Rig inspection

Presented by:

Sigve Hamilton Aspelund

Module (01) Drilling & Work-over Operations

1.1 Drilling Operations

Exploration and production licences

• Government invite companies to apply for exploration and production licences on the continental shelf.

• Exploration licences may be awarded any time.• Production licences are awarded at specific

discrete intervals known as licensing rounds.

Exploration, development and abandonment

• Before drilling an exploration well an oil company will have to obtain a production licence.

• Prior to applying for a production licence– Exploration geologists• Scouting exercise –Analyse seismic data–Analyse regional geology–Analyse well tests in the vicinity of the

prospect they are considering

• Explorationists – Consider exploration and development costs• Oil price and tax regimes – Establish if reservoir is worth developing

• If prospect is considered worth exploring– The company will try to aquire a production

licence• Explore the field

• The licence will allow company to drill exploration wells in the area of interest.

• Before exploration wells are drilled– Licencee may shoot extra seismic lines in a

closer grid pattern• Detailed information about the prospect –Assist in definition of optimum drilling

target• Despite improvements in seismic techniques the

only way of confirmining the presence of hydrocarbons is to drill an exploration well.

• Drilling is very expensive– If hydrocarbons are not found there is no return

on the investment, although valuable geological information may be obtained.

– With only limited information available a large risk is involved.

• Having decided to go ahead and drill an exploration well proposal is prepared.

• The objectives of this well will be:– 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 flud samples.

• The life of an oil or gas field can be sub-divided into the following phases:– Exploration– Appraisal– Development– Maintenance– Abandonment

• The length of the exploration phase will depend on the success or otherwise of the exploration wells.

• There may be a single exploration well or many exploration wells drilled on a prospect.

• If an economically attractive discovery is made on the prospect then the company enters the appraisal phase of the life of the field.

• During this phase more seismic lines may be shot and more wells will be drilled to establish the lateral and vertical extent of (to delineate) the reservoir.

• These appraisal wells will yield further information, on the basis of which future plans will be based.

• The information provided by the appraisal wells will be combined with all of the previously collected data and engineers will investigate the most cost effective manner in which to develop the field.

• If the prospect is economical attractive a field development plan wil be submitted to secrectary state of energy.

• If approval for the development is received then the company will commence drilling development wells and constructing the production facilities according to the development plan.

• Once the field is on-stream the companies commitment continues in the form of maintenance of both the wells and the production facilities.

• After many years of production it may be found that the field is yielding more or possibly less hydrocarbons than initially anticipated at the development planning stage and the company may undertake further appraisal and subsequent drilling in the field.

• At some point in the life of the field the costs of production will exceed the revenue from the field and the field will be abandoned.

• All of the wells will be plugged and the surface facilities will have to be removed in a safe and environmentally acceptable fashion.

1.2 Vertical / Horizontal Wells

Directional drilling: ApplicationsThere are many reasons for drilling a non-vertical (deviated) well

Multi-well plattform drilling

• Multi-well plattform drilling is widely employed in the North Sea.

• The deviated wells are designed to intercept a reservoir over a wide areal extent.

• Many oilfields (both onshore and offshore) would not be economically feasible if not for this technique.

Fault drilling

• If a well is drilled across a fault the casing can be damaged by fault slippage.

• The potential for damaging the casing can be minimised by drilling parallel to a fault and then changing the direction of the well to cross the fault into the target.

Inaccessible locations

• Vertical access to a producing zone is often obstructed by some obstacle at surface (e.g. river estuary, mountain range, city).

• In this case the well may be directionally drilled into the target from a rig site some distance away from the point vertically above the required point of entry into the reservoir.

Sidetracking and straigthening

• In this fact quite difficult to control the angle of inclination of any well (vertical or deviated) and it may be neccessary in the event of the drillpipe becoming stuck in the hole to simply drill around the stuckpipe (or fish), or plug back the well to drill to an alternative target.

Salt dome drilling

• Salt domes (called Diapirs) often form hydrocarbon traps in what were overlying reservoir rocks.

• In this form of trap the reservoir is located directly beneath the flank of the salt dome.

• To avoid potential drilling problems in the salt (e.g. severe washouts, moving salt, high pressure blocks of dolomite) a directional well can be used to drill alongside the Diapir (not vertically down through it) and then at an angle below the salt to reach the reservoir.

Relief wells

• If a blow-out occurs and the rig is damaged, or destroyed, it may be possible to kill the «wild» well.

• The «wild» well is killed by circulating high density fluid down the relief well, into and up the wild well.

Depth reference and geographical reference systems

• The trajectory of a deviated well must be carefully planned so that the most effecient 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.

• 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 the Northerly

direction– The distance traversed from the wellhead in the Easterly direction

• The depth of a particular point in the well path 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.

Depth reference systems

• 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 well is abandoned.

• Hence, since the only permanent datum is the MSL (the rig will be removed and the wellhead may be removed and 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 know until the drilling rig is in place.

• In most drilling operation 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, for the driller for instance, to measure depths relative to this point.

• The elevation of the RTE is also refered 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 depths measruement.

• 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.

• Whereas the TVD is the vertical depth of a point from the surface reference point, measured along the trajectory of the borehole.

• Whereas 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 techniques used to survey the well will be discussed in the chapther on wellbore surveying.

Parameters defining the well path

• Kick-off point• Buildup and drop off rate• Tangent angle of the well

The kickoff point (KOP)

• The kickoff point is the along hole measured depth at which a change in inclination of the well is initiated and the well is orientation in a particular direction (in terms of North, South, East and West).

• In general the most distant targets have the shallowest KOPs in order to reduce the inclination of the tangent section of the well.

• It is generally easier to kick off a well the shallow formations than in deep formations.

• The kick-off should also be initiated in formations which are stable and not likely to cause drilling problems, such as unconsolidated clays.

Buildup rate (BUR) and Drop Off Rate (DOR)• The build up rate and drop off rate (in degrees of

inclination) are the rates at which the well deviates from the vertical (usually measured in degrees per 100 ft drilled).

• The build-up rate is chosen on the basis of drilling experience in the location and the tools available, but rates between 1 degree and 3 degree per 100ft of hole drilled are most common in conventional wells.

• Since the build up and the drop off rates are constant, these sections of the well, by definition, form the arc of a circle.

• Build up rates in excess of 3 degrees per 100 ft are termed doglegs when drilling conventional drilling equipment.

• The build up rates is often termed the dogleg severity.

Tangent (or Drift) angle

• The tangent angle (or drift angle) is the inclination (in degrees from the vertical) of the long straight section of the well.

• This section of the well is termed the tangent section because it forms a tangent to the arc formed by the build up section of the well.

• The tangent angle will generally be between 10 and 60 degrees since it is difficult to control the trajectory of the will at angles below 10 degrees and it is difficult to run wireline tools into wells at angles of greater than 60 degrees.

Defining the points on the wellpath

• Having fixed 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)

• Since the driller will only be able to determine the along hole depth of the well the following information will be required:

• AHD of the KOP (same as TVD of KOP)• Build up 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 • ADH of the target• These depths and distances can be defined by a simple

geometrical analysis of the well trajectory.

Radius of the build up section

• Once the tangent angle is know the other points on the well path can be calculated as follows:

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.

• An arc of this radius can be drawn to define the build-up profile.

• A tangent from T can 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 distaces BX, XE, BE, 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 is measuring TEY with a protractor may mean that the tangent trajectory is imprecise and that the target may be missed by the driller.

Geometrical calculation technique

Standard build up chart

• A simpler approach to profile planning is to use charts similar to those given in Appendix 1. The charts are drawn up for spesific build-up rates and give the maximum drift angle for a given well.

• Select the relevant chart (2 degrees/100’). Locate the TVD=(10000-2000)=8000’ on the left hand scale, and the horizontal deviation of 3000’ on the horizontal deviation scale.

• Where the lines intersect gives a drift angel of 22 degrees.

• From the table at the top right corner of the chart the measured depth, vertical depth (PE) and deviation (XE) can be read at corresponding angle of 22 degrees

• These distances are very close to those calculated earlier. However, interpolation is sometimes neccessary, which leads to errors.

• For accurate well planning, computer programmes are frequently used.

• The programmes have wider applications (e.g. calculating distance between proposed well path and existing wells).

• Large scale computer plots are often used in planning offshore wells from fixed platforms.

• These are used on the rig to monitor the actual path of the well by plotting survey results whilst it is being drilled.

Considerations when planning the directional well path

• Whan planning a directional well a number of technical constraints and issues will have to be considered. These will include the:

• Target location• Target size and shape• Surface location (rig location)• Subsurface obstacles (adjacent wells, faults etc.)

• In conjunction with the above constraints the following factors must be considered in the geometrical design of the well:

• Casing and mud programmes• Geological section

Target location

• The location of the target is chosen by the geologists and/or the reservoir engineers.

• The target location will be specified in terms of a geographical co-ordinate system such as longitude and latitude or a grid co-ordinate system such as the UTM system.

• The grid reference system, in which the co-ordinates are expressed in terms of feet (or meters) north and east of a loval or national reference point, is particularly useful when planning the directional well path, since the displacement of all points on the wellpath can be easily calculated.

• The depth of the target is generally expressed by the geologist in terms of true vertical depth, TVD below a national reference datum such as Mean Sea Level.

• The difference between this national reference point and the drilling reference datum (such as the Rotary table) must be computed so that the driller can translate the computed TVD of the borehole below the rotary table elevation, into depth below mean sea level, and therefore proximity to the target.

Specification of Target, Size and Shape

• The size and shape of the target is also chosen by geologists and/or reservoir engineers.

• The target area will be dictaced by the shape of the geologial structure and the precense of geological features, such as faults.

• In general the smaller the target area, the more directional control that is required, and so the more expensive the well will be.

Rig location

• The position of the rig must be considered in relation to the target and the geological formations to be drilled (e.g. salt domes, faults.).

• If possible the rig will be placed directly above the target location.

• When developing a field from a fixed platform the location of the platform will be optimised so that the directionally drilled wells can reach the full extent of the reservoir.

Location of adjacent wells

• Drilling close to an existing well can be very dangerous, particularily if the existing well is on production. This is especially true just below the seabed on offshore platforms, where the wells are very closely spaced.

• The proposed wellpath must be designed so that the wells are very closely spaced.

• The proposed wellpath must be designed so that it avoids all other wells in the vicinity.

• It is essential that the possible errors in determination of the existing ant proposed wells are considered when the trajectory of the new well is designed.

Geological section

• The equpment and techniques involved in controlling the deviated wellpath are not suited to certain types of formation.

• It is for example difficult to initiate the deviated portion of the well (kickoff the well) in unconsolidated mudstone.

• The engineer may therefore decide to drill vertically through the problematic formation and commence the deviated part of the well once the well has entered the next most suitable formation type.

• The vertical depth of the formation tops will be provided by the geologists.

Casing and mud programmes• The trajectory of the well will be designed so that

the most difficult parts of the well are drilled through competent formations, minimising problems whilst drilling the well.

• It is very common to initiate the kick-off just below the surface casing and possibly to change out to oil-based mud when drilling the build-up section.

• In highly deviated wells the build up section of the well may also be used in the long, tangent sections of the well.

• The trajectory of the well will therefore be designed so that these operations correspond to the casing setting depths which have been selected for many other reasons.

• This is an iterative process taking into account all of the considerations when designing the well.

Deflection tools

• Badger bit (Jet deflection)

Whipstocks

Rebel tools

The advantages of this tool are that it:• Makes gradual change in direction• Allows normal rotary drilling to continue• Cheaper than using downhole motors.

