setting the wellhead (steel fittings that support the tubing and a series of valves and pressure gauges to control oil flow.

DRILLING TO FINAL DEPTH


DRILLING PROBLEMS


DRILLING PROBLEMS• Major Drilling Problems are:

– Shallow Gas.– Stuck Pipe.– Loss of Equipment.– Loss of Hole.– Formation Fracture.– Kicks.– Blowouts


• Shallow gas is usually defined as pockets of gas found less than 1000 m or 3000 ft in depth.

• It is usually at high pressure but will be slightly overpressured due to its relative buoyancy compared with other fluids.

• Shallow gas is usually biogenic in origin and consists predominantly of methane. It is derived from recently buried organic material

• It is possible for gas generated non-biogenically from depth to be transmitted up through a conduit such as a fault or an old wellbore. Transmitted gas is potentially more dangerous as it may be at a higher pressure.

SHALLOW GAS


• The gas accumulates in poorly consolidated but relatively high porosity and permeability sands.

• Once one of these beds is penetrated by the bit, the gas may flow only if there is a negative pressure or it is swabbed (sucked) into the hole.

• Once the gas starts to flow into the borehole it is almost impossible to stop.

• The formation at this depth is usually not strong enough to handle any sort of imposed pressure even if casing has been set.

SHALLOW GAS


• Offshore, these zones are drilled with returns to the seabed and the gas rises, expands and flows into the sea.

• In whatever location the gas obviously poses a serious fire risk and offshore large amounts of gas entrained in the sea reduces the buoyancy effect and boats and rigs can sink.

• Large volumes of escaping gas can erode large holes so that the legs of a jack-up may become unstable.

SHALLOW GAS


BLOWOUTS AND FIRES• In blowouts, you see oil gushing (a blowout), and perhaps even a fire, when drillers reach the final depth.

• These are actually dangerous conditions, and are (hopefully) prevented by the blowout preventers and the pressure of the drilling mud.

• In most wells, the oil flow must be started by acidizing or fracturing the well


• Also called well decomissioning.

• Decommissioning of offshore installations came to international prominence as a result of Shell's proposals to dispose of the Brent Spar oil storage tank by dumping it in deep water beyond the edge of the Continental Shelf.

WELL ABANDONMENT


DRILLING CONTRACTS


• Drilling contracts generally fall under four main categories:

– Daily Rate Contracts.– Modified Daily Rate (Footage Bonus) Contracts.

– Footage Contracts.– Turnkey Contracts.

DRILLING CONTRACTS


• Daily Rate Contracts: – This is the most common type of contract used worldwide.

– The drilling contractor is paid by the operator for each day that he spends on the well.

– The contractor can be penalized for negligence.

– Day rates are usually broken down into four groups:• Operating.• Reduced.• Special. • Zero.

DRILLING CONTRACTS


• Operating Rate: o Operating rate is applied to rig utilisation. o This means that the contractor’s equipment and personnel are fully utilised.

o This rate covers activities such as drilling, tripping and casing runs.

• Reduced Rate:o Reduced rate used when the contractor’s equipment and personnel are not being fully utilised.

o Other operations can fall in this category such as rig mobilisation.

o This rate is usually a few per cent cheaper than the operating rate.

DRILLING CONTRACTS


• Special Rate: o Special rate applied in many circumstances.

o o An example are the allowances given in specific month due to the repairs in downtime period.

• Reduced Rate:o No payment is given to the drilling contractor.

o The main reason behind that is negligence by the contractor which causing operational delays.

DRILLING CONTRACTS


• Modified Daily Rate (Footage Bonus) Contracts: – The purpose of this is to encourage the drilling contractor to reach TD more quickly than the daily rate contract.

– There will be a bonus for the contractor if he reaches a certain depth within an agreed time scale.

– This type of contract can be attractive to both the operator and drilling contractor but is not applied very often in practice.

DRILLING CONTRACTS


• Footage Contracts: – These are given in reasonably well-known areas. – A specified rate per foot drilled is negotiated for a well of a certain depth.

– With this contract style the drilling contractor has a direct incentive to drill the well faster.

– When offering a drilling contractor a footage contract the operator should clearly list any special terms that contractor must to comply for the specific well.

– An example would be the an agreement of a maximum tripping speed to prevent pressure surges.

DRILLING CONTRACTS


• Turnkey Contracts: – With this kind of contract the operator pays the drilling contractor a lump sum to drill a well of a certain depth in a given area.

– It is up to the drilling contractor to comply with the well head and casing requirements, organise the third party services and generally fulfil all the normal operator’s roles on the well.

– It is probable that the operator will insist on rights of inspection at any time on the well.

DRILLING CONTRACTS


• Turnkey Contracts:

– Since in most areas of the world the operator can never give away the responsibility for oil spills in his license block, then turnkey drilling has had a limited impact on the market.

– Notable exception, to this are USA and China where local legislation makes turnkey drilling attractive.

DRILLING CONTRACTS


• The cost of the rig contract represents 30-40 per cent of the overall well costs.

• • To ensure that the operator’s interests are best protected, the drilling contract is set up by the operator.

• Drilling contractors submit their bids for the work, based on the issued contract.

• Upon signing by both partners, the contract then forms the basis of the working relationship between operator and drilling contractor.

CONTRACT FORMAT AND MANAGEMENT


• Both partners are bound by the contract, therefore it is vital that the design of the contract is such that there are no loopholes or deficiencies.

• Note that the operator writes the contract, so if he has cause to criticize the contract during its execution then he only has himself to blame.

• The contract must cover all aspects of the operator/contractor relationship. In a well-written contract there are no ‘grey areas’, everything should be in ‘black and white’. Contract formats vary from area to area to suit local conditions.

CONTRACT FORMAT AND MANAGEMENT


– Agreement– Supplies– Manner of Compensation

– Liabilities– Insurance– Confidentiality– Assignment of Contract

– Arbitration

– Personnel, Equipment and Services

– Compensation– Quality Control of Performance

– Drilling Methods and Practices

– Special Conditions– Patents– Laws, Rules and Regulations

– Signatures

CONTRACT FORMAT AND MANAGEMENT• However, certain clauses are common to all drilling contracts.

• Examples of these clauses are:


CONTRACT FORMAT AND MANAGEMENT• The following clauses are common to all Contracts:

• Agreement:o The Agreement should describe the objective of the Contract.

o It should clearly state when the contract will begin, its duration and termination date.



• Personnel, equipment, services and supplies:o This clause lays down what the contractor is expected to supply.

o Most contractors refer to Appendices which are included with the contract, where a list of equipment or personnel is offered by the contractor and included in the Tender Document.



• Personnel, equipment, services and supplies:o The Operator should clearly state what personnel and equipment will provide.

o A format should cover any additional equipment which might be required.

o This format allowing the Contractor to add on a charge if purchases additional equipment to fulfil the purposes of the Contract.



• Compensation:o This details how much money the contractor will receive for the services.

o All aspects of the operation must be covered in this Section and it is better to apply too much rather than too little detail to describe the grouping into which services will come. COMMITMENT TO ACADEMIC AND


• Mobilisation Charges

• Operating• Inspection• Negligence• Demobilisation Charges

• Rates• Repair• Maintenance• Force Majeure• Taxes

CONTRACT FORMAT AND MANAGEMENT• Compensation:

o A typical breakdown of the groups would be:

• If the rates are adjustable then any adjustments should be explained.



• Manner of Compensation:o This clause explains how invoicing must take place.

o The clause should also state when the payment will be made.



• Quality Control of Performance:o The Operator reserves the right to insist that the Contractor’s equipment and personnel should fulfil the commitment made in the Tender Document.

o In practice,this means providing access to the hardware and to records.

o For a semi-submersible rig, structural surveys, inclining test records and certificates and planned maintenance records would have to be available for inspection. COMMITMENT TO ACADEMIC AND INDUSTRIAL EXCELLENCE 414


• Quality Control of Performance:o Usually, a rig audit team will visit the rig prior to awarding the Contract to inspect all of the above.

o Most operators will include in this Section an opportunity for the operator to take over the operation and Contractor’s personnel for reasons which will be defined.COMMITMENT TO ACADEMIC AND



• Quality Control of Performance:o The Operator will normally reserve the right to insist that the Drilling Contractor removes undesirable crew members.

o The method by which the operator wishes to effect this must be clearly defined.



• Liabilities:o This section defines the operator’s and the contractor’s liabilities.

o The bulk of this Section will represent the Contractor holding the Operator harmless in respect of damage to his equipment and vice versa.

o There must be details of how the Operator's equipment must be serviced under the Contract by the Contractor.



• Liabilities:o To cover the cost of any Contractor’s equipment lost downhole, the Contract will define the formula by which the present value of the equipment is determined.

o Generally speaking, the Contractor’s liabilities tend to be limited in most cases, whilst those of the Operator are considerable.

o An average pollution liability would be limited to $100,000 for the Contractor, whilst the Operator’s liability to the licensing authority or government would be unlimited.



• Drilling Methods and Practices:o This defines the safe working practices that are expected from the Contractor.

o Details such as special BOP testing, tripping, mud monitoring and reporting are clearly defined.

• Insurance:o This establishes the level of insurance cover that the Operator and Contractor will have to carry.

COMMITMENT TO ACADEMIC AND



• Special Conditions:o Any possible unexpected circumstances should be clearly defined in this Section.

o The actions and responsibilities must be made clear in each case.

o Force majeure will come under this section and will cover all eventualities which are beyond the control of the Operator or Contractor.

COMMITMENT TO ACADEMIC AND



• Confidentiality:o The Contract must clearly lay down what the Contractor may disclose about the well it is drilling.

• Patents:o This Section indemnifies each party from patent infringement by the other party for the duration of the Contract.



• Assignment of Contract:

o This Section can give the Operator the right to assign the Contract to another Operator (farm out agreement) or can prevent this from happening.



• Assignment of Contract:o This defines under which government laws the Contract will operate.

o Usually, this will be the area where the drilling is taking place.

o However, in frontier areas, another country’s laws might be used.

o Typically, this would be the home country of the operator, for example, NAOC - Italy, SPDC – Holland and MPNU – United States.COMMITMENT TO ACADEMIC AND



• Arbitration:o In the event of dispute of the Contract, the arbitration process should be clearly defined in this Section.