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Bent sub and positive displacement motor

• Accurate control over direction• Smoother deviation-less risk of dog-legs• Can be used to build or drip angle (depending on

orientation of bend sub)• PDMs can be designed to operate in high solids

mud or with LCM

Steerable drilling systems

• Componentsa) Drill bitb) Mud motorc) Navigation Subd) Navigation Stabilizerse) Survey System

Drill bit

• Steerable systems are compatible with either tricone or PDC type bits.

• In most cases a PDC bit will be used since this eliminates frequent trips to change the bit.

PDM

• The motor section of the system causes the bit to rotate when mud is circulated throug the string. This makes oriented drilling possible.

• The motors may also have the navitation sub and a bearing housing stabilizer attached to complete the navigation motor configuration.

Navigation Sub

• The navigation sub converts a standard Mud motor into a steerable motor by tilting the bit at predermined angle.

• The bit tilt angle and the location of the sub at a minimal distance from the bit allows both oriented and rotary drilling without excessive loads and wear on the bit and motor.

• The design of the navigation sub ensures that the deflection forces are primarly applied to the bit face (rather than the gauge) thereby maximizing cutting efficiency.

Navigation stabilisers

• Two specially designed stabilizers are required for the operation of the system and influence the directional performance of a steerable assebly.

• The motor stabilizer or Upper Bearing Housing Stabiliser, UBHS is an integral part of the navigation motor, and is slightly undergauge.

• The upper stabilizer, which defines the third tangency point, is also undergauge.

• The upper stabilizer, which defines the third tangency point, is also undergauge and is similar to a string stabilizer.

• The size and spacing of the stabilizer also can be varied to fine-tune assembly reactions in both oriented and rotary modes.

Survey system

• A real time downhole survey system is required to provide continous directional information.

• A measurement while drilling, MWD system is typically used for this purpose.

• An MWD tool will produce fast, accurate data for the hole inclination, azimuth, and the navigation sub toolface orientation.

• In some cases, a wireline steering tool may be used for this purpose.

Dogleg produced by a steerable system

• When oriented drilling, the theoretical geometric dogleg severity or TGDS produced by the system is defined by three points on a drilled arc. The three points required to establish the arc are:

• The bit• The PDM stabilizer or Upper Bearing Housing Stabilizer• The first stabilizer above the mud motor (upper stabiliser).The radius of the arc is further determined by the tilt of the navigation sub. The following basic relationship is produced by mathematical derivation.

Directional Bottom Hole Assemblies (BHA)

• Once the hole has been kicked off in the correct direction, using a bent sub or other deflection tool, a conventional rotary drilling assembly can be run back in hole.

• This is not of course necessary with a steerable assembly.

• The BHA of the conventional assembly may be designed to build, drop or hold angle.

• In rotary drilling a BHA cannot normally be expected to control lateral movement.

Pack Hole Assembly

• This type of configuration is a configuration is a very stiff assembly, consisting of drill collars and stabilizers positioned to reduce bending and keep the bit on course.

• This type of assebly is often used in the tangential section of a directional hole.

• In practice it is very difficult to find a tangent assembly which will maintain tangent angle and direction.

• Short drill collars are sometimes used, and also reamers or stabilizers run in tandem.

Pendulum assembly

• Using the unsupported weight of drill collars to force the bit against low side of the hole.

• The resulting decrease or drop off in angle depends on WOB, RPM, stabilization and the distance between the bit and the first reamer.

• The basic drop of assembly is:Bit-Monel DC-reamer-DC-stab-DC-stab-90’-DC-stab

To increase the tendency to drop angle:• Apply less WOB (lower penetration rate)• Apply more RPM and pump pressure in soft

formations where jetting and reaming down is possible

• Use bigger size Monel DC below the reamer, small DCs above

To increase the build:• Add more WOB• Use smaller size monel (increase buckling effect)• Reduce RPM and pump rates in soft formations

Positive displacement motors (PDM)

• A PDM is a downhole mud motor that uses the reverse Moineau pump principle to drive the bit without rotating the entire drillstring.

• It can be powered using drilling fluid, air or gas.

Turbodrills

• This is another type of mud motor which turns the bit without rotating the drillstring.

• Unlike a PDM a turbodrill can only be powered by a liquid drilling fluid.

• The turbodrill motor consist of bladed rotors and stators mounted at rignt angles to fluid flow.

• The rotors are attached to the drive shaft, while the stators are attached to the outer case.

• Each rotor-stator pair is called a stage; a typical turbodrill may have 75-250 stages.

• The stators direct the flow of drilling fluid onto the rotor blades, forcing the drive shaft to rotate clockwice.

• Turbodrills are also used in straight-hole drilling as an alternative to rotary drilling.

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Advantages:a) String and casing wear reducedb) Lower torque applied to stringc) Higher RPM at bit (better penetration rates)

Turbodrills are sometimes used with PDC (polycrystalline diamond compact) bits in North Sea wells to reduce costs in long bit runs.

Solutions to Exercises• Ex 1: Designing a deviated well

1.3 Extended Reach

• An extended-reach well is one in which the ratio of the measured depth (MD) vs. the true vertical depth (TVD) is at least 2:0.

Overview

• Extended reach wells can be extremely long (measured depth) and relatively shallow vertically, as well as relatively short and very shallow vertically - and everything in between.

• The extremely long reach wells are typically drilled to distant reservoirs to reduce the infrastructure and operational footprint that would otherwise be required to access the resource.

• The relatively short reach wells may be drilled to provide needed reservoir contact length in very shallow reservoirs.

• The current world record (circa 2013) for the longest measured depth ERD well is the Chayvo Z-42 well (Exxon Neftegas Limited, Sakhalin Island, Russia) with a measured depth of 41,667 ft. and horizontal departure of 38,514 ft.

• Relatively short wells with MD/TVD ratio’s approaching 12 have reportedly been drilled in Western Canada in very shallow bitumen sands that are too deep to develop using surface mining techniques.

Horizontal departure limits

• Other notable extended reach achievements in pushing the horizontal departure distance from 30,000 ft. to 40,000 ft. (circa 2013) include:

• 25 wells drilled by Exxon Neftegas Limited on the Sakhalin-1 project, Sakhalin Island Russia, (MD/TVD = 3.9 to 6.9)

• 1 well drilled by Maersk Oil Qatar in the Al Shaheen field, Qatar (MD/TVD = 11.1)

• 2 wells drilled by BP on the Wytch Farms project, England (MD/TVD = 6.9 to 6.6)

• 1 well drilled by Total in Argentina, Cullen Norte #1 (MD/TVD = 6.7)

• 1 well drilled by ExxonMobil in the Santa Ynez Unit, offshore California, USA (MD/TVD = 5.36)

Benefits of extended-reach wells

• Extended-reach wells are expensive and technically challenging.

• However, they can add value to drilling operations by making it possible to reduce costly subsea equipment and pipelines, by using satellite field development, by developing near-shore fields from onshore, and by reducing the environmental impact by developing fields from pads.

Types of directional wells

• The major types of directional wells are:• Horizontal wells• Multilateral wells• Extended reach wells

Fig. 1—Illustration of the visualization of a well path.

Horizontal wells• Horizontal wells are high-angle wells (with an

inclination of generally greater than 85°) drilled to enhance reservoir performance by placing a long wellbore section within the reservoir.

• Horizontal well Vs extended-reach well• Horizontal Well contrasts with an 

extended-reach well, which is a high-angle directional well drilled to intersect a target point.

• Growth of horizontal drilling• There was relatively little horizontal drilling

activity before 1985. • The Austin Chalk play is responsible for the boom

in horizontal drilling activity in the U.S. • Now, horizontal drilling is considered an effective

reservoir-development tool.

Advantages of horizontal wells

• Reduced water and gas coning because of reduced drawdown in the reservoir for a given production rate, thereby reducing the remedial work required in the future

• Increased production rate because of the greater wellbore length exposed to the pay zone

• Reduced pressure drop around the wellbore• Lower fluid velocities around the wellbore• A general reduction in sand production from a

combination of Items 3 and 4• Larger and more efficient drainage pattern leading to

increased overall reserves recovery

Characteristics of horizontal wells

• Horizontal wells are normally characterized by their buildup rates and are broadly classified into three groups that dictate the drilling and completion practices required, as shown in table below

Build rate• The “build rate” is the positive change in

inclination over a normalized length (e.g., 3°/100 ft.)

• A negative change in inclination would be the “drop rate.” A long-radius horizontal well is characterized by build rates of 2 to 6°/100 ft, which result in a radius of 3,000 to 1,000 ft.

• This profile is drilled with conventional directional-drilling tools, and lateral sections of up to 8,000 ft have been drilled.

• This profile is well suited for applications in which a long, horizontal displacement is required to reach the target entry point.

• The use of rotary-steerable systems (RSSs) may be required to drill an extra-long lateral section because slide drilling may not be possible with the conventional steerable motors.

Medium radius horizontal wells• Medium-radius horizontal wells have build rates of 6 to

35°/100 ft, radii of 1,000 to 160 ft, and lateral sections of up to 8,000 ft.

• These wells are drilled with specialized downhole mud motors and conventional drillstring components.

• Double-bend assemblies are designed to build angles at rates up to 35°/100 ft.

• The lateral section is often drilled with conventional steerable motor assemblies.

• This profile is common for land-based applications and for re-entry horizontal drilling.

• In practical terms, a well is classified as medium radius if the bottomhole assembly (BHA) cannot be rotated through the build section at all times.

• At the upper end of the medium radius, drilling the maximum build rate is limited by the bending and torsional limits of American Petroleum Institute (API) tubulars.

• Smaller holes with more-flexible tubulars have a higher allowable maximum dogleg severity (DLS).

Short radius horizontal wells

• Short-radius horizontal wells have build rates of 5 to 10°/3 ft (1.5 to 3°/ft), which equates to radii of 40 to 20 ft.

• The length of the lateral section varies between 200 and 900 ft.

• Short-radius wells are drilled with specialized drilling tools and techniques.

• This profile is most commonly drilled as a re-entry from any existing well.

Short radius horizontal wells

• Short-radius horizontal wells have build rates of 5 to 10°/3 ft (1.5 to 3°/ft), which equates to radii of 40 to 20 ft.

• The length of the lateral section varies between 200 and 900 ft.

• Short-radius wells are drilled with specialized drilling tools and techniques.

• This profile is most commonly drilled as a re-entry from any existing well.

1.4 Deviated Holes

Deviated hole

• A wellbore that is not vertical. • The term usually indicates a wellbore

intentionally drilled away from vertical.

Hole deviation

• Hole deviation is the unintentional departure of the drill bit from a preselected borehole trajectory.

• Whether it involves drilling a straight or curved-hole section, the tendency of the bit to walk away from the desired path can lead to drilling problems such as higher drilling costs and also lease-boundary legal problems figure below provides examples of hole deviations.

Causes of hole deviation

• It is not exactly known what causes a drill bit to deviate from its intended path.

• It is, however, generally agreed that one or a combination of several of the following factors may be responsible for the deviation:

• Heterogeneous nature of formation and dip angle• Drillstring characteristics, specifically the bottomhole

assembly (BHA) makeup• Stabilizers (location, number, and clearances)• Applied weight on bit (WOB)• Hole-inclination angle from vertical• Drill-bit type and its basic mechanical design• Hydraulics at the bit• Improper hole cleaning

• It is known that some resultant force acting on a drill bit causes hole deviation to occur. The mechanics of this resultant force is complex and is governed mainly by the mechanics of the BHA, rock/bit interaction, bit operating conditions, and, to some lesser extent, by the drilling-fluid hydraulics.

• The forces imparted to the drill bit because of the BHA are directly related to the makeup of the BHA, i.e.:

• Stiffness• Stabilizers• Reamers

• The BHA is a flexible, elastic structural member that can buckle under compressive loads.

• The buckled shape of a given designed BHA depends on the amount of applied WOB.

• The significance of the BHA buckling is that it causes the axis of the drill bit to misalign with the axis of the intended hole path, thus causing the deviation.

• Pipe stiffness and length and the number of stabilizers (their location and clearances from the wall of the wellbore) are two major parameters that govern BHA buckling behavior.

• Actions that can minimize the buckling tendency of the BHA include reducing WOB and using stabilizers with outside diameters that are almost in gauge with the wall of the borehole.

The contribution of the rock/bit interaction to bit deviating forces is governed by:Rock properties• Cohesive strength• Bedding or dip angle• Internal friction angleDrill-bit design features• Tooth angle• Bit size• Bit type• Bit offset in case of roller-cone bits• Teeth location and number• Bit profile• Bit hydraulic featuresDrilling parameters• Tooth penetration into the rock and its

cutting mechanism

• The mechanics of rock/bit interaction is a very complex subject and is the least understood in regard to hole-deviation problems.

• Fortunately, the advent of downhole measurement-while-drilling tools that allow monitoring the advance of the drill bit along the desired path makes our lack of understanding of the mechanics of hole deviation more acceptable.

1.5 Under-Balance Drilling Operations

Underbalanced drilling

• Underbalanced drilling, or UBD, is a procedure used to drill oil and gas wells where the pressure in the wellbore is kept lower than the fluid pressure in the formation being drilled.

• As the well is being drilled, formation fluid flows into the wellbore and up to the surface. This is the opposite of the usual situation, where the wellbore is kept at a pressure above the formation to prevent formation fluid entering the well. In such a conventional "overbalanced" well, the invasion of fluid is considered a kick, and if the well is not shut-in it can lead to a blowout, a dangerous situation.

• In underbalanced drilling, however, there is a "rotating head" at the surface - essentially a seal that diverts produced fluids to a separator while allowing the drill string to continue rotating.

• If the formation pressure is relatively high, using a lower density mud will reduce the well bore pressure below the pore pressure of the formation. Sometimes an inert gas is injected into the drilling mud to reduce its equivalent density and hence its hydrostatic pressure throughout the well depth.

• This gas is commonly nitrogen, as it is non-combustible and readily available, but air, reduced oxygen air, processed flue gas and natural gas have all been used in this fashion.

• Coiled tubing drilling (CTD) allows for continuous drilling and pumping and therefore can underbalanced drilling can be utilized which can increase the rate of penetration (ROP).

Kinds of Underbalanced Drilling

• There are several kinds of underbalanced drilling. The most common are listed below.

• Dry Air. This is also known as dusting. Here air compressors combined with a booster (which takes the head from the compressors and increases the pressure of the air, but does not increase the volume of air going down hole) are used and the only fluid injected into the well is a small amount of oil to reduce corrosion.

• Mist. A small amount of foaming agent (soap) is added into the flow of air. Fine particles of water and foam in an atmosphere of air bring cuttings back to the surface.

• Foam. A larger amount of foaming agent is added into the flow. Bubbles and slugs of bubbles in an atmosphere of mist bring cuttings back to the surface.

• Stable foam. An even larger amount of foaming agent is added into the flow. This is the consistency of a shaving cream.

• Airlift. Slugs and bubbles of air in a matrix of water, soap can or can not be added into the fluid flow of air.

• Aerated Mud. Air or another gas is injected into the flow of drilling mud. Degassing units are required to remove air before it can be recirculated.

Advantages

• Underbalanced wells have several advantages over conventional drilling including:

• Eliminated formation damage. In a conventional well, drilling mud is forced into the formation in a process called invasion, which frequently causes formation damage - a decrease in the ability of the formation to transmit oil into the wellbore at a given pressure and flow rate. It may or may not be repairable. In underbalanced drilling, if the underbalanced state is maintained until the well becomes productive, invasion does not occur and formation damage can be completely avoided.

• Increased Rate of Penetration (ROP). With less pressure at the bottom of the wellbore, it is easier for the drill bit to cut and remove rock.

• Reduction of lost circulation. Lost circulation is when drilling mud flows into the formation uncontrollably. Large amounts of mud can be lost before a proper mud cake forms, or the loss can continue indefinitely. If the well is drilled underbalanced, mud will not enter the formation and the problem can be avoided.

• Differential sticking is eliminated. Differential sticking is when the drill pipe is pressed against the wellbore wall so that part of its circumference will see only reservoir pressure, while the rest will continue to be pushed by wellbore pressure. As a result the pipe becomes stuck to the wall, and can require thousands of pounds of force to remove, which may prove impossible. Because the reservoir pressure is greater than the wellbore pressure in UBD, the pipe is pushed away from the walls, eliminating differential sticking.

• Formation damage Some rock formation have a reactive tendency to water. When drillmud is used the water in the drill mud reacts with the formation (mostly clay) and inheriently causes a formation damage (reduction in permeability and porosity) Use of underbalanced drilling can prevent it

Disadvantages

• Underbalanced drilling is usually more expensive than conventional drilling (when drilling a deviated well which requires directional drilling tools), and has safety issues of its own. Technically the well is always in a blowout condition unless a heavier fluid is displaced into the well.

• Air drilling requires a faster up hole volume as the cuttings will fall faster down the annulus when the compressors are taken off the hole compared to having a higher viscosity fluid in the hole.

• Because air is compressible mud pulse telemetry measurement while drilling (MWD) tools which require an incompressible fluid can not work. Common technologies used to eliminate this problem are either electromagnetic MWD tools or wireline MWD tools.

• Downhole mechanics are usually more violent also because the volume of fluid going through a downhole motor or downhole hammer is greater than an equivalent fluid when drilling balanced or over balanced because of the need of higher up hole velocities. Corrosion is also a problem, but can be largely avoided using a coating oil or rust inhibitors.

1.6 Rig Types/ Classifications/ Functions

Jack up

Retractable legs that can be lowered to the sea bed. The legs support the drilling rig and keep the rig in position.

Jack up

Unaffected by the weather during the drilling phaseThe safety valve is located on deckIt does not need anchoring systemIt does not need heave compensator 

(permanent installation in the drilling phase)It has removable drill towerDepth limit is 150 metersIt is unstable under the relocationIt depends on the tug for moving

Semi submersible

Portable device that consists of a deck placed on columns attached to two or more pontoons. During operation tubes are filled with water and lowered beneath the sea surface. 

Semi submersible

• The vessel normally kept in position by anchors, but may also have dynamic positioning equipment (DP). 

• Usually have their own propulsion machinery (max. depth approx.  600 to 800 meters). 

• The most common type is the "semi-submersible drilling rig".

Drilling ship

• In very deep water (2300m) drill ships are used for drilling the well.

• A drillship is easy to move and is therefore well suited for drilling in deep waters, since it is well suited for dynamic positioning. 

• It requires relatively  little force to remain in position.

Condeep platform

Condeep platform is the denomination of a series of oil platforms that were developed in Norway to drill for oil and gas in the North Sea. The name comes from the English“concrete deep water structure", or deep  structure of concrete.

The platforms rest on thick concrete tanks that are on the ocean floor and acts as an oil stock. From these sticks it as one, three or four slender hollow columns, which is about 30 feet above the surface.

Condeep platform

It was Stavanger company Norwegian Contractors who developed the concept of Condeep platforms in 1973, after the success of the concrete tank at the Ekofisk field.Condeep platforms are not produced anymore. The large concrete platforms are out competed by new, cheaper floating rigs and remote-controlled underwater installations.

 Jacket platform

The most widely used platform in the North Seabearing structure is built as framed in steelPlatform are poles fixed to the bottomThe construction is susceptible to corrosionHas no storage tank, but must be associated pipeline network.

Tension leg platform

• A tension leg platform is a floating and vertically anchored platform or buoy which is normally used for offshore production of oil or natural gas, and is especially suitable for water depths exceeding 300 meters. We usually use rods or chains to keep the platform in place.

Tension leg platform

• Affordable solution• Quick to install• Can be equipped entirely by countries• Can be used on very deep• Can be moved when a field is empty• Because of movement of water required

compensation equipment

Well head plattform

• Can be an alternative to production facilities on the seabed, especially where water depth is small, as in the southern part of the north sea. The wellhead platform is an unmanned small platform, which we can remotely control from a “mother platform".Valve tree is dry.

Module (02) Wellhead & Downhole Equipment

2.1 Well Types

• Wildcat wells are those drilled outside of and not in the vicinity of known oil or gas fields.

• Exploration wells are drilled purely for exploratory (information gathering) purposes in a new area.

• Appraisal wells are used to assess characteristics (such as flow rate) of a proven hydrocarbon accumulation.

• Production wells are drilled primarily for producing oil or gas, once the producing structure and characteristics are determined.

• Abandoned well are wells permanently plugged in the drilling phase for technical reasons.

At a producing well site, active wells may be further categorised as:• Oil producers producing predominantly liquid hydrocarbons, but

mostly with some associated gas.• Gas producers producing almost entirely gaseous hydrocarbons.• Water injectors injecting water into the formation to maintain 

reservoir pressure, or simply to dispose of water produced with the hydrocarbons because even after treatment, it would be too oily and too saline to be considered clean for dumping overboard offshore, let alone into a fresh water resource in the case of onshore wells.

• Water injection into the producing zone frequently has an element of reservoir management; however, often produced water disposal is into shallower zones safely beneath any fresh water zones.

• Aquifer producers intentionally producing water for re-injection to manage pressure.

• If possible this water will come from the reservoir itself.

• Using aquifer produced water rather than water from other sources is to preclude chemical incompatibility that might lead to reservoir-plugging precipitates.

• These wells will generally be needed only if produced water from the oil or gas producers is insufficient for reservoir management purposes.

• Gas injectors injecting gas into the reservoir often as a means of disposal or sequestering for later production, but also to maintain reservoir pressure.

Lahee classification

• New Field Wildcat (NFW) – far from other producing fields and on a structure that has not previously produced.

• New Pool Wildcat (NPW) – new pools on already producing structure.

• Deeper Pool Test (DPT) – on already producing structure and pool, but on a deeper pay zone.

• Shallower Pool Test (SPT) – on already producing structure and pool, but on a shallower pay zone.

• Outpost (OUT) – usually two or more locations from nearest productive area.

• Development Well (DEV) – can be on the extension of a pay zone, or between existing wells (Infill).

2.2 Well Casing System

• Picture above: Compared with a conventional well (left), drilling with casing underbalanced (right) allowed a liner to be eliminated by drilling in the 5 ½-in. liner and the 3 ½-in.-by-2 7/8-in. production casing.

• The new well plan also reduced the number of drilling days to 28 on the first well, compared with a typical 58 on conventional wells.

Casing

• Casing is the tubular structure that is placed in the drilled well to maintain the well opening.

• Along with grout, the casing also confines the ground water to its zone underground and prevents contaminants from mixing with the water.

• Some states or local governing agencies have laws that require minimum lengths for casing.

• The most common materials for well casing are carbon steel, plastic (most commonly, but not exclusively, PVC), and stainless steel.

• Different geologic formations dictate what type of casing can be used.

• For example, parts of the country where hard rock lies underground are known strictly as “steel states.”

• Residents in some areas have a choice between steel and PVC, both of which have advantages.

• PVC is lightweight, resistant to corrosion, and relatively easy for contractors to install. However, it is not as strong and not as resistant to heat as steel.

• Steel, though, is susceptible to corrosion, can have scale build-up, and can cost more than PVC.

• Some contractors also use concrete, fiberglass, and asbestos cement casing.

Hole sections and well trajectory

• Drilling starts with 36 "holes down to 60-100mCasing (30 ") at an early stage because of the danger of infill of soft sediments. Casing is cast onto the formation of cement on the outside.Next section is drilled with a 26 "crown to depths of between 400-800m. Casing (20 ") is the same with cement on the outside.