• Signatures:o This Section has space for Signatures and Witnesses for the Operator and Contractor.

o Note that each page of the Contract should be initialled by both parties as well as any changes to the Contract.


DRILLING COST ANALYSIS


DRILLING COST ANALYSIS• The main function of the drilling engineer is to recommend drilling procedures that will result in the successful completion of the well as safely and economically as possible.

• The drilling engineer must make recommendations concerning routine rig operations such as:• drilling fluid treatment,• pump operation.• bit selection, and• any problems encountered in the drilling operation.


DRILLING COST ANALYSIS• In many cases, the use of a drilling cost equation can be useful in making these recommendations.

• The usual procedure is to break the drilling costs into:• variable drilling costs,• fixed operating expenses that are independent of alternatives being evaluated.


DRILLING COST FORMULA• The most common application of a drilling cost formula is in evaluating the efficiency of a bit run.

• A large fraction of the time required to complete a well is spent either drilling or making a trip to replace the bit.

• The total time required to drill a given depth, ∆D, can be expressed as the sum of: • the total rotating time during the bit run, tb,

• the nonrotating time during the bit run, tc, and

• the trip time, tt


• The drilling cost formula is given by:

• where:• Cf = drilled cost per unit length,• Cb = cost of bit,• Cr = the fixed operating cost of the rig

per unit time independent of the alternatives being evaluated,

• tb = the total rotating time during the bit run,

• tc = the nonrotating time during the bit run,

• tt = the trip time, and• ∆D = a given depth interval.

DRILLING COST FORMULA


• Since this drilling cost function ignores risk factors, the results of the cost analysis sometimes must be tempered with engineering judgement.

• Reducing the cost of a bit run will not necessarily result in lower well costs if the risk of encountering drilling problems such as stuck pipe, hole deviation, hole washout, etc., is increased greatly.

DRILLING COST FORMULA


TUTORIAL 1• A recommended bit program is being prepared

for a new well using bit performance records from nearby wells. Drilling performance records for bits are shown for a thick limestone formation at 9,000 ft. Determine which bit gives the lowest drilling cost if the operating cost of the rig is $400/hr, the trip time is 7 hours and connection time is 1 minute per connection. Assume that each of the bits was operated at near the minimum cost per foot attainable for that bit.Bit

Bit Cost ($)

Rotating Time

(Hours)

Connection Time

(Hours)

Mean Penetration Rate (ft/hr)

A 800 14.8 0.1 13.8B 4,900 57.7 0.4 12.6C 4,500 95.8 0.5 10.2


SOLUTION TO TUTORIAL 1• The cost per foot drilled for each bit type can be computed using the Drilling Cost Equation.

• For Bit A, the cost per foot is:

• Similarly, for Bit B, the cost per foot is:

• Finally, for Bit C, we have:

• The lowest drilling cost was obtained using Bit B.


• The following bit records are taken from the offset wells used in the design of the well shown on the next slide. Assuming: that the geological conditions in this well are the same as those in the offset wells below; that the 121/4” section will be drilled from around 7000 ft; an average trip time of 8 hrs and a rig rate of £400/hr. Select the best bit type to drill the 121/4" hole section.Well

Bit Cost (₤)

Depth In (ft)

Depth Out (ft)

Time on Bottom (Hrs.)

1 A 350 7100 7306 14.92 B 1600 7250 7982 58.13 C 1600 7000 7983 96.3

TUTORIAL 2


TUTORIAL 2


• The process of selection of the best bit type from a number of offset wells requires a number of assumptions:– a. The lithology encountered in the offset bit runs must be similar to that lithology expected in the proposed well.

– b. The depth of the offset bit runs are similar to that in the proposed well.

– c. The bit runs in the offset wells were run under optimum operating conditions (hydraulics, WOB, RPM etc.).

• On the strength of the above assumptions, the ‘best bit’ will be selected on the basis of footage drilled, ROP and most importantly Cost per Foot of bit run.

• The results of these numerical criteria are shown on the next slide. The ‘best’ bit is considered to be bit B since this bit had the most economical bit run (£/ft).



• Solution (contd.):– It is worth noting that bit A would have been selected on the basis of ROP and bit C would have been selected on the basis of footage drilled.

Bit Bit Cost (₤)

Footage Drilled (ft.)


ROP (ft/Hr.)

Cost/ft (₤/ft)

A 350 206 14.90 13.83 46.17B 1600 732 58.10 12.60 38.31C 1600 983 96.30 10.21 44.07

Rig Rate (₤/ft) 400Trip Time (Hours)

8



• A recommended bit programme is being prepared for a new well using bit performance records from nearby wells. Drilling records for three (3) bits are shown below for a thick shale section encountered at 12,000 ft. Determine which bit gives the lowest drilling cost if the hourly operating cost of the rig is $1,000/hr and the trip time is 10 hours. The connection times are included in the rotating times given below.

• Answer: Bit B ($183.13/ft).

Bit Bit Cost ($)

Interval Drilled (ft)

Rotating Time (Hours)

A 700 106 9B 4,000 415 62C 8,000 912 153

TUTORIAL 3


• The following bit records were obtained on a well drilled in Maverick County, Texas, U. S. Compare the performance of Bits 2 and 3. Assume a daily operating cost of $24,000/day, a bit cost of $3,000 for Bit 2 and a bit cost of $12,000 for Bit 3.

• Answer: $565/ft and $679/ft.

Bit Depth Out(ft)

Time (Hours)

Bit Size(Inches)

1 7,988 26.8 12.02 8,060 25.8 12.03 8,494 270.0 12.04 8,614 35.1 12.0

TUTORIAL 4


• During the drilling of the 121/4" hole section of a new well the following drilling data is being recorded and provided to the Company Man. At what point in time would you have suggested that the bit be pulled and why? Assume an average trip time of 8 hours and a rig rate of £400/hr. Also assume that the bit type selected IN Tutorial 2had been run in hole.


Footage Drilled (Feet)



1 34 7 1802 62 8 2103 86 9 2164 110 10 2265 126 11 2346 154 12 240

TUTORIAL 5


Drilling Time(Hrs.)


Total Cost of Run (₤)

Cost per Foot (₤/ft)

1 34 5200 152.942 62 5600 90.323 86 6000 69.774 110 6400 58.185 126 6800 53.976 154 7200 46.757 180 7600 42.228 210 8000 38.109 216 8400 38.8910 226 8800 38.9411 234 9200 39.3212 240 9600 40.00

Rig Rate (₤/Hr.)

400

Bit Cost (₤) 1600Trip Time (Hrs.)

8



• The decision to pull a bit should be based on the performance of the bit over a period of time.

• The Table on the previous slide and the Figure on the right show that after 8 hours the cost per foot of the bit run had reached its minima and started to increase.

Bit Run Evaluation

It should be noted that only ‘consideration’ is given to pulling the bit at this point. The engineer should first check with the mud loggers that the bit had not entered a new type of formation, since this may affect the performance of the bit.



0 2 4 6 8 10 12 140

20406080

100120140160

Bit Run Cost

Time (Hours)

Cost

per

Foo

t (₤

/ft)

• The engineer should also consider the proximity to the next casing or logging point and the consequent cost of running a new bit to drill what may be a relatively short section of hole.

• This must be weighed against the possibility of the bit breaking up and losing teeth or even a cone.

• Note that:



INTRODUCTION TO DIRECTIONAL DRILLING


INTRODUCTION• At one time, it was assumed all oil wells were essentially vertical or the bottom of the hole was directly under the drilling rig.

• Unfortunately, this is not true. • The petroleum industry did not become fully aware of deviated well problems until the development of the Seminole Field, Oklahoma, United States.

• The wells in this field were drilled very close together.

• As a result of the deviation tendencies, wells were drilled into other drilling wells and wells which were already producing.


• Also, wells were encountering the producing formation at different measured depths.

• The true vertical depths were similar, but measured depths varied significantly.

• In the late 1920's, survey instruments were developed that could measure both inclination and azimuth.

• Deviations as high as 46º from the vertical were measured in the Seminole Field wells.

• The average deviation from the vertical was approximately 13°.

• The first controlled directional well was drilled in California in 1930 to tap offshore oil reserves.

INTRODUCTION


• Unfortunately, there was a dispute as to who owned the oil offshore.

• Operators were drilling across lease lines in order to drain oil owned by someone else, resulting in legal problems.

• In the 1930's, wells were directionally drilled to tap oil reserves that would otherwise be inaccessible.

• Directional drilling was employed to produce oil from under a cemetery.

• Oil was produced from under the ocean by placing the rig on the shore and directionally drilling into the offshore oil deposits.

• Little attention was paid to directional drilling until a relief well was drilled to kill a blowout near Conroe, Texas.

INTRODUCTION


• In that instance, a blowout had occurred while drilling; and as a result, a 170 foot diameter crater was created around the well.

• The drilling rig sank and was lost. Approximately 6,000 barrels of oil per day were flowing from the crater.

• A relief well was drilled near the surface location of the blowout.

• Directional drilling techniques were used to intersect the producing formation near the blowout and the blowout was killed by pumping fluid down the relief well and into the blowout well.

• Since then, directional drilling has been widely accepted.

INTRODUCTION


• Today, the on-going research and development of new tools and techniques are making directional drilling more accurate and economical.

• Controlled directional drilling is defined by the API as: The art and science involving the intentional deflection of a wellbore in a specific direction in order to reach a predetermined objective below the surface of the earth.

• Today, it is much more science than art.

INTRODUCTION


• Sidetracking is one of the primary uses for directional drilling.

• Sidetracking is an operation which deflects the borehole by starting a new hole at any point above the bottom of the old hole.

• The primary reason for sidetracking is to bypass a fish which has been lost in the hole; however, there are several other reasons for sidetracking.

USES OF DIRECTIONAL DRILLING


• A sidetrack can be performed in an old well to move the location of the bottom of the hole from a depleted portion of the reservoir to a portion that is productive, such as, across a fault or permeability barrier.

• Sidetracking an exploration well can lead to a better geologic understanding of an area especially where the geology is complicated.



• Straight hole drilling is a special case of directional drilling where an attempt is made to keep the hole vertical.

• Some reasons for wanting to keep the hole vertical are: • To keep from crossing

lease lines; • To stay within the

specifications of a drilling contract;

• To stay within the well spacing requirements in a developed field.