• On top of this place BOP

• Production pipe cold tubing placed inside the well, a little above the bottom.At the bottom is a "production packer" placed.100-500 from the top of the subsurface safety valve (surface controlled sub surfacevalve, SCSSV) located to ensure accidental outflow from the well.At the top is placed a valve system (production street) where we can control production.

• Next section is drilled with a 17 ½ “ crown and casing at 13 5/8“ • Often the last section with 12 ¼ “ crown and 9 5/8" casing. • We are now down in the reservoir and the well can be prepared

for production.• In some wells we drill even a section before the reservoir

is reached. • This section is drilled with 8 ½ "crown and

casing 7". It is plain that this casing mounted on the 9 5/8"casing. This called for the liner.

2.3 Well Cementing

Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.

Cement Plugs

Cement slurry design.– Cement type and additives. • API class• Extenders, shrinkage, gas control, fluid loss

control, formation and pipe adherence, spacers.• Volumes and excesses. • Placement method.– Location identification,– Depth control,– Spotting method (bailer, circulation, etc.),– Contamination control,– Testing requirements.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Cement Plug Placement

Balanced method.• Modified balanced method.• Displacement from surface.• Two plug circulation.• Grouting – various.• Mechanical assistance.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Setting a cement plug

Not as easy as it may seem• Position of the end of tubing (EOT) may not

correspond to where the plug is actually set.• What are the considerations of setting a cement

plug in mud?• Effect of fluid loss and cross flow on setting an

effective cement plug?

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Setting Cement Plugs

A near 100% reliable system if cross flow can be stopped.• Most cement plugs fail because of cross flow,

density and viscosity mismatch, or failure to “break” the fluid momentum.

• Full plug method described and field tested in SPE 11415 (published in SPE JPT Nov 1984, pp 1897-1904) and SPE 7589.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Cement Plug Failure

Many cement plugs fail for the same 4 reasons:1. Cross flow cuts channels into the plug.2. Cement is higher density that the mud – cement

falls through the mud. Mud contamination of the cement may keep it from

setting.3. The mud is much lower viscosity than the cement

slurry – cement falls through the mud4. The open ended tubing produces a high

momentum energy condition that the mud cannot stop – thus cement falls through the mud.

The result of the last three is that the cement is spread out along the hole and a plug is never formed.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

How?

1. Use a simple tubing end plug with circulation to the side and

upward but not downward.2. Spot a heavily gelled bentonite pill below the cement

plug depth. Pill thickness of 500- 800 ft (152- 244 m).3. Use a custom spacer to separate the pill and the cement

slurry.4. Use a viscous, thixotropic cement with setting time equal

to the job time plus ½ hr. Plug thickness of 300 to 600 ft (91 to 183 m)5. Rotate the centralized tubing (do not reciprocate) during placement and gently withdraw at the end of the pumping. 6. WOC = 4 hrs for every 1 hour of pump time. Full details and field tests in SPE 11415.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Reasons for Cement Plug Failures

• Contamination of the cement slurry with drilling mud during or immediately after placement.

• Failure to place a viscous pill to stop downward movement of cement slurry.

• Inaccurate knowledge of volumes required.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

General Requirements

• Onshore – 10 ft (3 m) plug on top of the well and casing cut 3 ft (1m) below the ground surface.

• Mud between plugs (9.5 lb/gal).• Plug thickness minimum of 100 ft, plus 10% for

each 1000 ft of zone.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Procedures

• Remove salvageable equipment.– NORM scale present? Leave the pipe in the well?– What pipe is needed for a barrier? How effective?• Set, at minimum, plugs required by regulations. Don’t hesitate to go beyond requirements.• Test to limits required. • Cap and identify as specified.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Isolation of Open Hole

• Cement Plug 100ft (30m) above and below lower-most shoe in open hole.

• Cement retainer 50 to 100 ft (15 to 30m) above the shoe. Cement 100 ft (30m) below shoe

and 50 ft (15m) of cement on top. • Tested to 15,000 lbs load or 1000 psi.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Isolation of Perforations

• Cement Plug 100ft (30m) above and below perfs (or to next plug).

• Cement retainer 50 to 100 ft (15 to 30m) above the perfs. Cement 100 ft (30m) below shoe and 50 ft (15m) of cement on top.

• Permanent bridge plug within 150 ft (45m) of perfs with 50 ft (15m) of cement on top.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Isolation of lap joints or liner tops

• Cement Plug 100ft (30m) above and below liner top (or to next plug).

• Cement retainer or permanent bridge plug 50 ft (15m) above the liner with 50 ft (15m) of cement on top.

• Cement plug 200 ft (60m) long within 100 ft (30m) of liner.

Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.

Finding and Repairing Channels in Cement

Channels in cement occur from many causes:– Lack of effective pipe centralization, – Inadequate mud conditioning prior to cementing,– Ineffective cement displacement design and/or

execution,– Excess free water in the cement, especially in a

deviated hole (usually a cement mixing problem).– Excessive fluid loss from the cement slurry

(generally results in low cement top),– Gas influx before the cement sets,– Cement shrinkage,

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Identifying Channels in Cement Sheath

Numerous logging methods:– CBL and segmented CBL tools that scan around

the wellbore,– Borax logging, Carbon-Oxygen logs, Sonic tools,

etc.• Plug and packers with perforating.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Repair of Channels - Cement Squeezes

Types (some names anyway)– Block squeeze– Cement Packer– Suicide squeeze– Breakdown squeeze– Running and Walking squeezes– Hesitation squeeze• What is used depends on both what is needed

and the experience of the operator.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Surface Plug

On-Shore – depends on local regulations.• Offshore – cement plug 150 ft (45m) long within

150 ft (45m) of mud line. Placed in the smallest string of casing that extends

to the mud line.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Testing of Plugs

Location of the first plug below the surface plug shall be verified. – Pipe weight of 15,000 lbs on cement plug, cement

retainer, or bridge plug.– Pump pressure of 1,000 psi with maximum 10%

drop in 15 minutes.

2.4 Well Completion Types /Functions

Completion systems

• Completion systems are the components necessary to complete the well after it is drilled and prepare it for production.

• There are many completion options available to oil and gas producers.

• Today’s cased-hole completion systems vary from relatively simple single-zone low-pressure/low-temperature (LP/LT) designs to complex high-pressure/high-temperature (HP/HT) applications that were unthinkable with the technology available 50 years ago.

• Many of the basic components appear similar to those used in the past, yet they have been vastly improved, and their performance has been optimized to suit numerous environments.

Factors that affect the design of completion systems

• There are several keys to designing a successful completion system and selecting components that are fit for purpose for both the downhole environment and application.

• Consideration must be given to the various modes under which the completion must operate and the effects any changes in temperature or differential pressure will have on the tubing string and packer.

• Ultimately, the system must be both efficient and cost-effective to achieve production and financial goals.

• A key factor in the completion design is the production rate.

• Other factors that must be considered as part of the completion design:

• Packers• Elastomers• Flow control equipment• Equipment metallurgy• Equipment standards and grades such as IS

O and API• Understanding the impact of force and lengt

h changes to the tubing string• Operational mode of the well (production,

shut-in, injecting, treating)

Systems for specific completion types

• The appropriate equipment depends on the type of completion as well as downhole conditions.

Cased hole completions• Single-string low pressure/low temperature (LP/LT) wells• Single-string medium pressure/medium temperature wells• Single-string high pressure/high temperature (HP/HT) wells• Multiple-zone single-string selective completions• Dual-zone completion using parallel tubing strings• Big-bore/monobore completions

• Multilateral completions• Combination completions

Packers

• The packer forms the basis of the cased-hole completion design.

• The packer is a sealing device that isolates and contains produced fluids and pressures within the wellbore to protect the casing and other formations above or below the producing zone.

• This is essential to the basic functioning of most wells.

2.5 X-mas Tree Types/ Functions

Christmas tree (oil well)

• In petroleum and natural gas extraction, a Christmas tree, or "tree" (not "wellhead" as sometimes incorrectly referred to), is an assembly of valves, spools, and fittings used for an oil well, gas well, water injection well, water disposal well, gas injection well, condensate well and other types of wells.

• It was named for its crude resemblance to a decorated tree.

• Christmas trees are used on both surface and subsea wells. • It is common to identify the type of tree as either "subsea tree"

or "surface tree". • Each of these classifications has a number of variations. • Examples of subsea include conventional, dual bore, mono bore,

TFL (through flow line), horizontal, mudline, mudline horizontal, side valve, and TBT (through-bore tree) trees.

• The deepest installed subsea tree is in the Gulf of Mexico at approximately 9,000 feet (2,700 m).

• (Current technical limits are up to around 3000 metres and working temperatures of -50°F to 350°F with a pressure of up to 15,000 psi.)

• The primary function of a tree is to control the flow, usually oil or gas, out of the well.

• (A tree may also be used to control the injection of gas or water into a non-producing well in order to enhance production rates of oil from other wells.)

• When the well and facilities are ready to produce and receive oil or gas, tree valves are opened and the formation fluids are allowed to go through a flow line.

• This leads to a processing facility, storage depot and/or other pipeline eventually leading to a refinery or distribution center (for gas).

• Flow lines on subsea wells usually lead to a fixed or floating production platform or to a storage ship or barge, known as a floating storage offloading vessel (FSO), or floating processing unit (FPU), or floating production, storage and offloading vessel (FPSO).

• A tree often provides numerous additional functions including chemical injection points, well intervention means, pressure relief means, monitoring points (such as pressure, temperature, corrosion, erosion, sand detection, flow rate, flow composition, valve and choke position feedback), and connection points for devices such as down hole pressure and temperature transducers (DHPT).

• On producing wells, chemicals or alcohols or oil distillates may be injected to preclude production problems (such as blockages).

• Functionality may be extended further by using the control system on a subsea tree to monitor, measure, and react to sensor outputs on the tree or even down the well bore.

• The control system attached to the tree controls the downhole safety valve (SCSSV, DHSV, SSSV) while the tree acts as an attachment and conduit means of the control system to the downhole safety valve.

• Tree complexity has increased over the last few decades.

• They are frequently manufactured from blocks of steel containing multiple valves rather than being assembled from individual flanged components.

• This is especially true in subsea applications where the resemblance to Christmas trees no longer exists given the frame and support systems into which the main valve block is integrated.

• Note that a tree and wellhead are separate pieces of equipment not to be mistaken as the same piece.

• The Christmas tree is installed on top of the wellhead.

• A wellhead is used without a Christmas tree during drilling operations, and also for riser tie-back situations that later would have a tree installed at riser top.

• Wells being produced with rod pumps (pump jacks, nodding donkeys, and so on) frequently do not utilize any tree owing to no pressure-containment requirement.

Valves

• Subsea and surface trees have a large variety of valve configurations and combinations of manual and/or actuated (hydraulic or pneumatic) valves.

• Examples are identified in API Specifications 6A and 17D.

• A basic surface tree consists of two or three manual valves (usually gate valves because of their flow characteristics, i.e. low restriction to the flow of fluid when fully open).

• A typical sophisticated surface tree will have at least four or five valves, normally arranged in a crucifix type pattern (hence the endurance of the term "Christmas tree").

• The two lower valves are called the master valves (upper and lower respectively).

• Master valves are normally in the fully open position and are never opened or closed when the well is flowing (except in an emergency) to prevent erosion of the valve sealing surfaces.

• The lower master valve will normally be manually operated, while the upper master valve is often hydraulically actuated, allowing it to be used as a means of remotely shutting in the well in the event of emergency.

• An actuated wing valve is normally used to shut in the well when flowing, thus preserving the master valves for positive shut off for maintenance purposes.