• Controlled directional drilling is used when drilling multiple wells from an artificial structure such as offshore platforms, drilling pads, or man made islands.

• The economics of building one offshore platform for each well would be prohibitive in most cases.



• There are special cases when multiple sands are drilled with a single wellbore.

• Where steeply dipping sand zones are sealed by an unconformity, fault or salt dome overhang, a number of vertical wells would be required to produce each sand, which are separated by a permeability barrier.



• There are times when oil deposits lie under inaccessible locations such as towns, rivers, shorelines, mountains or even production facilities.

• When a location cannot be constructed directly above the producing formation, the wellbore can be horizontally displaced by directional drilling.



• Directional drilling is also applicable in fault drilling.

• In fault drilling, often, the bit will deflect when passing through the fault plane, and sometimes the bit will follow the fault plane.

• To avoid the problem, the well can be drilled on the upthrown or downthrown side of the fault and deflected into the producing formation.



• Many oil fields are associated with the intrusion of salt domes.

• Directional drilling has been used to tap some of the oil which has been trapped by the intrusion of the salt.

• Instead of drilling through the salt overhangs, the wells can be directionally drilled adjacent to the salt dome and into the underlying traps as shown in the figure.



• A highly specialized application for directional drilling is the relief well.

• If a well blows out and is no longer accessible from the surface, then a relief well is drilled to intersect the uncontrolled well near the bottom.

• Water or mud are then pumped through the relief well and into the uncontrolled well.



• Horizontal drilling is another special application of directional drilling and is used to increase the productivity of various formations.

• One of the first applications for horizontal drilling was in vertically fractured reservoirs.

• Horizontal drilling is also used to produce thin oil zones with water or gas coning problems.



• Directional drilling can also be used to drill multilateral wells.

• Multilaterals are additional wells drilled from a parent wellbore as illustrated in the figure.

• Multilaterals can be as simple as an open hole sidetrack or it can be more complicated with a junction that is cased and has pressure isolation and reentry capabilities.



• There are four basic types of directional wells.

• Most wells can be categorized by one of the four basic types or a combination thereof.

• The types of Directional Wells are: • Type 1 Directional Well.• Type 2 Directional Well.• Type 3 Directional Well.• Type 4 Directional Well.

TYPES OF DIRECTIONAL WELLS


• A Type I well is often called a build and hold.

• The Type 1 well is drilled vertically from the surface to kickoff point at a relatively shallow depth.

• At that point, the well is steadily and smoothly deflected until a maximum angle and the desired direction are achieved.

• The established angle and direction are maintained while drilling to the target depth.

TYPE 1 DIRECTIONAL WELL


• The Type II well is often called an “S” curve.

• The angle and direction are maintained until a specified depth and horizontal departure has been reached.

• Then, the angle is steadily and smoothly dropped until the well is near vertical.

• Drilling continues in the vertical hole below the intermediate casing to the target.



• The Type III well is a continues build to target.

• It is similar to the Type I well except the kickoff point is at a deeper depth, and surface casing is set prior to deflecting the well.

• The well is deflected at the kickoff point, and inclination is continually built through the target interval.



• Type IV wells can be categorized as horizontal or extended reach wells.

• Design of these wells can vary significantly, but they will have high inclinations and large horizontal departures.

• Horizontal wells will have an inclination greater than 80°.



• The geometry of a directional well can be defined with three parameters:• Build Rate,• Hold Inclination, (Drop Inclination), and • Kickoff Point (KOP).

• The directional well configuration can be determined by assuming any two of the above three parameters and then, calculating the third.

• The assumption of a particular parameter requires good understanding for an intelligent selection.

• Hold inclination and kickoff point are easier to calculate than the build rate.

PLANNING A DIRECTIONAL WELL


• The build-rate can be chosen to minimize fatigue in drill pipe, minimize keyseat possibility, or help to minimize torque and drag.

• If drilling a horizontal well, the build rate may be selected based on steerability of the bottomhole assembly.

• The hold inclination can be chosen based on any number of concerns.

• At low inclinations, it may be difficult to maintain the direction of the wellbore.

• Bit walk is greater at low inclinations because the direction can change significantly with small changes in dogleg severity.

• Above 30 degrees, it is more difficult to clean the hole with 45o to 60o being the hardest to clean.



• Above 60o, open hole logs may no longer fall. If the hole is not very clean, open hole logs may not fall at inclinations above 50o.

• In cased hole, wireline tools will not fall at inclinations greater than 70o.

• Tubing conveyed perforating or coiled tubing conveyed perforating will be required.

• The kickoff point may be selected based on hole conditions and target constraints.

• Many times it is desirable to case the build curve to minimize the possibility of a keyseat; therefore, the kickoff point may be based on casing seats.

• It may be desirable to drill some troublesome formations such as lost circulation or sloughing before kicking the well off.



• MWD tools do not tolerate large quantities of LCM for extended periods of time. In sloughing formations, stuck pipe may lead to loss of very expensive directional tools.

• If the troublesome formations are too deep, it may be desirable to be drilling a hold section in these formations.

• Generally, the build rate is chosen trying to keep below the endurance limit of the drill string in order to minimize the possibility of fatigue damage.

• The higher in the hole the kickoff point, the lower the dogleg severity needs to be in order to minimize fatigue in the drill string through the build section.



• It may not always be possible to drill a directional well and not cause some fatigue in the drill string or to keep the inclination below 30o.

• It depends upon the target departure. • With high departure targets, high inclinations will be required.

• After all, the objective of the directional well is to hit the target or to hit multiple targets.



• The trajectory of a deviated well must be carefully planned so that the most efficient trajectory is used to drill between the rig and the target location and ensure that the well is drilled for the least amount of money possible.

• When planning, and subsequently drilling the well, the position of all points along the wellpath and therefore the trajectory of the well must be considered in three dimensions.

• This means that the position of all points on the trajectory must be expressed with respect to a three dimensional reference system.

DEPTH REFERENCE AND GEOLOGICAL REFERENCE SYSTEMS

COMMITMENT TO ACADEMIC AND INDUSTRIAL EXCELLENCE

• The three dimensional system that is generally used to define the position of a particular point along the wellpath is:– the vertical depth of the point below a particular reference point,

– the horizontal distance traversed from the wellhead in a Northerly direction, and

– the distance traversed from the wellhead in an Easterly direction.

• The depth of a particular point in the wellpath is expressed in feet (or meters) vertically below a reference (datum) point and the Northerly and Easterly displacement of the point is expressed in feet (or meters) horizontally from the wellhead.



Well Planning Reference Systems



• There are a number of datum systems used in the depth reference systems.

• The datum systems which are most widely used are :– Mean Sea Level, MSL.– Rotary Table Elevation, RTE.– 20” Wellhead Housing.

• The Mean Sea Level, MSL is a permanent, national and well documented datum whereas datum such as the Rotary Table Elevation, RTE only exists when the drilling rig is on site.

• The top of the 20” Wellhead Housing is only available when the wellhead housing has been installed and will be removed when the well is abandoned.

DEPTH REFERENCE SYSTEMS


• Hence, since the only permanent datum is the MSL (the rig will be removed and the wellhead may be removed on abandonment), the distance between the MSL and the rotary table on the drillfloor and the MSL and the wellhead housing must be measured and recorded carefully on the well survey documents.

• The elevation of the rotary table above the MSL will be measured when the drilling rig is placed over the drilling location.

• The depths of the formations to be penetrated are generally referenced, by the geologists and reservoir engineers, to MSL since the Rotary Table Elevation will not be known until the drilling rig is in place.



• In most drilling operations the Rotary Table Elevation (RTE) is used as the working depth reference since it is relatively simple to measure depths relative to this point.

• The elevation of the RTE is also referred to as Derrick Floor Elevation (DFE).

• Depths measured from these references are often called depths below rotary table (BRT) or below derrick floor (BDF).

• The top of the kelly bushing is also used as a datum for depth measurement.

• In this case the depths are referred to as depths below rotary kelly bushing (RKB).



• The depth of any point in the wellpath can be expressed in terms of the Along Hole Depth (AHD) and the True Vertical Depth (TVD) of the point below the reference datum.

• The AHD is the depth of a point from the surface reference point, measured along the trajectory of the borehole.

• The TVD is the vertical depth of the point below the reference point.

• The AHD will therefore always be greater than the TVD in a deviated well.

• Since there is no direct way of measuring the TVD, it must be calculated from the information gathered when surveying the well.



• The position of a point in the well can only be defined in three dimensions when, in addition to the TVD of the point, its lateral displacement and the direction of that displacement is known.

• The lateral displacement is expressed in terms of feet (or meters) from the wellhead in a Northerly and Easterly direction or in degrees of latitude and longitude.

• All displacements are referenced to the wellhead position.

• The position of the wellhead is determined by land or satellite surveying techniques and quoted in latitude and longitude or an international grid co-ordinate system (e.g. Universal Transverse Mercator (UTM) system).



• Due to the large number of digits in some grid co-ordinate systems, a local origin is generally chosen and given the co-ordinates zero, zero (0,0).

• This can be the location of the well being drilled, or the centre of an offshore platform.

• When comparing the position of points in a well, and in particular for anti-collision monitoring, it is important that all coordinate data are ultimately referenced to a single system.

GEOGRAPHICAL REFERENCE SYSTEMS


RESERVOIR

TVDSSTVD MD

DF

GL

MSL

Drill Floor

Ground Level

TVDSSTVD MD

DF

GL

MSL

Offshore

DF or Rotary Table RT

On Land

Kelly Bushing KB

Mean Sea Level

MD - TVD - TVDSSDeviated Well

DEPTH REFERENCES


MSL

• The S-shaped well is more complex but is often required to ensure that the well penetrates the target formation vertically.

• This type of trajectory is often required in exploration and appraisal wells since it is easier to assess the potential productivity of exploration wells, or the efficiency of stimulation treatments when the productive interval is entered vertically, at right angles to the bedding planes of the formation.

• The deep kick-off profile may be required when drilling horizontal wells or if it is necessary to drill beneath an obstacle such as the flank of a salt diapir.

• This well profile is the most difficult trajectory to drill since it is necessary to initiate the deviated trajectory in deeper, well compacted formations.

PLANNING THE PROFILE OF THE WELL


• After the target and the rig position, the next stage is to plan the geometrical profile of the well to reach the target.