• Hydraulic operated wing valves are usually built to be fail safe closed, meaning they require active hydraulic pressure to stay open.

• This feature means that if control fluid fails the well will automatically shut itself in without operator action.

• The right hand valve is often called the flow wing valve or the production wing valve, because it is in the flowpath the hydrocarbons take to production facilities (or the path water or gas will take from production to the well in the case of injection wells).

• The left hand valve is often called the kill wing valve (KWV). • It is primarily used for injection of fluids such as corrosion

inhibitors or methanol to prevent hydrate formation. • In the North Sea, it is called the non-active side arm (NASA). • It is typically manually operated.• The valve at the top is called the swab valve and lies in the path

used for well interventions like wireline and coiled tubing. • For such operations, a lubricator is rigged up onto the top of the

tree and the wire or coil is lowered through the lubricator, past the swab valve and into the well.

• This valve is typically manually operated.

• Some trees have a second swab valve, the two arranged one on top of the other.

• The intention is to allow rigging down equipment from the top of the tree with the well flowing while still preserving the Two-barrier rule.

• With only a single swab valve, the upper master valve is usually closed to act as the second barrier, forcing the well to be shut in for a day during rig down operations.

• However, avoiding delaying production for a day is usually too small a gain to be worth the extra expense of a having a Christmas tree with a second swab valve.

• Subsea trees are available in either vertical or horizontal configurations with further speciality available such as dual bore, monobore, concentric, drill-through, mudline, guidlineless or guideline.

• Subsea trees may range in size and weight from a few tons to approximately 70 tons for high pressure, deepwater (>3000 feet) guidelineless applications.

• Subsea trees contain many additional valves and accessories compared to Surface trees.

Surface and subsea Christmas tree images

2.6 Wellhead Types/ Functions

Wellhead

Wellhead

• A wellhead is the component at the surface of an oil or gas well that provides the structural and pressure-containing interface for the drilling and production equipment.

• The primary purpose of a wellhead is to provide the suspension point and pressure seals for the casing strings that run from the bottom of the hole sections to the surface pressure control equipment.

• While drilling the oil well, surface pressure control is provided by a blowout preventer (BOP).

• If the pressure is not contained during drilling operations by the column of drilling fluid, casings, wellhead, and BOP, a well blowout could occur.

• Once the well has been drilled, it is completed to provide an interface with the reservoir rock and a tubular conduit for the well fluids. The surface pressure control is provided by a Christmas tree, which is installed on top of the wellhead, with isolation valves and choke equipment to control the flow of well fluids during production.

• Wellheads are typically welded onto the first string of casing, which has been cemented in place during drilling operations, to form an integral structure of the well. In exploration wells that are later abandoned, the wellhead may be recovered for refurbishment and re-use.

• Offshore, where a wellhead is located on the production platform it is called a surface wellhead, and if located beneath the water then it is referred to as a subsea wellhead or mudline wellhead.

Components

The primary components of a wellhead system are:• casing head• casing spools• casing hangers• packoffs (isolation) seals• test plugs• mudline suspension systems• tubing heads• tubing hangers• tubing head adapter

Functions

A wellhead serves numerous functions, some of which are:• Provide a means of casing suspension. (Casing is the permanently

installed pipe used to line the well hole for pressure containment and collapse prevention during the drilling phase).

• Provides a means of tubing suspension. (Tubing is removable pipe installed in the well through which well fluids pass).

• Provides a means of pressure sealing and isolation between casing at surface when many casing strings are used.

• Provides pressure monitoring and pumping access to annuli between the different casing/tubing strings.

• Provides a means of attaching a blowout preventer during drilling.• Provides a means of attaching a Christmas tree for production

operations.• Provides a reliable means of well access.• Provides a means of attaching a well pump.

2.7 Oil & Gas Platform

Atlantis Deepwater Oil and Gas Platform, Gulf of Mexico, United States of America

• Considered one of BP's most technically challenging projects ever, the Atlantis platform is the deepest moored floating dual oil and gas production facility in the world.

• Weighing in at 58,700t, it is also one of the largest.

• BP is operator of Atlantis with 56% ownership, and its partner in the venture, BHP Billiton, has a 44% working interest.

"The Atlantis platform is the deepest moored floating dual oil and gas production facility in the world."

• The platform is located 190 miles south of New Orleans in 7,070ft (2,150m) of water, the field itself occupying five blocks – Green Canyon 699, 700, 742, 743 and 744 – with water depths ranging between 4,400ft and 7,100ft (1,338m and 2,158m).

• Originally scheduled to start in 2006, the hurricane of the 2005 season delayed progress and hiked prices, Atlantis finally produced its first oil in October 2007, with full commissioning – and a ramp up in production – following in mid-December.

• Initially producing at a daily rate of around 10,000 barrels of oil, Atlantis reached plateau production by the end of 2008.

• It has a production capacity of 200,000 barrels of oil and 180 million cubic feet of gas a day.

• The field has an estimated life of 15 years and oil reserves of 635,000 million barrels of oil equivalent.

Atlantis deepwater platform production and development

• The Atlantis platform employs an integrated semi-submersible design, with the production quarters platform supported by a separate dedicated mobile offshore drilling unit.

• In addition to the semi-submersible platform, field development uses a network of wet-tree subsea wells – with the potential for more than 18 to be tied back to Atlantis – while development drilling and well completion involved Global Santa Fe's submersible rig, Development Driller II, a long-term development unit.

• Transporting the oil and gas to existing shelf and onshore interconnections uses the Caesar and Cleopatra pipelines, respectively, which form part of the largest-capacity deepwater line ever built – the Mardi Gras transportation system, which is 65% BP-owned.

• BHP Billiton has a 25% equity share in the component Caesar pipeline and a 22% stake in Cleopatra.

• Crude from Atlantis is transported to the Ship Shoal 332B platform, from where the multiple pipeline connections allow it to reach major US markets and interconnections.

• Natural gas is channelled along Cleopatra to the Ship Shoal 332A platform, where it interconnects with the Manta Ray gathering system, before being transported to Louisiana along the Nautilus gas transportation system.

• In October 2011, EMAS AMC was contracted to install and replace subsea systems including manifolds, pipeline end manifolds, jumpers and associated equipment at the Atlantis field.

Topsides and hull

• The hull was built in Okpo, South Korea, and the topsides modules were fabricated by Ray McDermott in Morgan City, Louisiana, US, and their subsequent integration took place at Ingleside, Texas.

• The topsides layout consists of three production/utilities modules, amounting to a lift weight of 14,125t.

• Duffy & McGovern supplied the accommodation, including sleeping and office modules, laundry facilities, recreation areas and galleys, with associated sewage and fresh water tanks.

• The finished installation has a main power generation capability of 63MW.

• With a main deck of 403ft x 294ft, the hull has a displacement of 88,826t, a normal draft of 85ft and four columns of 67ft x 67ft in height; mooring is achieved via a hydraulic linear chain jack mooring system using 12in x 5.75in wire rope and chain with suction pile.

• Permanent mooring piles were installed at a depth of 2,134m by Heerema Marine – a record in 2005, which they subsequently went on to break by 308m as part of the Independence Hub project.

• The production quarters were moored at their permanent location in August 2006.

Future of Atlantis

• Atlantis is one of a series of important deepwater projects that BP and BHP are undertaking, jointly and separately – and is widely expected to make a significant difference to the fortunes of both companies.

• The petroleum division of BHP – once the biggest revenue earner – has been described as 'relatively flat' over recent years.

• With the contribution of other fields in the Gulf, Neptune and Genghis Khan where BHP is the operator having a 35% and 44% share in each, respectively, their regional production is set to rocket from a 2007 total of 12,000bpd to 100,000bpd.

• BP has a long record of major deepwater developments in the Gulf of Mexico.

• The start-up of the BP's long-delayed Thunder Horse platform in 2008 - some three years behind schedule - promoted this still further.

• It is the largest offshore platform in the world – with a capacity to produce 250,000bpd and 200 million cubic feet of gas a day – and when combined with Atlantis, add around 6.5% to total US production.

Module (03) Rig Components

3.1 Introduction to Rigs Components

List of components of oil drilling rigs1. Mud tank2. Shale shakers3. Suction line (mud pump)4. Mud pump5. Motor or power source6. Vibrating hose7. Draw-works8. Standpipe9. Kelly hose10. Goose-neck11. Traveling block12. Drill line13. Crown block14. Derrick15. Monkey board16. Stand (of drill pipe)17. Pipe rack (floor)18. Swivel (On newer rigs this may be replaced by a top drive)19. Kelly drive20. Rotary table21. Drill floor22. Bell nipple23. Blowout preventer (BOP) Annular type24. Blowout preventer (BOP) Pipe ram & blind ram25. Drill string26. Drill bit27. Casing head or Wellhead28. Flow line

Explanation

• Bell nipple (#22) is a section of large diameter pipe fitted to the top of the blowout preventers that the flow line attaches to via a side outlet, to allow the drilling mud to flow back to the mud tanks.

• Blowout preventers (BOPs) (#23 and #24) are devices installed at the wellhead to prevent fluids and gases from unintentionally escaping from the wellbore. #23 is the annular(often referred to as Hydril named after a manufacturer), and #24 is the pipe rams and blind rams.

• Casing head (#27) is a large metal flange welded or screwed onto the top of the conductor pipe (also known as drive-pipe) or the casing and is used to bolt the surface equipment such as the blowout preventers (for well drilling) or the Christmas tree (oil well) (for well production).

• Centrifuge (not pictured) is an industrial version of the device that separates fine silt and sand from the drilling fluid. It is typically mounted on top or just off of the mud tanks.

• Crown block (#13) is the stationary end of the block and tackle.• Degasser (not pictured) is a device that separates air and/or gas from the

drilling fluid. It is typically mounted on top of the mud tanks.• Derrick (#14) is the support structure for the equipment used to lower and

raise the drill string into and out of the wellbore.

• Desander / desilter (not pictured) contains a set of hydrocyclones that separate sand and silt from the drilling fluid. Typically mounted on top of the mud tanks.

• Draw-works (#7) is the mechanical section that contains the spool, whose main function is to reel in/out the drill line to raise/lower the traveling block.

• Drill Bit (#26) is a device attached to the end of the drill string that breaks apart the rock being drilled. It contains jets through which the drilling fluid exits.

• Drill floor (#21) is the area on the rig where the tools are located to make the connections of the drill pipe, bottom hole assembly, tools and bit. It is considered the main area where work is performed.

• Drill line (#12) is thick, stranded metal cable threaded through the two blocks (traveling and crown) to raise and lower the drill string.

• Drill pipe (#16) is a joint of hollow tubing used to connect the surface equipment to the bottom hole assembly (BHA) and acts as a conduit for the drilling fluid. In the diagram, these are stands of drill pipe which are 2 or 3 joints of drill pipe connected and stood in the derrick vertically, usually to save time while tripping pipe.

• Drill string (#25) is an assembled collection of drill pipe, heavy weight drill pipe, drill collars and any of a whole assortment of tools, connected and run into the wellbore to facilitate the drilling of a well. The collection is referred to singularly as the drill string.

• Elevators (not pictured) are hinged devices that is used to latch to the drill pipe or casing to facilitate the lowering or lifting (of pipe or casing) into or out of the wellbore.

• Flow line (#28) is large diameter pipe that is attached to the bell nipple and extends to the shale shakers to facilitate the flow of drilling fluid back to the mud tanks.

• Goose-neck (#10) is a thick metal elbow connected to the swivel and standpipe that supports the weight of and provides a downward angle for the kelly hose to hang from.

• Kelly drive (#19) is a square, hexagonal or octagonal shaped tubing that is inserted through and is an integral part of the rotary table that moves freely vertically while the rotary table turns it.

• Kelly hose (#9) is a flexible, high pressure hose that connects the standpipe to the kelly (or more specifically to the gooseneck on the swivel above the kelly) and allows free vertical movement of the kelly, while facilitating the flow of the drilling fluid through the system and down the drill string.

• Monkey board (#15) is the catwalk along the side of the derrick (usually about 35 or 40 feet above the "floor"). The monkey board is where the derrick man works while "tripping" pipe.

• Mud motor (not pictured) is a hydraulically powered device positioned just above the drill bit used to spin the bit independently from the rest of the drill string.

• Mud pump (#4) is a reciprocal type of pump used to circulate drilling fluid through the system.

• Mud tank (#1) is often called mud pits and stores drilling fluid until it is required down the wellbore.

• Pipe rack (#17) is a part of the drill floor (#21) where the stands of drill pipe are stood upright. It is typically made of a metal frame structure with large wooden beams situated within it. The wood helps to protect the end of the drill pipe.

• Rotary table (#20) rotates, along with its constituent parts, the kelly and kelly bushing, the drill string and the attached tools and bit.

• Shale shaker (#2) separates drill cuttings from the drilling fluid before it is pumped back down the wellbore.

• Stand (#16) is a section of 2 or 3 joints of drill pipe connected and stood upright in the derrick. When they are pulled out of the hole, instead of laying down each joint of drill pipe, 2 or 3 joints are left connected and stood in the derrick to save time.

• Standpipe (#8) is a thick metal tubing, situated vertically along the derrick, that facilitates the flow of drilling fluid and has attached to it and supports one end of the kelly hose.

• Suction line (#3) is an intake line for the mud pump to draw drilling fluid from the mud tanks.

• Swivel (#18) is the top end of the kelly that allows the rotation of the drill string without twisting the block.

• Traveling block (#11) is the moving end of the block and tackle. Together, they give a significant mechanical advantage for lifting.

• Vibrating hose (#6) is a flexible, high pressure hose (similar to the kelly hose) that connects the mud pump to the stand pipe. It is called the vibrating hose because it tends to vibrate and shake (sometimes violently) due to its close proximity to the mud pumps.

3.2 Drill String Components

Drill string

• A drill string on a drilling rig is a column, or string, of drill pipe that transmits drilling fluid (via the mud pumps) and torque (via the kelly drive or top drive) to the drill bit.

• The term is loosely applied as the assembled collection of the drill pipe, drill collars, tools and drill bit.

• The drill string is hollow so that drilling fluid can be pumped down through it and circulated back up the annulus (the void between the drill string and the casing/open hole).

Drill string components

The drill string is typically made up of three sections:• Bottom hole assembly (BHA)• Transition pipe, which is often heavyweight drill

pipe (HWDP)• Drill pipe

Transition pipe

• Heavyweight drill pipe (HWDP) may be used to make the transition between the drill collars and drill pipe.

• The function of the HWDP is to provide a flexible transition between the drill collars and the drill pipe.

• This helps to reduce the number of fatigue failures seen directly above the BHA.

• A secondary use of HWDP is to add additional weight to the drill bit.

• HWDP is most often used as weight on bit in deviated wells.

• The HWDP may be directly above the collars in the angled section of the well, or the HWDP may be found before the kick off point in a shallower section of the well.

Drill pipe

• Drill pipe makes up the majority of the drill string back up to the surface.

• Each drill pipe comprises a long tubular section with a specified outside diameter (e.g. 3 1/2 inch, 4 inch, 5 inch, 5 1/2 inch, 5 7/8 inch, 6 5/8 inch).

• At each end of the drill pipe tubular, larger-diameter portions called the tool joints are located.

• One end of the drill pipe has a male ("pin") connection whilst the other has a female ("box") connection.

• The tool joint connections are threaded which allows for the make of each drill pipe segment to the next segment.

Running a drill string

• Most components in a drill string are manufactured in 31 foot lengths (range 2) although they can also be manufactured in 46 foot lengths (range 3).

• Each 31 foot component is referred to as a joint. • Typically 2, 3 or 4 joints are joined together to make a stand. • Modern onshore rigs are capable of handling ~90 ft stands (often

referred to as a triple).• Pulling the drill string out of or running the drill string into the hole

is referred to as tripping. • Drill pipe, HWDP and collars are typically racked back in stands in

to the monkey board which is a component of the derrick if they are to be run back into the hole again after, say, changing the bit.

• The disconnect point ("break") is varied each subsequent round trip so that after three trips every connection has been broken apart and later made up again with fresh pipe dope applied.

3.3 Marine Riser and Riser Tensioner

Drilling riser

• A drilling riser is a conduit that provides a temporary extension of a subsea oil well to a surface drilling facility.

• Drilling risers are categorised into two types: marine drilling risers used with subsea blowout preventer (BOP) and generally used by floating drilling vessels; and tie-back drilling risers used with a surface BOP and generally deployed from fixed platforms or very stable floating platforms like a spar or tension leg platform (TLP).

Marine drilling riser

• A marine drilling riser has a large diameter, low pressure main tube with external auxiliary lines that include high pressure choke and kill lines for circulating fluids to the subsea blowout preventer (BOP), and usually power and control lines for the BOP.

• The design and operation of marine drilling risers is complex, and the requirement for high reliability means an extensive amount of engineering analysis is required.

• When used in water depths greater than about 20 meters, the marine drilling riser has to be tensioned to maintain stability.

• A marine riser tensioner located on the drilling platform provides a near constant tension force adequate to maintain the stability of the riser in the offshore environment.

• The level of tension required is related to the weight of the riser equipment, the buoyancy of the riser, the forces from waves and currents, the weight of the internal fluids, and an adequate allowance for equipment failures.

• To reduce the amount of tension required to maintain stability of the riser, buoyancy modules, known in the industry as 'buoyancy cakes', are added to the riser joints to make them close to neutrally buoyant when submerged.

• The international standard ISO 13624-1:2009 covers the design, selection, operation and maintenance of marine riser systems for floating drilling operations. 

• Its purpose is to serve as a reference for designers, for those who select system components, and for those who use and maintain this equipment.

• It relies on basic engineering principles and the accumulated experience of offshore operators, contractors, and manufacturers.

Tie-back drilling riser

• A tie-back riser can be either a single large-diameter high pressure pipe, or a set of concentric pipes extending the casing strings in the well up to a surface BOP.

Drilling riser joints with buoyancy modules

Marine riser tensioner

• A marine riser tensioner is a device used on an offshore drilling vessel which provides a near constant upward force on the drilling riser independent of the movement of the floating drill vessel.

• The marine riser is connected to the wellhead on the sea bed and therefore the tensioner must manage the differential movements between the riser and the rig.

• If there were no tensioner and the rig moves downward, the riser would buckle; if the rig rises then high forces would be transmitted to the riser and it would stretch and be damaged.

• Tensioners have historically been composed of hydraulic actuated cylinders with wire sheaves.

• More recently, active electrical motors have been used for compensation purposes.

Hydraulic Tensioner

• A hydraulic riser tensioner consists of a hydraulic cylinder with sheaves at both sides.

• The cylinder is connected to a number of high-pressure gas bottles via a medium separator.

• A wire rope is rigged in the cylinder; one end is connected to the fixed part of the tensioner, the other end is connected to the riser. 

• On board a drill rig tensioners are usually required for drill string compensator, riser tensioner, and guideline tensioner.

Aker Kvaerner MH Marine Riser Tensioner (MRT)

3.4 BHA

Bottom hole assembly (BHA)

• The BHA is made up of: a drill bit, which is used to break up the rock formations; drill collars, which are heavy, thick-walled tubes used to apply weight to the drill bit; and drilling stabilizers, which keep the assembly centered in the hole.

• The BHA may also contain other components such as a downhole motor and rotary steerable system, measurement while drilling (MWD), and logging while drilling (LWD) tools.

• The components are joined together using rugged threaded connections.

• Short "subs" are used to connect items with dissimilar threads.

BHA

3.5 BOP Types, Functions and Components

• A blowout preventer is a large, specialized valve or similar mechanical device, usually installed redundantly in stacks, used to seal, control and monitor oil and gas wells.

• Blowout preventers were developed to cope with extreme erratic pressures and uncontrolled flow (formation kick) emanating from a well reservoir during drilling.

• Kicks can lead to a potentially catastrophic event known as a blowout. • In addition to controlling the downhole (occurring in the drilled hole)

pressure and the flow of oil and gas, blowout preventers are intended to prevent tubing (e.g. drill pipe and well casing), tools and drilling fluid from being blown out of the wellbore (also known as bore hole, the hole leading to the reservoir) when a blowout threatens.

• Blowout preventers are critical to the safety of crew, rig (the equipment system used to drill a wellbore) and environment, and to the monitoring and maintenance of well integrity; thus blowout preventers are intended to provide fail-safety to the systems that include them.

• The term BOP (pronounced B-O-P, not "bop") is used in oilfield vernacular to refer to blowout preventers.

• The abbreviated term preventer, usually prefaced by a type (e.g. ram preventer), is used to refer to a single blowout preventer unit.

• A blowout preventer may also simply be referred to by its type (e.g. ram).

• The terms blowout preventer, blowout preventer stack and blowout preventer system are commonly used interchangeably and in a general manner to describe an assembly of several stacked blowout preventers of varying type and function, as well as auxiliary components.

• A typical subsea deepwater blowout preventer system includes components such as electrical and hydraulic lines, control pods, hydraulic accumulators, test valve, kill and choke lines and valves, riser joint, hydraulic connectors, and a support frame.

• Two categories of blowout preventer are most prevalent: ram and annular. • BOP stacks frequently utilize both types, typically with at least one

annular BOP stacked above several ram BOPs.• (A related valve, called an inside blowout preventer, internal blowout

preventer, or IBOP, is positioned within, and restricts flow up, the drillpipe.)

• Blowout preventers are used on land wells, offshore rigs, and subsea wells.

• Land and subsea BOPs are secured to the top of the wellbore, known as the wellhead.

• BOPs on offshore rigs are mounted below the rig deck. • Subsea BOPs are connected to the offshore rig above by a drilling riser

that provides a continuous pathway for the drill string and fluids emanating from the wellbore.

• In effect, a riser extends the wellbore to the rig.

Use

• Blowout preventers come in a variety of styles, sizes and pressure ratings.

• Several individual units serving various functions are combined to compose a blowout preventer stack.

• Multiple blowout preventers of the same type are frequently provided for redundancy, an important factor in the effectiveness of fail-safe devices.

The primary functions of a blowout preventer system are to:• Confine well fluid to the wellbore;• Provide means to add fluid to the wellbore;• Allow controlled volumes of fluid to be withdrawn from

the wellbore.

Additionally, and in performing those primary functions, blowout preventer systems are used to:• Regulate and monitor wellbore pressure;• Center and hang off the drill string in the wellbore;• Shut in the well (e.g. seal the void, annulus,

between drillpipe and casing);• “Kill” the well (prevent the flow of formation fluid,

influx, from the reservoir into the wellbore);• Seal the wellhead (close off the wellbore);• Sever the casing or drill pipe (in case of

emergencies).

• In drilling a typical high-pressure well, drill strings are routed through a blowout preventer stack toward the reservoir of oil and gas.

• As the well is drilled, drilling fluid, "mud", is fed through the drill string down to the drill bit, "blade", and returns up the wellbore in the ring-shaped void, annulus, between the outside of the drill pipe and the casing (piping that lines the wellbore).

• The column of drilling mud exerts downward hydrostatic pressure to counter opposing pressure from the formation being drilled, allowing drilling to proceed.

• If the blowout preventers and mud do not restrict the upward pressures of a kick, a blowout results, potentially shooting tubing, oil and gas up the wellbore, damaging the rig, and leaving well integrity in question.