• The most common well trajectory is the build and hold profile, which consists of 3 sections - vertical, build-up and tangent.

• The trajectory of the wellbore can be plotted when the following points have been defined:– KOP (selected by designer).– TVD and horizontal displacement of the end of the build up section.

– TVD and horizontal displacement of the target (defined by position of rig and target).

DEFINING THE POINTS ON THE WELL PATH


• Since the driller will only be able to determine the along hole depth of the well the following information will also be required:– AHD of the KOP (same as TVD of KOP),– Buildup Rate for the build up section (selected by Designer),

– Direction in which the well is to be drilled after the KOP in degrees from North (defined by position of rig and target),

– AHD at which the build up stops and the tangent section commences, and

– AHD of the target.



• These depths and distances can be defined by a simple geometrical analysis of the well trajectory.

• Radius of the Buildup Section:– The radius R of the Buildup section of the well can be calculated from the build-up rate (γo/100 ft):



• Tangent Angle:• The tangent angle, α of the well can be calculated as follows:

• Note that it is possible for angle x to be negative if d < R, but these equations are still valid.

• Once the tangent angle is known the other points on the wellpath can be calculated as follows:



• AHD at the end of Build Section:• The measured depth at end of build section, AE:

– AE = AB + BE (curved length)

– BE can be calculated from

• TVD at the end of the Build Section:– The TVD at end of build section, AX is given by:

– AX = AB + PE•where PE = R sin α

– Thus, AX = AB + R sin α



• Displacement at the end of Build Section:– The horizontal deviation at end of build, XE is

– XE = OB - OP• where OB = R and OP = R cos α

– Thus, XE = R - R cos α = R(1 – cos α)

• AHD of the target:– The total measured depth, AT is given by:

– AT = AE + ET



• Design a well with the following data:– KOP (BRT) - 2000 ft– TVD of Target (BRT) - 10000 ft– Horizontal Displacement of Target - 3000 ft

– Build-up Rate - 2 degrees/100 ft

TUTORIAL 6


• (A) Using Scaled Diagrams:– Using a scaled diagram, this information can simply be plotted on a piece of graph paper using a compass and a ruler.

– Point A represents the rig location on surface.

– Point B is the KOP at 2000'. Point T is the target. Point O defines the centre of the arc which forms the buildup section.

– The radius OB can be calculated from the build-up rate:



• (A) Using Scaled Diagrams (contd.):– An arc of this radius can be drawn to define the build-up profile. A tangent from T can then be drawn to meet this arc at point E.

– The drift angle TEY can then be measured with a protractor.

– Note that TEY = BOE. – From this information the distances BX, XE, BE and EY can be calculated.

– This method of defining the well trajectory is not however very accurate, since an error of 1 degree or 2 degrees in measuring TEY with a protractor may mean that the tangent trajectory is imprecise and that the target may be missed by the driller.



• (B) Geometrical Calculation Technique:– The drift angle TEY can alternatively be calculated as follows:

– AE (Measured Depth at end of Build Section is given by:• AE = AB + BE

• From

• AE = (2000 + 1097.50) ft = 3097.50 ft.



• (B) Geometrical Calculation Technique (contd.):– AX (TVD at end of Build Section is given by:• AX = AB + PE

– where PE = R sin α = 1071.39 ft• AX = (2000 + 1071.39) ft = 3071.39 ft.

– XE (Horizontal Deviation at end of Build) is given by:• XE = OB – OP

– where OB = R and OP = R cos α = 2658.47 ft.

• XE = (2866.24 – 2658.47) ft = 207.77 ft.– AT (Total Measured Depth) is given by:

• AT = AE + ET

• From

• AT = 3097.5 + 7470.12) ft = 10567.62 ft.



• It has been decided to sidetrack a well from 1500 ft. The sidetrack will be a build and hold profile with the following specifications:– Target Depth: 10000 ft.– Horizontal Departure: 3500 ft.– Buildup Rate: 1.5o per 100 ft.

• Calculate the following:– a. the Drift Angle of the well.– b. the TVD and Horizontal Deviation at the end of the Buildup Section.

– c. the Total Measured Depth to the Target.

TUTORIAL 7


GLOSSARY OF TERMS


GLOSSARY OF TERMSAbandon a well v : to stop producing hydrocarbons when the well becomes unprofitable. A wildcat may be abandoned after poor results from a well test. Mechanical and cement plugs are placed in the wellbore to prevent fluid migration to surface and between different zones.

Abnormal pressure n : a formation pressure which is greater or less than the "normal“ formation fluid hydrostatic pressure. Such pressures may be classified as "subnormal“ (lower than normal) or "overpressured" (higher than normal).

Accelerometer n : a surveying instrument which measures components of the Earth's gravitational field.

Acidize v : to apply acids to the walls of oil and gas wells to remove any material which may obstruct flow into the wellbore.

Adjustable choke n : a choke in which the rate of flow is controlled by adjusting a conical needle and seat.

Air drilling n : a method of drilling that uses compressed air as the circulating medium.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSAngle unit n : the component of a survey instrument used to measure inclination.

Annular preventer n : a large BOP valve that forms a seal in the annular space between the wellbore and the drillpipe. It is usually installed above the ram type preventers in the BOP stack.

Annulus n : the space between the drillstring and open hole or drillstring and cased hole in the wellbore.

Anticline n : a configuration of folded and stratified rock layers in the shape of an arch. Often associated with a trap.

A.P.I. abbr : American Petroleum Institute. The leading standardising organisation on oilfield drilling and production equipment.

A.P.I. gravity n : a measure of the density of liquid petroleum products, expressed in degrees. It can be derived from the following equation:API Gravity (degrees) = 141.5 - 131.5

Specific Gravity


GLOSSARY OF TERMSAzimuth n : used in directional drilling as the direction of the trajectory of the wellbore measured in degrees (0-359) clockwise from True North or Magnetic North.Back off v : to disconnect a section of stuck drillpipe by unscrewing one of the connections above the stuckpoint.Back up :1. v - to hold one section of pipe while another is being screwed into or out of it (as in back up tongs).2. n - a piece of equipment held in reserve in case another piece fails.Badger bit n : a specially designed bit with one large nozzle, which can be used as a deflecting tool in soft formations.Bail n : a rounded steel bar which supports the swivel and connects it to the hook. May also apply to the steel bars which connect the elevators to the hook (links).Ball up v : buildup of a mass of sticky material (drill cuttings) on components of drillstring (especially bits and stabilisers).


GLOSSARY OF TERMSBarge n : a flat decked, shallow draft vessel which may accommodate a drilling rig, or be used to store equipment and materials or for living quarters.

Barite (Baryte) n : Barium Sulphate (BaSO4), a mineral used as a weighting material to increase mud weight (specific gravity = 4.2).

Barrel n : a measure of volume for fluids. One barrel (bbl) = 42 U.S. gallons = 0.15899 cubic metres. The term bbl is derived from the blue barrels in which oil was originally transported.

Bed n : a geological term to specify one particular layer of rock.

Bell nipple n : In marine drilling, the uppermost component of the marine riser attached to the telescopic joint. The top of the nipple is expanded to guide drilling tools into the well.

Bentonite n : a finely powdered clay material (mainly montmorillonite) which swells when mixed with water. Commonly used as a mud additive, and sometimes referred to as "gel".


GLOSSARY OF TERMSBent sub n : a short piece of pipe whose axis is deviated 1°-3° off vertical. Used in directional drilling as a deflecting tool.Bit n : the cutting element at the bottom of the drillstring, used for boring through the rock.Bit breaker n : a heavy metal plate which fits into the rotary table and holds the bit while it is being connected to or disconnected from the drillstring.

Bit record n : a report containing information relating to the operating parameters and performance of the bits run in a well.Bit sub n : a short length of pipe installed immediately above the bit. The threads on the bit sub accept the pin thread on the bit and the pin thread for the drillcollars.Bit walk n : the tendency for the bit and drillstring to wander off course by following the direction of rotation (usually to the right) in a directionally drilled well.Blind rams n : one of the valves on the BOP stack. It is designed to close off the wellbore when the drillstring is out of the hole.Blocks n : an assembly of pulleys on a common framework.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSBlooey line n : the discharge pipe from a well being drilled with compressed air.

Blowout n : an uncontrolled flow of formation fluids into the atmosphere at surface.

BOP abbr : Blow Out Preventer. A valve installed on top of the wellhead to control wellbore pressure in the event of a kick.

BOP stack n : an assembly of BOPs consisting of annular preventers and ram type preventers. For land drilling the BOP stack is installed just below the rig floor, while for floating rigs the stack is positioned on the seabed.

Borehole n : the hole made by the drill bit.

Bottom hole assembly (BHA) n : the part of the drillstring which is just above the bit and below the drillpipe. It usually consists of drill collars, stabilisers and various other components.

Bottom hole pressure (bhp) n : the pressure,1. at the bottom of the borehole, or 2. at a point opposite the producing formation.

Box n : the female section of a tool joint or other connection.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSBrake n: the device operated by the driller to stop the downward motion of the travelling block and therefore the drillstring.

Breakout v : to unscrew one section of pipe from another.

Bridge n : an obstruction in the borehole usually caused by the borehole wall caving in.

BRT abbr : Below Rotary Table. Reference point for measuring depth.

Building assembly n : a BHA specially designed to increase the inclination (drift angle) of the wellbore.

Build up rate n : the rate at which drift angle is increasing as the wellbore is being deviated from vertical. Usually measured in degrees per 100 ft drilled.

Build up section n : that part of the wellbore's trajectory where the drift angle is increasing.

Bumper sub n : a drilling tool, placed in the BHA, consisting of a short stroke slip joint which allows a more constant WOB to be applied when drilling from a floating rig.


GLOSSARY OF TERMSCable tool drilling n : an earlier method of drilling used before the introduction of modern rotary methods. The bit was not rotated but reciprocated by means of a strong wire rope.

Caliper log n : a tool run on electric wireline which measures the diameter of the wellbore. It may be used for detecting washouts, calculating cement volumes, or detecting internal corrosion of casing.

Cap rock n : an impermeable layer of rock overlying an oil or gas reservoir and preventing the migration of fluids.

Cased hole n : that part of the hole which is supported by a casing which has been run and cemented in place.

Casing n : large diameter steel pipe which is used to line the hole during drilling operations.