• Since BOPs are important for the safety of the crew and natural environment, as well as the drilling rig and the wellbore itself, authorities recommend, and regulations require, that BOPs be regularly inspected, tested and refurbished.

• Tests vary from daily test of functions on critical wells to monthly or less frequent testing on wells with low likelihood of control problems.

• Exploitable reservoirs of oil and gas are increasingly rare and remote, leading to increased subsea deepwater well exploration and requiring BOPs to remain submerged for as long as a year in extreme conditions.

• As a result, BOP assemblies have grown larger and heavier (e.g. a single ram-type BOP unit can weigh in excess of 30,000 pounds), while the space allotted for BOP stacks on existing offshore rigs has not grown commensurately.

• Thus a key focus in the technological development of BOPs over the last two decades has been limiting their footprint and weight while simultaneously increasing safe operating capacity.

Types

• BOPs come in two basic types, ram and annular. • Both are often used together in drilling rig BOP

stacks, typically with at least one annular BOP capping a stack of several ram BOPs.

Ram blowout preventer

• The ram BOP was invented by James Smither Abercrombie and Harry S. Cameron in 1922, and was brought to market in 1924 by Cameron Iron Works.

• A ram-type BOP is similar in operation to a gate valve, but uses a pair of opposing steel plungers, rams.

• The rams extend toward the center of the wellbore to restrict flow or retract open in order to permit flow.

• The inner and top faces of the rams are fitted with packers (elastomeric seals) that press against each other, against the wellbore, and around tubing running through the wellbore.

• Outlets at the sides of the BOP housing (body) are used for connection to choke and kill lines or valves.

• Rams, or ram blocks, are of four common types: pipe, blind, shear, and blind shear.

• Pipe rams close around a drill pipe, restricting flow in the annulus (ring-shaped space between concentric objects) between the outside of the drill pipe and the wellbore, but do not obstruct flow within the drill pipe.

• Variable-bore pipe rams can accommodate tubing in a wider range of outside diameters than standard pipe rams, but typically with some loss of pressure capacity and longevity.

• Blind rams (also known as sealing rams), which have no openings for tubing, can close off the well when the well does not contain a drill string or other tubing, and seal it.

• Shear rams cut through the drill string or casing with hardened steel shears.

• Blind shear rams (also known as shear seal rams, or sealing shear rams) are intended to seal a wellbore, even when the bore is occupied by a drill string, by cutting through the drill string as the rams close off the well.

• The upper portion of the severed drill string is freed from the ram, while the lower portion may be crimped and the “fish tail” captured to hang the drill string off the BOP.

• In addition to the standard ram functions, variable-bore pipe rams are frequently used as test rams in a modified blowout preventer device known as a stack test valve.

• Stack test valves are positioned at the bottom of a BOP stack and resist downward pressure (unlike BOPs, which resist upward pressures).

• By closing the test ram and a BOP ram about the drill string and pressurizing the annulus, the BOP is pressure-tested for proper function.

• The original ram BOPs of the 1920s were simple and rugged manual devices with minimal parts.

• The BOP housing (body) had a vertical well bore and horizontal ram cavity (ram guide chamber).

• Opposing rams (plungers) in the ram cavity translated horizontally, actuated by threaded ram shafts (piston rods) in the manner of a screw jack.

• Torque from turning the ram shafts by wrench or hand wheel was converted to linear motion and the rams, coupled to the inner ends of the ram shafts, opened and closed the well bore.

• Such screw jack type operation provided enough mechanical advantage for rams to overcome downhole pressures and seal the wellbore annulus.

• Hydraulic rams BOPs were in use by the 1940s. • Hydraulically actuated blowout preventers had

many potential advantages. • The pressure could be equalized in the opposing

hydraulic cylinders causing the rams to operate in unison.

• Relatively rapid actuation and remote control were facilitated, and hydraulic rams were well-suited to high pressure wells.

• Because BOPs are depended on for safety and reliability, efforts to minimize the complexity of the devices are still employed to ensure longevity.

• As a result, despite the ever-increasing demands placed on them, state of the art ram BOPs are conceptually the same as the first effective models, and resemble those units in many ways.

• Ram BOPs for use in deepwater applications universally employ hydraulic actuation.

• Threaded shafts are often still incorporated into hydraulic ram BOPs as lock rods that hold the ram in position after hydraulic actuation.

• By using a mechanical ram locking mechanism, constant hydraulic pressure need not be maintained.

• Lock rods may be coupled to ram shafts or not, depending on manufacturer.

• Other types of ram locks, such as wedge locks, are also used.• Typical ram actuator assemblies (operator systems) are secured to

the BOP housing by removable bonnets. • Unbolting the bonnets from the housing allows BOP maintenance

and facilitates the substitution of rams. • In that way, for example, a pipe ram BOP can be converted to a

blind shear ram BOP.

• Shear-type ram BOPs require the greatest closing force in order to cut through tubing occupying the wellbore.

• Boosters (auxiliary hydraulic actuators) are frequently mounted to the outer ends of a BOP’s hydraulic actuators to provide additional shearing force for shear rams.

• Ram BOPs are typically designed so that well pressure will help maintain the rams in their closed, sealing position.

• That is achieved by allowing fluid to pass through a channel in the ram and exert pressure at the ram’s rear and toward the center of the wellbore.

• Providing a channel in the ram also limits the thrust required to overcome well bore pressure.

• Single ram and double ram BOPs are commonly available. • The names refer to the quantity of ram cavities (equivalent to the effective

quantity of valves) contained in the unit. • A double ram BOP is more compact and lighter than a stack of two single

ram BOPs while providing the same functionality, and is thus desirable in many applications.

• Triple ram BOPs are also manufactured, but not as common.• Technological development of ram BOPs has been directed towards deeper

and higher pressure wells, greater reliability, reduced maintenance, facilitated replacement of components, facilitated ROV intervention, reduced hydraulic fluid consumption, and improved connectors, packers, seals, locks and rams. In addition, limiting BOP weight and footprint are significant concerns to account for the limitations of existing rigs.

• The highest-capacity large-bore ram blowout preventer on the market, as of July 2010, Cameron’s EVO 20K BOP, has a hold-pressure rating of 20,000 psi, ram force in excess of 1,000,000 pounds, and a well bore diameter of 18.75 inches.

Annular blowout preventer

• The annular blowout preventer was invented by Granville Sloan Knox in 1946; a U.S. patent for it was awarded in 1952. 

• Often around the rig it is called the "Hydril", after the name of one of the manufacturers of such devices.

• An annular-type blowout preventer can close around the drill string, casing or a non-cylindrical object, such as the kelly.

• Drill pipe including the larger-diameter tool joints (threaded connectors) can be "stripped" (i.e., moved vertically while pressure is contained below) through an annular preventer by careful control of the hydraulic closing pressure.

• Annular blowout preventers are also effective at maintaining a seal around the drillpipe even as it rotates during drilling.

• Regulations typically require that an annular preventer be able to completely close a wellbore, but annular preventers are generally not as effective as ram preventers in maintaining a seal on an open hole.

• Annular BOPs are typically located at the top of a BOP stack, with one or two annular preventers positioned above a series of several ram preventers.

• An annular blowout preventer uses the principle of a wedge to shut in the wellbore.

• It has a donut-like rubber seal, known as an elastomeric packing unit, reinforced with steel ribs.

• The packing unit is situated in the BOP housing between the head and hydraulic piston.

• When the piston is actuated, its upward thrust forces the packing unit to constrict, like a sphincter, sealing the annulus or openhole.

• Annular preventers have only two moving parts, piston and packing unit, making them simple and easy to maintain relative to ram preventers.

• The original type of annular blowout preventer uses a “wedge-faced” (conical-faced) piston.

• As the piston rises, vertical movement of the packing unit is restricted by the head and the sloped face of the piston squeezes the packing unit inward, toward the center of the wellbore.

• In 1972, Ado N. Vujasinovic was awarded a patent for a variation on the annular preventer known as a spherical blowout preventer, so-named because of its spherical-faced head.

• As the piston rises the packing unit is thrust upward against the curved head, which constricts the packing unit inward.

• Both types of annular preventer are in common use.

Control methods

• When rigs are drilled on land or in very shallow water where the wellhead is above the water line, BOPs are activated by hydraulic pressure from a remote accumulator.

• Several control stations will be mounted around the rig. They also can be closed manually by turning large wheel-like handles.

• In deeper offshore operations with the wellhead just above the mudline on the sea floor, there are four primary ways by which a BOP can be controlled.

The possible means are:• Electrical Control Signal: sent from the surface through a

control cable• Acoustical Control Signal: sent from the surface based on a

modulated/encoded pulse of sound transmitted by an underwater transducer

• ROV Intervention: remotely operated vehicles (ROVs) mechanically control valves and provide hydraulic pressure to the stack (via “hot stab” panels)

• Deadman Switch / Auto Shear: fail-safe activation of selected BOPs during an emergency, and if the control, power and hydraulic lines have been severed

• Two control pods are provided on the BOP for redundancy.

• Electrical signal control of the pods is primary. • Acoustical, ROV intervention and dead-man controls

are secondary.• An emergency disconnect system, or EDS, disconnects

the rig from the well in case of an emergency. • The EDS is also intended to automatically trigger the

deadman switch, which closes the BOP, kill and choke valves.

• The EDS may be a subsystem of the BOP stack’s control pods or separate.

• Pumps on the rig normally deliver pressure to the blowout preventer stack through hydraulic lines.

• Hydraulic accumulators are on the BOP stack enable closure of blowout preventers even if the BOP stack is disconnected from the rig.

• It is also possible to trigger the closing of BOPs automatically based on too high pressure or excessive flow.

• Individual wells along the U.S. coastline may also be required to have BOPs with backup acoustic control. 

• General requirements of other nations, including Brazil, were drawn to require this method. 

• BOPs featuring this method may cost as much as US$500,000 more than those that omit the feature.

Blowout preventer

Cameron International Corporation's EVO Ram BOP Patent Drawing (with legend)

Patent Drawing of Hydril Annular BOP (with legend)

Patent Drawing of a Subsea BOP Stack (with legend)

A Patent Drawing of the Original Ram-type Blowout Preventer, by Cameron Iron Works (1922).

Blowout Preventer diagram showing different types of rams. (a) blind ram (b) pipe ram and (c) shear ram.

Patent Drawing of a Varco Shaffer Ram BOP Stack. A shear ram BOP has cut the drillstring and a pipe ram has hung it off.

Hydril Company's Compact BOP Ram Actuator Assembly Patent Drawing

Patent Drawing of Original Shaffer Spherical-type Blowout Preventer (1972)

Diagram of an Annular blowout preventer in open and fully closed configurations. The flexible annulus (donut) in blue is forced into the drillpipe cavity by the hydraulic pistons.

Deepwater horizon incident

Deepwater Horizon blowout

• During the Deepwater Horizon drilling rig explosion incident on April 20, 2010, the blowout preventer should have been activated automatically, cutting the drillstring and sealing the well to preclude a blowout and subsequent oil spill in the Gulf of Mexico, but it failed to fully engage.

• Underwater robots (ROVs) later were used to manually trigger the blind shear ram preventer, to no avail.

• Blowout (well drilling)

• As of May 2010 it was unknown why the blowout preventer failed. • Chief surveyor John David Forsyth of the American Bureau of Shipping testified

in hearings before the Joint Investigation of the Minerals Management Service and the U.S. Coast Guard investigating the causes of the explosion that his agency last inspected the rig's blowout preventer in 2005.

• BP representatives suggested that the preventer could have suffered a hydraulic leak. 