Casing head Housing n : a large recepticle which is installed on top of the surface casing string. It has an upper flanged connection. Once it is installed it provides: a landing shoulder for the next casing string; and a flanged connection for the BOP stack to be connected to the well.


GLOSSARY OF TERMSCasing head spool n : a large receptacle which is installed on top of the casing head housing or a previous spool. It has both an upper and lower flanged connection. Once it is installed it provides: a landing shoulder for the next casing string; access to the annulus between the casing strings and a flanged connection for the BOP stack to be connected to the well.

Casing hanger n : a special component which is made up on top of the casing string to suspend the casing from the previous casing housing or spool.

Casing shoe n : a short section of steel pipe filled with concrete and rounded at the bottom. This is installed on the bottom of the casing string to guide the casing past any ledges or irregularities in the borehole. Sometimes called a guide shoe.

Casing string n : the entire length of all the casing joints run into the borehole.

Cathead n : a spool shaped attachment on a winch, around which rope is wound. This can be used for hoisting operations on the rig floor.


GLOSSARY OF TERMSCaving: 1. v: collapse of the walls of the borehole. Also referred to as "sloughing".2. n: a small part of the borehole wall that has collapsed into the hole.

Centraliser n : a device secured around the casing which is designed to support and centralise the casing in deviated wellbores.

Centrifugal pump n : a pump consisting of an impellor, shaft and casing which discharges fluid by centrifugal force. Often used for mixing mud.

Centrifuge n : a piece of solids control equipment which separates out particles of varying density.

Cement Slurry n: A mixture of cement powder, water and additives which harden to form a cement sheath or cement plug in a well.

Cementing v : the placement of a liquid slurry of cement and water inside or outside of the casing. Primary cementing is carried out immediately after the casing is run. Secondary cementing is carried out when remedial work is required.


GLOSSARY OF TERMSCement channeling v : the irregular displacement of mud by cement, leaving voids in the cement sheath between the casing and the borehole, thereby reducing the effectiveness of the cement sheath.

Cement head n : a manifold system installed on the top of the casing which allows the cement slurry to be pumped from the cement unit down the casing string. The cement head is also used for releasing the top and bottom cement plugs.

Cement plug n :1. A specific volume of cement placed at some point in the wellbore to seal off the well.2.A device used during a primary cement job to separate the cement slurry from contaminating fluids in the casing. A wiper plug is pumped ahead of the slurry and a shut off plug behind the slurry.

Chain tongs n : a tool used by roughnecks on the rig floor to tighten or loosen a connection. The tool consists of a long handle and an adjustable chain which will fit a variety of pipe sizes.


GLOSSARY OF TERMSChoke line n : a pipe connected to the BOP stack which allows fluids to be circulated out of the annulus and through the choke manifold when a well kiling operation is beimg performed.

Choke manifold n : an arrangement of pipes, valves and chokes which allows fluids to be circulated through a number of routes.

Christmas tree n : an assembly of control valves and fittings installed on top of the wellhead. The Christmas tree is installed after the well has been completed and is used to control the flow of oil and gas.

Circulate v : to pump drilling fluid through the drillstring and wellbore, returning to the mud pits. This operation is carried out during drilling and is also used to improve the condition of the mud while drilling is suspended.

Clay n : a term used to describe the aluminium silicate minerals which are plastic when wet and have no well-developed parting along bedding planes. Such material is commonly encountered while drilling a well.

Clay minerals n : the constituents of a clay which provide its plastic properties. These include kaolinite, illite, montmorillonite and vermiculite.


GLOSSARY OF TERMSClosure n : the shortest horizontal distance from a particular survey station back to the reference point.

Combination string n : a casing string which is made up of various different grades or weights of casing (sometimes referred to as a tapered string when different sizes of casing are used).

Company man n : an employee of an operating company whose job is to represent the operator's interests on the drilling rig (sometimes referred to as "drilling supervisor“ or "company man").

Compass unit n : the component of a survey instrument used to measure azimuth.

Completion1. v : the activities and methods used to prepare a well for the production of oil or gas.2. n: the tubing and accessories installed in the production casing and through which the produced fluid flows to surface.

Conductor line n : a small diameter wireline which carries electric current. This is used for logging tools and steering tools.


GLOSSARY OF TERMSConductor pipe n : a short string of casing of large diameter which is normally the first casing string to be run in the hole.

Connection v : the joining of a section of drillpipe to the top of the drillstring as drilling proceeds.

Core n : a cylindrical rock sample taken from the formation for geological analysis.

Core barrel n : a special tool which is installed at the bottom of the drillstring to capture and retain a core sample which is then recovered when the string is pulled out of the hole.

Core Bit (Core Head) n: A donut shaped drilling bit used just below the core barrel to cut a cylindrical sample of rock.

Correction run n : a section of hole which must be directionally drilled to bring the well path back onto the planned course.

Crater n : a large hole which develops at the surface of a wellbore caused by the force of escaping gas, oil or water during a blowout.

Cross-over n : a sub which is used to connect drill string components which have different types or sizes of threads.


GLOSSARY OF TERMSCrown block n : an assembly of sheaves or pulleys mounted on beams at the top of the derrick over which the drilling line is reeved.

Cuttings n : the fragments of rock dislodged by the bit and carried back to surface by the drilling fluid.

Deadline n : that part of the drilling line between the crown block and the deadline anchor. This line remains stationary as the travelling block is hoisted.

Deadline anchor n : a device to which the deadline is attached and securely fastened to the derrick substructure.

Defecting tool n : a piece of drilling equipment which will change the inclination and/or direction of the hole.

Degasser n : a piece of equipment used to remove unwanted gas from the drilling mud.

Density n : the mass of a substance per unit volume. Drilling fluid density is usually expressed in psi/ft, kg/m3, g/cc or ppg.

Departure n : one of the coordinates used to plot the path of the well on the horizontal plane (along the x axis).


GLOSSARY OF TERMSDerrick n : a large load-bearing structure from which the hoisting system and therefore the drillstring is suspended.

Derrickman n : a member of the drilling crew whose work station is on the monkey board high up in the derrick. From there he handles the upper end of the stands of drillpipe being raised or lowered. He is also responsible for maintaining circulation equipment and carrying out routine checks on the mud.

Desander n : a hydrocyclone used to remove sand from the drilling mud.

Desilter n : a hydrocyclone used to remove fine material (silt size) from the drilling mud.

Development well n : a well drilled in a proven field to exploit known reserves. Usually one of several wells drilled from a central platform.

Deviation n : a general term referring to the horizontal displacement of the well. May also be used to describe the change in drift angle from vertical (inclination).


GLOSSARY OF TERMSDiamond bit n : a bit which has a steel body surfaced with diamonds to increase wear resistance.

Directional drilling : n the intentional deviation of a wellbore in order to reach a certain objective some distance from the rig.

Directional surveying n : a method of measuring the inclination and direction of the wellbore by using a downhole instrument. The well must be surveyed at regular intervals to accurately plot its course.

Discovery well n : the first well drilled in a new field which successfully indicates the presence of oil or gas reserves.

Displace v : to move a liquid (e.g. cement slurry) from one position to another by means of pumping another fluid behind it.

Displacement fluid n : the fluid used to force cement slurry or some other material into its intended position. (e.g. drilling mud may be used to displace cement out of the casing into the annulus).

Dog house n : a small enclosure on the rig floor used as an office by the driller and as a storage place for small items.


GLOSSARY OF TERMSDog leg n : a sharp bend in the wellbore which may cause problems tripping in and out of the hole.

Dog leg severity n : a parameter used to represent the change in inclination and azimuth in the well path (usually given in degrees per 100 ft).

Dope n : a lubricant for the threads of oilfield tubular goods.

Double n : a section of drillpipe, casing or tubing consisting of two single lengths screwed together.

Downhole motor n : a special tool mounted in the BHA to drive the bit without rotating the drill string from surface (see positive displacement motor).

Downhole telemetry n : the process whereby signals are transmitted from a downhole sensor to a surface readout instrument. This can be done by a conductor line (as on steering tools) or by mud pulses (as in MWD tools).

Drag n : The force required to move the drillstring due to the drillstring being in contact with the wall of the borehole.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSDrag bit n : a drilling bit which has no cones or bearings but consists of a single unit with a cutting structure and circulation passageways. The fishtail bit was an early example of a drag bit, but is no longer in common use. Diamond bits are also drag bits.

Drawworks n : the large winch on the rig which is used to raise or lower the drill string into the well.

Drift angle n : the angle which the wellbore makes with the vertical plane (see inclination).

Drill collar n : a heavy, thick-walled steel tube which provides weight on the bit to achieve penetration. A number of drill collars may be used between the bit and the drillpipe.

Driller n : the employee of the drilling contractor who is in charge of the drilling rig and crew. His main duties are to operate the drilling equipment and direct rig floor activities.

Drilling contractor n : an individual or company that owns the drilling rig and employs the crew required to operate it.


GLOSSARY OF TERMSDrilling crew n : the men required to operate the drilling rig on one shift or tour. This normally comprises a driller, derrickman and 2 or 3 roughnecks.

Drilling fluid n : the fluid which is circulated through the drillstring and up the annulus back to surface under normal drilling operations. Usually referred to as mud.

Drilling line n : the wire rope used to support the travelling block, swivel, kelly and drillstring.

Drill pipe n : a heavy seamless pipe which is used to rotate the bit and circulate the drilling fluid. Lengths of drill pipe 30ft long are coupled together with tool joints to make the drillstring.

Drill ship n : a specially designed ship which is used to drill a well at an offshore location.

Drill stem n : used in place of drillstring in some locations. Describes all the drilling components from the swivel down to the bit.


GLOSSARY OF TERMSDrill stem test (DST) n : a test which is carried out on a well to determine whether or not oil or gas is present in commercial quantities. The downhole assembly consists of a packer, valves and a pressure recording device, which are run on the bottom of the drill stem.

Drillstring n : the string of drill pipe with tool joints which transmits rotation and circulation to the drill bit. Sometimes used to include both drill collars and drill pipe.

Drop off section n : that part of the well's trajectory where the drift angle is decreasing (i.e. returning to vertical).

Duplex pump n : a reciprocating positive displacement pump having 2 pistons which are double acting. Used as the circulating pump on some older drilling rigs.

Dynamic positioning n : a method by which a floating drilling rig or drill ship is kept on location. A control system of sensors and thrusters is required.

Easting n : one of the co-ordinates used to plot a deviated well's position on the horizontal plane (along the x axis).COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSElectric logging v : the measurement of certain electrical characteristics of formations traversed by the borehole. Electric logs are run on conductor line to identify the type of formations, fluid content and other properties.

Elevators n : a lifting collar connected to the travelling block, which is used to raise or lower pipe into the wellbore. The elevators are connected to the travelling block by links or bails.

Emulsion n : a mixture in which one liquid (dispersed phase) is uniformly distributed in another liquid (continuous phase). Emulsifying agents may be added to stabilise the mixture.

Exploration well n : a well drilled in an unproven area where no oil and gas production exists (sometimes called a "wildcat").

Fastline n : the end of the drilling line which is attached to the drum of the drawworks.

Fault n : a geological term which denotes a break in the subsurface strata. On one side of the fault line the strata has been displaced upwards, downwards or laterally relative to its original position. COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSField n : a geographical area in which oil or gas wells are producing from a continuous reservoir.

Filter cake n : the layer of concentrated solids from the drilling mud that forms during natural filtration on the sides of the borehole. Sometimes called "wall cake" or "mud cake".

Filter press n : a device used in the measurement of the mud's filtration properties.

Filtrate n : a fluid which has passed through a filter. In drilling it usually refers to the liquid part of the mud which enters the formation.

Filtration v : the process by which the liquid part of the drilling fluid is able to enter a permeable formation, leaving a deposit of mud solids on the borehole wall to form a filter cake.

Fish n : any object accidentally left in the wellbore during drilling or workover operations, which must be removed before work can proceed.


GLOSSARY OF TERMSFishing v : the process by which a fish is removed from the wellbore. It may also be used for describing the recovery of certain pieces of downhole completion equipment when the well is being reconditioned during a workover.

Fishing tool n : a specially designed tool which is attached to the drill string in order to recover equipment lost in the hole.

Flange up v : to connect various components together (e.g. in wellheads or piping systems).

Flare n : an open discharge of fluid or gas to the atmosphere. The flare is often ignited to dispose of unwanted gas around a completed well.

Flex joint n : a component of the marine riser system which can accommodate some lateral movement when drilling from a floater.

Float collar n : a special device inserted one or two joints above the bottom of a casing string. The float collar contains a check valve which permits fluid flow in a downward direction only. The collar thus prevents the back flow of cement once it has been displaced.


GLOSSARY OF TERMSFloater n : general term used for a floating drilling rig.

Float shoe n : a short cylindrical steel component which is attached to the bottom of a casing string. The float shoe has a check valve and functions in the same manner as the float collar. In addition the float shoe has a rounded bottom which acts as a guide shoe for the casing.

Float sub n : a check valve which prevents upward flow through the drill string.

Flocculation v : the coagulation of solids in a drilling fluid produced by special additives or contaminants in the mud.

Fluid loss v : the transfer of the liquid part of the mud to the pores of the formation. Loss of fluid (water plus soluble chemicals) from the mud to the formation can only occur where the permeability is sufficiently high. If the pores are large enough the first effect is a "spurt loss", followed by the build up of solids (filter cake) as filtration continues.

Formation n : a bed or deposit composed throughout of substantially the same kind of rock to form a lithologic unit.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSFormation fluid n : the gas, oil or water which exists in the pores of the formation.

Formation pressure n : the pressure exerted by the formation fluids at a particular point in the formation. Sometimes called "reservoir pressure" or "pore pressure".

Formation testing v : the measurement and gathering of data on a formation to determine its potential productivity.

Fracture n : a break in the rock structure along a particular direction. Fractures may occur naturally or be induced by applying downhole pressure in order to increase permeability.

Fracture gradient n : a measure of how the strength of the rock (i.e. its resistance to break down) varies with depth.

Fulcrum assembly n : a bottom hole assembly which is designed to build hole inclination.

Gas cap n : the free gas phase which is sometimes found overlying an oil zone and occurs within the same formation as the oil.

Gas cut mud n : mud which has been contaminated by formation gas.COMMITMENT TO ACADEMIC AND INDUSTRIAL EXCELLENCE 519

GLOSSARY OF TERMSGas show n : the gas that is contained in mud returns, indicating the presence of a gas zone.

Gas injector n : a well through which produced gas is forced back into the reservoir to maintain formation pressure and increase the recovery factor.

Gel n : a semi-solid, jelly-like state assumed by some colloidal dispersions at rest. When agitated the gel converts to a fluid state.

Gel strength n : the shear strength of the mud when at rest. Its ability to hold solids in suspension. Bentonite and other colloidal clays are added to the mud to increase gel strength.

Geostatic pressure n : the pressure exerted by a column of rock. Under normal conditions this pressure is approximately 1 psi per foot. This is also known as "lithostatic pressure" or "overburden pressure".

Guideline tensioner n : a pneumatic or hydraulic device used to provide a constant tension on the wire ropes which run from the subsea guide base back to a floating drilling rig.

Guide shoe n : See Float Shoe.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSGumbo n : clay formations which contaminate the mud as the hole is being drilled.The clay hydrates rapidly to form a thick plug which cannot pass through a marine riser or mud return line.

Gunk n : a term used to describe a mixture of diesel oil, bentonite and sometimes cement which is used to combat lost circulation.

Gusher n : an uncontrolled release of oil from the wellbore at surface.

Gyro multi-shot n : a surveying device which measures and provides a series of photographic images showing the inclination and direction of the wellbore. It measures direction by means of a gyroscopic compass.

Gyro single-shot n : a surveying device which measures the inclination and direction of the borehole at one survey station. It measures direction by means of a gyroscopic compass. COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSGyroscope n : a wheel or disc mounted on an axle and free to spinto spin rapidly about one axis, but free to rotate about one or both of the other two axes. The inertia of the wheel keeps the axis aligned with the reference direction (True North in directional survey tools).

Hole opener n : a special drilling tool which can enlarge an existing hole to a larger diameter.

Hook n : the large component attached to the travelling block from which the drill stem is suspended via the swivel.

Hopper n : a large funnel shaped device into which dry material (e.g. cement or powdered clay) can be poured. The purpose of the hopper is to mix the dry material with liquids injected at the bottom of the hopper.

H.W.D.P. abbr : heavy weight drill pipe. Thick walled drill pipe with thick walled sections used in directional drilling and placed between the drill collars and drill pipe.

Hydrostatic pressure n : the load exerted by a column of fluid at rest. Hydrostatic pressure increases uniformly with the density and depth of the fluid. COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSInclination n : a measure of the angular deviation of the wellbore from vertical. Sometimes referred to as "drift angle".

Injection n : usually refers to the process whereby gas, water or some other fluid is forced into the formation under pressure.

Impermeable adj : preventing the passage of fluid through the pores of the rock.

Insert bit n : a type of roller cone bit where the cutting structure consists of specially designed tungsten carbide cutters set into the cones.

Intermediate casing n : a string of casing set in the borehole to keep the hole from caving and to seal off troublesome formations.

Invert oil emulsion mud n : a drilling fluid which contains up to 50% by volume of water, which is distributed as droplets in the continuous oil phase. Emulsifying agents and other additives are also present.

Iron roughneck n : an automated piece of rig floor equipment which can be used to make connections.


GLOSSARY OF TERMSJack-up rig n : an offshore drilling structure which is supported on steel legs.

Jet deflection n : a technique used in directional drilling to deviate the wellbore by washing away the formation in one particular direction. A special bit (badger bit) is used which has one enlarged nozzle which must be orientated towards the intended inclination.

Jet sub n : a tool used at the bottom of the drill pipe when the conductor pipe is being jetted into position (this method of running the conductor is only suitable where the surface formations can be washed away by the jetting action).

Joint n : a single length of pipe which has threaded connections at either end.

Junk n : debris lost in the hole which must be removed to allow normal operations to continue.

Junk sub n : a tool run with the BHA, which is designed to recover pieces of debris left in the hole.

Kelly n : the heavy square or hexagonal steel pipe which runs through the rotary table and is used to rotate the drillstring.


GLOSSARY OF TERMSKelly bushing n : a device which fits into the rotary table and through which the kelly passes. The rotation of the table is transmitted via the kelly bushing to the kelly itself. Sometimes called the “drive bushing”.

Kelly cock n : a valve installed between the kelly and the swivel. It is used to control a backflow of fluid up the drillstring and isolate the swivel and hose from high pressure.

Kelly spinner n : a pneumatically operated device mounted on top of the kelly which, when actuated, causes the kelly to rotate. It may be used to make connections by spinning up the kelly.

Key seat n : a channel or groove cut into the side of the borehole due to the dragging action of the pipe against a sharp bend (or dog leg).

Key seat wiper n : a tool made up in the drillstring to ream out any key seats which may have formed and thus prevent the pipe from becoming stuck.

Kick n : an entry of formation fluids (oil, gas or water) into the wellbore caused by the formation pressure exceeding the pressure exerted by the mud column.


GLOSSARY OF TERMSLiner hanger n : a slip type device which suspends the liner inside the previous casing shoe.

Location n : the place at which a well is to be drilled.

Log n : a systematic recording of data (e.g. driller’s log, electric log, etc.)

Lost circulation n : the loss of quantities of whole mud to a formation due to caverns, fractures or highly permeable beds. Also referred to as “lost returns”.

Magnetic declination n : the angle between True North and Magnetic North. This varies with geographical location, and also changes slightly each year.

Magnetic multi-shot n : a surveying instrument which provides a series of photographic discs showing the inclination and direction of the wellbore. It measures direction by means of a magnetic compass and so direction is referenced to Magnetic North.

Magnetic North n : the northerly direction in the earth’s magnetic field indicated by the needle of a magnetic compass.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSMagnetometer n : a surveying device which measures the intensity and direction of the earth’s magnetic field.

Make up v : to assemble and join components together to complete a unit (e.g. to make up a string of casing).

Make hole v : to drill ahead

Marine riser n : the pipe which connects the subsea BOP stack with the floating drilling rig. The riser allows mud to be circulated back to surface, and provides guidance for tools being lowered into the wellbore.

Mast n : a portable derrick capable of being erected as a unit unlike a standard derrick which has to be built up.

Master bushing n : a sleeve which fits into and protects the rotary table and accommodates the slips and drives the kelly bushing.

Measured depth (MD) n : the distance measured along the path of the wellbore (i.e. the length of the drillstring).

Mill n : a downhole tool with rough, sharp cutting surfaces for removing metal by grinding or cutting.


GLOSSARY OF TERMSMilled tooth bit n : a roller cone bit whose cutting surface consists of a number of steel teeth projecting from the surface of the cones.

Monel n : term used for a non-magnetic drill collar made from specially treated steel alloys so that it does not affect magnetic surveying instruments.

Monkey board n : the platform on which the derrickman works when handling stands of pipe.

Moon pool n : the central slot under the drilling floor on a floating rig.

Motion compensator n : a hydraulic or pneumatic device usually installed between the travelling block and hook. Its function is to keep a more constant weight on the drill bit when drilling from a floating vessel. As the rig heaves up and down a piston moves within the device to cancel out this vertical motion.

Mousehole n : a small diameter pipe under the derrick floor in which a joint of drill pipe is temporarily stored for later connection to the drillstring.


GLOSSARY OF TERMSM.S.L. abbr : Mean Sea Level.

Mud n : common term for drilling fluid.

Mud balance n : a device used for measuring the density of mud or cement slurry. It consists of a cup and a graduated arm which carries a sliding (counterbalanced) weight and balances on a fulcrum.

Mud conditioning v : the treatment and control of drilling fluid to ensure that it has the correct properties. This may include the use of additives, removing sand or other solids, adding water and other measures. Conditioning may also involve circulating the mud prior to drilling ahead.

Mud engineer n : usually an employee of a mud service company whose main responsibility on the rig is to test and maintain the mud properties specified by the operator.

Mudline n : the seabed.

Mudlogging n : the recording of information derived from the examination and analysis of drill cuttings. This also includes the detection of oil and gas. This work is usually done by a service company which supplies a portable laboratory on the rig.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSMud motor n : a downhole component of the BHA which rotates the bit without having to turn the rotary table. The term is sometimes applied to both positive displacement motors and turbodrills.

Mud pits n : a series of open tanks in which the mud is mixed and conditioned. Modern rigs are provided with three or more pits, usually made of steel plate with built-in piping, valves and agitators.

Mud pump n : a large reciprocating pump used to circulate the drilling fluid down the well. Both duplex and triplex pumps are used with replaceable liners. Mud pumps are also called “slush pumps”.

Mud return line n : a trough or pipe through which the mud being circulated up the annulus is transferred from the top of the wellbore to the shale shakers. Sometimes called a “flowline”.

Mud screen n : shale shaker.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSMule shoe n : the guide shoe on the lower end of a survey tool which locates into the key way of the orienting sub. The survey tool can then be properly aligned with the bent sub.

M.W.D. abbr : Measurements While Drilling. A method of measuring petrophysical properties of formations, drilling parameters (WOB, torque etc.) and environmental parameters downhole and sending the results to surface without interrupting routine drilling operations. A special tool containing sensors, power supply and transmitter is installed as part of the BHA. The information is transmitted to surface by a telemetry system using mud pulses or signals through the pipe.

Nipple n : a short length of tubing (generally less than 12") with male threads at both ends.

Nipple up v : to assemble the components of the BOP stack on the wellhead.

Normal pressure n : the formation pressure which is due to a normal deposition process where the pore fluids are allowed to escape under compaction. The normal pressure gradient is usually taken as 0.465 psi per foot of depth from surface.


GLOSSARY OF TERMSNorthing n : one of the co-ordinates used in plotting the position of the wellbore in the horizontal plane along the y axis.

Offshore drilling n : drilling for oil or gas from a location which may be in an ocean, gulf, sea or lake. The drilling rig may be on a floating vessel (e.g. semi-submersible, drill ship) or mounted on a platform fixed to the seabed (e.g. jack up, steel jacket).

Oil based mud n : a drilling fluid which contains oil as its continuous phase with only a small amount of water dispersed as droplets.

Open hole n : any wellbore or part of the wellbore which is not supported by casing.

Operator n : the company which carries out an exploration or development programme on a particular area for which they hold a license. The operator may hire a drilling contractor and various service companies to drill wells, and will provide a representative (company man) on the rig.

Orientation v : the process by which a deflection tool is correctly positioned to achieve the intended direction and inclination of the wellbore.


GLOSSARY OF TERMSOrienting sub n : a special sub which contains a key or slot, which must be aligned with the scribe line of the bent sub. A surveying instrument can then be run into the sub aligning itself with the key to give the orientation of the scribe line, which defines the tool face.

Overburden n : the layers of rock lying above a particular formation.

Overshot n : a fishing tool which is attached to the drill pipe and is lowered over, and engages, the fish externally.

Packed hole assembly n : a BHA which is designed to maintain hole inclination and direction of the wellbore.

Packer n : a downhole tool, run on drillpipe, tubing or casing, which can be set hydraulically or mechanically against the wellbore. Packers are used extensively in DSTs, cement squeezes and completions.

Pay zone n : the producing formation.

Pendulum assembly n : a BHA which is designed to reduce hole inclination by allowing the drill collars to bend towards the low side of the hole.


GLOSSARY OF TERMSPerforate v : to pierce the casing wall and cement, allowing formation fluids to enter the wellbore and flow to surface. This is a critical stage in the completion of a well. Perforating may also be carried out during workover operations.

Perforating gun n : a device fitted with shaped charges which is lowered on wireline to the required depth. When fired electrically from the surface the charges shoot holes in the casing and the tool can then be retrieved.

Permeability n : a measure of the fluid conductivity of a porous medium (i.e. The ability of fluid to flow through the interconnected pores of a rock). The units of permeability are darcies or millidarcies.

pH value n : a parameter which is used to measure the acidity or alkalinity of a substance.

Pilot hole n : a small diameter hole which is later opened up to the required diameter. Sometimes used in directional drilling to control wellbore deviation during kick off.

Pin n : the male section of a threaded connection.COMMITMENT TO ACADEMIC AND INDUSTRIAL EXCELLENCE 534

GLOSSARY OF TERMSPipe ram n : a sealing device in a blowout preventor which closes off the annulus around the drill pipe. The size of ram must fit the drillpipe which is being used.

Polycrystalline diamond compact bit (PDC bit) n : a PDC bit is a type of drag bit which uses small discs of man-made diamond as the cutting surface.

P.O.H. abbr : Pull Out of Hole.

Pore n : an opening within a rock which is often filled with formation fluids.

Porosity n : a parameter used to express the pore space within a rock (usually given as a percentage of unit volume).

Positive displacement motor (PDM) n : a drilling tool which is located near the bit and is used to rotate the bit without having to turn the entire drillstring. A spiral rotor is forced to rotate within a rubber sleeved stator by pumping mud through the tool. Sometimes called a “Moineau pump” or “screw drill”.

Pressure gradient n : the variation of pressure with depth. Commonly used under hydrostatic conditions (e.g. a hydrostatic column of salt water has a pressure gradient of 0.465 psi/ft).


GLOSSARY OF TERMSPrimary cementing n : placing cement around the casing immediately after it has been run into the hole.

Prime mover n : an electric motor or internal combination engine which is the source of power on the drilling rig.

Production casing n : the casing string through which the production tubing and accessories are run to complete the well.

Propping agent n : a granular material carried in suspension by the fracturing fluid which helps to keep the cracks open in the formation after fracture treatment.

Protective casing n : an intermediate string of casing which is run to case off any troublesome zones.

p.s.i. abbr : pounds per square inch. Commonly used unit for expressing pressure.

Pup joint n : a short section of pipe used to space out casing or tubing to reach the correct landing depths.

Rathole n :1. A hole in the rig floor 30'-60' deep and lined with pipe. It is used for storing the kelly while tripping.2. That part of the wellbore which is below the bottom of the casing or completion zone.


GLOSSARY OF TERMSReactive torque n : the tendency of the drillstring to turn in the opposite direction from that of the bit. This effect must be considered when setting the toolface in directional drilling.

Ream v : to enlarge the wellbore by drilling it again with a special bit.

Reamer n : a tool used in a BHA to stabilise the bit, remove dog legs or enlarge the hole size.

Reeve v : to pass the drilling line through the sheaves of the travelling block and crown block and onto the hoisting drum.

Relief well n : a directionally drilled well whose purpose is to intersect a well which is blowing out, thus enabling the blow out to be controlled.

Reservoir n : a subsurface porous permeable formation in which oil or gas is present.

Reverse circulate v : to pump fluid down the annulus and up the drillstring or tubing back to surface.

Rig n : the derrick, drawworks, rotary table and all associated equipment required to drill a well.


GLOSSARY OF TERMSR.I.H. abbr : Run In Hole.

Riser tensioner n : a pneumatic or hydraulic device used to provide a constant strain in the cables which support the marine riser.

R.K.B. abbr : Rotary Kelly Bushing. Term used to indicate the reference point for measuring depths.

Roller cone bit n : a drilling bit with 2 or more cones mounted on bearings. The cutters consist of rows of steel teeth or tungsten carbide inserts. Also called a “rock bit”.

R.O.P. abbr : rate of penetration, normally measured in feet drilled per hour.

Rotary hose n : a reinforced flexible tube which conducts drilling fluid from the standpipe to the swivel. Also called "kelly hose" or “mud hose”.

Rotary table n : the main component of the rotating machine which turns the drillstring. It has a bevelled gear mechanism to create the rotation and an opening into which bushings are fitted.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSRoughneck n : an employee of a drilling contractor who works on the drill floor under the direction of the driller.

Round trip v : the process by which the entire drillstring is pulled out the hole and run back in again (usually to change the bit or BHA).

Roustabout n : an employee of the drilling contractor who carries out general labouring work on the rig.

R.P.M. abbr : revolutions per minute. Term used to measure the speed at which the drillstring is rotating.

Safety joint n : a tool which is often run just above a fishing tool. If the fishing tool has gripped the fish but cannot pull it free the safety joint will allow the string to disengage by turning it from surface.

Salt dome n : an anticlinal structure which is caused by an intrusion of rock salt into overlying sediments. This structure is often associated with traps for petroleum accumulations.

Sand n : an abrasive material composed of small quartz grains. The particles range in size from 1/16 mm to 2 mm. The term is also applied to sandstone.


GLOSSARY OF TERMSSandline n : small diameter wire on which light-weight tools can be lowered down the hole (e.g. surveying instruments).

Scratcher n : a device fastened to the outside of the casing which removes mud cake and thus promote a good cement job.

Semi-submersible n : a floating drilling rig which has submerged hulls, but not resting on the seabed.

Shale n : a fine-grained sedimentary rock composed of silt and clay sized particles.

Shale shaker n : a series of trays with vibrating screens which allow the mud to pass through but retain the cuttings. The mesh must be chosen carefully to match the size of the solids in the mud.

Shear ram n : the component of the BOP stack which cuts through the drillpipe and forms a seal across the top of the wellbore.

Sheave n : (pronounced “shiv”) a grooved pulley.

Sidetrack v : to drill around some permanent obstruction in the hole with some kind of deflecting tool.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSSingle n : one joint of pipe.

Slips n : wedge-shaped pieces of metal with a gripping element used to suspend the drillstring in the rotary table.

Slug n : a heavy viscous quantity of mud which is pumped into the drillstring prior to pulling out. The slug will cause the level of fluid in the pipe to fall, thus eliminating the loss of mud on the rig floor when connections are broken.

Slurry (cement) n : a pumpable mixture of cement and water. Once in position the slurry hardens and provides an impermeable seal in the annulus and supports the casing.

Spear n : a fishing tool which engages the fish internally and is used to recover stuck pipe.

Specific gravity n : the ratio of the weight of a substance to the weight of the same volume of water.

S.P.M. abbr : Strokes Per Minute. Rate of reciprocation of a Mud Pump.

Spool n : a wellhead component which is used for suspending a string of casing. The spool also has side outlets for allowing access to the annulus between casing strings.


GLOSSARY OF TERMSSpud v : to commence drilling operations.

Squeeze cementing v : the process by which cement slurry is forced into place in order to carry out remedial work (e.g. shut off water producing zones, repair casing leaks).

Stab v : to guide the pin end of a pipe into the tool joint or coupling before making up the connection.

Stabbing board n : a temporary platform erected in the derrick 20'-40' above the drill floor. While running casing one man stands on this board to guide the joints into the string suspended on the rig floor.

Stabiliser n : a component placed in the BHA to control the deviation of the wellbore. One or more stabilisers may be used to achieve the intended well path.

Stage collar n : a tool made up in the casing string which is used in the second stage of a primary cement job. The collar has side ports which are opened by dropping a dart from surface. Cement can then be displaced from the casing into the annulus. Also called a “DV collar”. COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSStand n : three joints of pipe connected together, usually racked in the derrick.

Standpipe n : a heavy wall pipe attached to one of the legs of the derrick. It conducts high pressure mud from the pumps to the rotary hose.

Standpipe manifold n : a series of lines, gauges and valves used for routing mud from the pumps to the standpipe.

Steering tool n : surveying instrument used in conjunction with a mud motor to continuously monitor azimuth, inclination and toolface. These measurements are relayed to surface via conductor line, and shown on a rig floor display.

Stimulation n : a process undertaken to improve the productivity of a formation by fracturing or acidising.

Stripping v : movement of pipe through closed BOPs.

Stuck pipe n : drillpipe, collars, casing or tubing which cannot be pulled free from the wellbore.COMMITMENT TO ACADEMIC AND


GLOSSARY OF TERMSSub n : a short threaded piece of pipe used as a crossover between pipes of different thread or size. Subs may also have special uses (e.g. bent subs, lifting subs, kelly saver sub).

Subsea wellhead n : the equipment installed on the seabed for suspending casing strings when drilling from a floater.

Suction pit n : the mud pit from which mud is drawn into the mud pumps for circulating down the hole.

Surface casing n : a string of casing set in a wellbore to case off any fresh water sands at shallow depths. Surface casing is run below the conductor pipe to depth of 1000‘-4000' depending on particular requirements).

Surge pressures n : excess pressure exerted against the formation due to rapid downward movement of the drillstring when tripping.

Survey v : to measure the inclination and direction of the wellbore at a particular depth.

Survey interval n : the measured depth between survey stations.Survey station n : the point at which a survey is taken.


GLOSSARY OF TERMSSwabbing n : a temporary lowering of the hydrostatic head due to pulling pipe out of the hole.

Swivel n : a component which is suspended from the hook. It allows mud to flow from the rotary hose through the swivel to the kelly while the drillstring is rotating.

Syncline n : a trough-shaped, folded structure of stratified rock.

Target n : the objective defined by the geologist which the well must reach.

Target area n : a specified zone around the target which the well must intersect.

Target bearing n : the direction of the straight line passing through the target and the reference point on the rig. This is used as the reference direction for calculating vertical section.

T.D. abbr : Total Depth.

Telescopic joint n : a component installed at the top of the marine riser to accommodate vertical movement of the floating drilling rig.


GLOSSARY OF TERMSThread protectors n : a device made of metal or plastic which is screwed onto pipe threads to prevent damage during transport or movement around the rig.

Tight formation n : a formation which has low porosity and permeability.

Tongs n : the large wrenches used to connect and disconnect sections of pipe. The tongs have jaws which grip the pipe and torque is applied by pulling manually or mechanically using the cathead. Power tongs are pneumatically or hydraulically operated tools which spin the pipe.

Tool face n : the part of the deflection tool which determines the direction in which deflection will take place. When using a bent sub the tool face is defined by the scribe line.

Tool joint n : a heavy coupling device welded onto the ends of drill pipe. Tool joints have coarse tapered threads to withstand the strain of making and breaking connections and to provide a seal. They also have seating shoulders designed to suspend the weight of the drillstring when the slips are set. On the lower end the pin connection is stabbed into the box of the previous joint. Hardfacing is often applied in a band on the outside of the tool joint to resist abrasion.


GLOSSARY OF TERMSTool pusher n : an employee of the drilling contractor who is responsible for the drilling rig and the crew. Also called rig superintendent.

Torque n : the turning force which is applied to the drillstring causing it to rotate. Torque is usually measured in ft-lbs.

Tour n : (pronounced “tower”) an 8 hour or 12 hour shift worked by the drilling crew.

Trajectory n : the path of the wellbore.

Trap n : the geological structure in which petroleum reserves may have accumulated.

Travelling block n : an arrangement of pulleys through which the drilling line is reeved, thereby allowing the drillstring to be raised or lowered.

Trip v : to pull the drillstring out of the hole, or to run in back in.

Trip gas n : a volume of gas (usually a small amount) which enters the wellbore while making a trip.


GLOSSARY OF TERMSTriplex pump n : a reciprocating mud pump with three pistons which are single acting.

True North n : the direction of a line joining any point with the geographical North pole. Corresponds with an azimuth of 000°.

Tugger line n : a small diameter cable wound on an air operated winch which can be used to pick up small loads around the rig floor.

Turbodrill n : a drilling tool located just above the bit which rotates the bit without turning the drillstring. The tool consists of a series of steel bladed rotors which are turned by the flow of drilling fluid through the tool.

T.V.D. abbr : True Vertical Depth. One of the co-ordinates used to plot the wellpath on the vertical plane.

Twist off v : to sever the drillstring due to excessive force being applied at the rotary table.

Underground blow out v : this situation arises when lost circulation and a kick occur simultaneously. Formation fluids are therefore able to enter the wellbore at the active zone and escape through an upper zone which has been broken down. (Sometimes called an “internal blow out").


GLOSSARY OF TERMSUnder ream v : to enlarge the size of the wellbore below casing.

Upset n : the section at the ends of tubular goods where the OD is increased to give better strength.

Valve n : a device used to control or shut off completely, the rate of fluid flow along a pipe. Various types of valve are used in drilling equipment.

V door n : an opening in one side of the derrick opposite the drawworks. This opening is used to bring in pipe and other equipment onto the drill floor.

Vertical section n : the horizontal distance obtained by projecting the closure onto the target bearing. This is one of the co-ordinates used in plotting the wellpath on the vertical plane of the proposed wellpath.

Viscometer n : a device used to measure the viscosity of the drilling fluid.

Viscosity n : a measure of a fluid’s resistance to flow. The resistance is due to internal friction from the combined effects of cohesion and adhesion.

Vug n : geological term for a cavity in a rock (especially limestone).


GLOSSARY OF TERMSWashout n :1. Wellbore enlargement due to solvent or erosion action of the drilling fluid.2. A leak in the drillstring due to abrasive mud or mechanical failure.

Water back v : to reduce the weight and solids content of the mud by adding water. This is usually carried out prior to mud treatment.

Water based mud n : a drilling fluid in which the continuous phase is water. Various additives will also be present.

Water injector n : a well which is used to pump water into the reservoir to promote better recovery of hydrocarbons.

Wear bushing n : a piece of equipment installed in the wellhead which is designed to act as a bit guide, casing seat protector and prevent damage to the casing hanger already in place. The wear bushing must be removed before the next casing string is run.

Weight indicator n : an instrument mounted on the driller’s console which gives both the weight on bit and the hook load.

Wellbore n : a general term to describe both cased hole and open hole.


GLOSSARY OF TERMSWellhead n : the equipment installed at the top of the wellbore from which casing and tubing strings are suspended.

Whipstock n : a long wedge-shaped pipe that uses an inclined plane to cause the bit to deflect away from its original position.Wildcat n : an exploration well drilled in an area where no oil or gas has been produced.

Wiper trip n : the process by which the drill bit is pulled back inside the previous casing shoe and then run back to bottom. This may be necessary to improve the condition of the wellbore (e.g. smooth out any irregularities or dog legs which could cause stuck pipe later).

Wireline n : small diameter steel wire which is used to run certain tools down into the wellbore. Also called slick line. Logging tools and perforating guns require conductor line.

W.O.B. abbr : Weight On Bit. The load put on the bit by the drill collars to improve penetration rate.

W.O.C. abbr : Waiting On Cement. The time during which drilling operations are suspended to allow the cement to harden before drilling out the casing shoe.


GLOSSARY OF TERMSW.O.W. abbr : Waiting On Weather. The time during which drilling operations must stop due to rough weather conditions. Usually applied to offshore drilling.

Workover n : the carrying out of maintenance and remedial work on the wellbore to increase production.


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BASIC DRILLING TECHNOLOGY

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