• Gamma-ray imaging of the preventer conducted on May 12 and May 13, 2010 showed that the preventer's internal valves were partially closed and were restricting the flow of oil.

• Whether the valves closed automatically during the explosion or were shut manually by remotely operated vehicle work is unknown. 

• A statement released by Congressman Bart Stupak revealed that, among other issues, the emergency disconnect system (EDS) did not function as intended and may have malfunctioned due to the explosion on the Deepwater Horizon.

• The permit for the Macondo Prospect by the Minerals Management Service in 2009 did not require redundant acoustic control means.

• Inasmuch as the BOPs could not be closed successfully by underwater manipulation (ROV Intervention), pending results of a complete investigation, it is uncertain whether this omission was a factor in the blowout.

• Documents discussed during congressional hearings June 17, 2010, suggested that a battery in the device's control pod was flat and that the rig's owner, Transocean, may have "modified" Cameron's equipment for the Macondo site (including incorrectly routing hydraulic pressure to a stack test valve instead of a pipe ram BOP) which increased the risk of BOP failure, in spite of warnings from their contractor to that effect.

• Another hypothesis was that a junction in the drilling pipe may have been positioned in the BOP stack in such way that its shear rams had an insurmountable thickness of material to cut through.

• It was later discovered that a second piece of tubing got into the BOP stack at some point during the Macondo incident, potentially explaining the failure of the BOP shearing mechanism. 

• As of July 2010 it was unknown whether the tubing might have been casing that shot up through the well or perhaps broken drill pipe that dropped into the well.

• The DNV final report indicated that the second tube was the segment of the drill string that was ejected after being cut by the blow out preventer shears.

• On July 10, 2010 BP began operations to install a sealing cap, also known as a capping stack, a top the failed blowout preventer stack.

• Based on BP's video feeds of the operation the sealing cap assembly, called Top Hat 10, included a stack of three blind shear ram BOPs manufactured by Hydril (a GE Oil & Gas company), one of Cameron's chief competitors.

• By July 15 the 3 ram capping stack had sealed the Macondo well, if only temporarily, for the first time in 87 days.

• The U.S. government wanted the failed blowout preventer to be replaced in case of any pressure change that occurs when the relief well intersected with the well. 

• On September 3 at 1:20 p.m. CDT the 300 ton failed blowout preventer was removed from the well and began being slowly lifted to the surface. 

• Later that day a replacement blowout preventer was placed on the well. 

• On September 4 at 6:54 p.m. CDT the failed blowout preventer reached the surface of the water and at 9:16 p.m. CDT it was placed in a special container on board the vessel Helix Q4000. 

• The failed blowout preventer was taken to a NASA facility in Louisiana for examination by Det Norske Veritas (DNV).

• On 20 March 2011, DNV presented their report to the US Department of Energy.

• Their primary conclusion was that while the rams succeeded in partly shearing through the drill pipe they failed to seal the bore because the drill pipe had buckled out of the intended line of action of the rams (because the drill string was caught at a tool joint in the upper annular BOP valve), jamming the shears and leaving the drill string shear actuator unable do deliver enough force to complete its stroke and fold the cut pipe over and seal the well.

• They did not suggest any failure of actuation as would be caused by faulty batteries.

• The upper section of the blow out preventer failed to separate as designed due to numerous oil leaks compromising hydraulic actuator operation, and this had to be cut free during recovery.

A robotic arm of a Remotely Operated Vehicle (ROV) attempts to activate the "Deepwater Horizon" Blowout Preventer (BOP), Thursday, April 22, 2010.

3.6 BOP Mounted Gate Valves & Lifting Equipment

Gate Valves

Functions• Gate Valves are Isolation Valves with generally two seats

and a gate moving up and down by use of a stem operated either by Wheel, Gear or Actuator.

• Gate Valves is always bi-directional.• Gate Valves looks similar to a Globe Valves from the

outside due to the fact that they often are producers from the same body and it could be a challenge to recognize a Gate Valve from a Globe Valves. 

• However the Globe Valves should be easy recognized since it always has an arrow on the body which is grinded off on a Gate Valves.

• This arrow also defines the flow direction of the Globe Valves.

Operation:

• Gate Valves are mainly used for isolation• Well head valves are always Gate Valves• Gate Valves could be damaged if it is operated

during production or when there is a differential pressure over the Gate Valves.

Options:

• Gate Valves could have fixed or floating seats- expanding or parallel gate

• Trough conduit or normal wedge Gate Valves – reversed or normal operated

• In general there are a lot of different models and options of the Gate Valves.

• This might cause some confusion when Gate Valves of different types and brands are installed on the same location.

3.7 BOP Hydraulic Power Unit

• The Hydraulic Power Unit (HPU) is a single skid mounted unit that supplies pressurized hydraulic fluid to various control system components for the safe and reliable operation of the BOP.

• The HPU is a demand based system (if running in auto mode) that will automatically provide and maintain the required system operating volume and pressure of five-thousand (5,000) psi.

• The HPU is designed in compliance with the provisions of API 16D that provide for a combined system to supply a sufficient quantity of hydraulic fluid to charge the entire accumulator system from the pre-charged pressure to the maximum rated operating pressure within fifteen (15) minutes.

• The main frame is fully seam welded for maximum durability and strength and comes equipped with four lift points (swivel rings) for safe handling.

• A stainless steel, sloped bottom drip pan with valved drains and flush mounted fiberglass grating are also provided to ensure a safe and uncluttered walkway.

• In addition, the HPU is supplied with all required suction strainers, block-and-bleed valves, downstream check valves, relief valves, and pulsation dampeners to operate the unit.

• All main skid structural components are coated with a three part marine epoxy paint system for added harsh environment protection.

Hydraulic Power Unit Functions:

• Supplies pressurized hydraulic fluid to various control system components for the safe and reliable operation of the BOP

• When in auto mode, monitors and charges the BOP Subsea Accumulators

• Communicates with the control system and provides reedbacks on behalf of the optional Reservoir Mixing Unit (RMU)

Hydraulic Power Unit Options:• Custom designs available to suit your specific needs• DNV and ABS certification availiableHydraulic Power Unit Features:• Self contained, fully seam welded skid with accessible component

design makes installation and maintenance fast and easy• Operates in manual or fully automatic modes for effortless control

and operation• Manufactured, in-house, at our Houston, Texas Facility with the

highest quality contemporary stainless steel valves and piping that resist corrosion and provide robust performance

• Our systems meet and/or exceed API 16D requirements. ABS and DNV Certification is available, upon request

• 7 days-a-week replacement parts customer support for “Rig-Down” situations

Technical Specifications

Overall Dimensions (typical): (L) 232 in x (W) 84 in x (H) 93.5 in (shackles removed)

Weight (Dry): 19,500 lbs.

Weight (with fluid): 20,000 lbs.

Temperature Range: -10oF to +140oF

Required Main Service Voltage: 3x 460 VAC, 3 Phase, 30 Amp

Required Fluid Service: Up to 75 gpm

Required Water Service: 90 psi @ 5 scfm

Max Throughput: 75 gpm @ 4,800 to 5,000 psi

Major System Components (Vary per Customer Requirements and Options)

• 3x 100hp AC Motors• Recirculation Pump• 3x 25 gpm pumps• Flow Control Valves• Motor starter panels• Fluid Level Sensors• Interface control panel• UV Filter Kit (optional)

3.8 Drilling Fluids System Components

Figure DFSC Diagram illustrating the drilling-fluid (drilling-mud) system and the flow of fluids through the system.

Spudding in

• "Spudding in," or to "spud" a well, means to begin drilling operations.

• The drill string, consisting of a drill bit, drill collars, drill pipe, and kelly, is assembled and lowered into the conductor pipe.

• Drilling fluid, better known as drilling mud, is circulated through the kelly and the drill string by means of pipes and flexible hose connecting the drilling fluid or mud pumps and a swivel device attached to the upper end of the kelly.

• The swivel device enables drilling mud to be circulated while the kelly and drill string are rotated.

• The mud pump draws fluid from mud tanks or pits located nearby. • The drilling mud passes through the kelly, drill pipe, drill collars,

and drill bit. • It is returned to the surface by means of the well bore and the

conductor pipe where it is directed to a device called a shale shaker.

• The shale shaker separates the drill cuttings and solids from the drilling mud, which is returned to the mud tanks to be circulated again Fig. DFSC

• As the drill string is rotated in the well bore, the drill bit cuts into the rock.

• The drilling mud lubricates and cools the drill bit and drill string and carries the drill cuttings to the surface (fig. DFSC).

• Figure DFSC Diagram illustrating the drilling-fluid (drilling-mud) system and the flow of fluids through the system.

3.9 Mud Gas Separator

Mud Gas Separator capable of handling 1000-1500gpm

Process Flow Diagram For Mud Gas Separator

• Mud Gas Separator is commonly called a gas-buster or poor boy degasser.

• It captures and separates large volume of free gas within the drilling fluid.

• If there is a "KICK" situation, this vessel separates the mud and the gas by allowing it to flow over baffle plates.

• The gas then is forced to flow through a line and vent it to a flare.

• A "KICK" situation happens when the annular hydrostatic pressurein a drilling well temporarily (and usually relatively suddenly) falls below that of the formation, or pore, pressure in a permeable section downhole, and before control of the situation is lost.

• It is always safe to design the mud/gas separator that will handle the maximum possible gas flow that can occur.

3.10 Choke Manifold

• In oil and gas production a choke manifold is used to lower the pressure from the well head.

• It consist of a set of high pressure valves and at least two chokes.

• These chokes can be fixed or adjustable or a mix of both.

• The redundancy is needed so that if one choke has to be taken out of service, the flow can be directed through another one.

• By lowering pressure the retrieved gases can be flared off on site.

3.11 Entry Test

3.12 Draw-works

3.13 Crown Block, Travelling Block and Swivel

3.14 Lifting and Handling Equipment

3.15 Mud Pumps

3.16 Diesel Engines, Emergency Engines and Air Compressors

• Diesel Engines

• Emergency Engines

• Air Compressors

Module (04) Drilling Fluids

4.1 Drilling Fluids (types, classification, calculations)

Drilling fluid

• In geotechnical engineering, drilling fluid is used to aid the drilling of boreholes into the earth.

• Often used while drilling oil and natural gas wells and on exploration drilling rigs, drilling fluids are also used for much simpler boreholes, such as water wells.

• Liquid drilling fluid is often called drilling mud. • The three main categories of drilling fluids are water-based muds (which

can be dispersed and non-dispersed), non-aqueous muds, usually called oil-based mud, and gaseous drilling fluid, in which a wide range of gases can be used.

• The main functions of drilling fluids include providing hydrostatic pressure to prevent formation fluids from entering into the well bore, keeping the drill bit cool and clean during drilling, carrying out drill cuttings, and suspending the drill cuttings while drilling is paused and when the drilling assembly is brought in and out of the hole.

• The drilling fluid used for a particular job is selected to avoid formation damage and to limit corrosion.

Types of drilling fluid

• Many types of drilling fluids are used on a day-to-day basis.

• Some wells require that different types be used at different parts in the hole, or that some types be used in combination with others.

The various types of fluid generally fall into a few broad categories:

• Air: Compressed air is pumped either down the bore hole's annular space or down the drill string itself.

• Air/water: The same as above, with water added to increase viscosity, flush the hole, provide more cooling, and/or to control dust.

• Air/polymer: A specially formulated chemical, most often referred to as a type of polymer, is added to the water & air mixture to create specific conditions.

• A foaming agent is a good example of a polymer.• Water: Water by itself is sometimes used. • In offshore drilling sea water is typically used while

drilling the top section of the hole.

Water-based mud (WBM):

• Most basic water-based mud systems begin with water, then clays and other chemicals are incorporated into the water to create a homogeneous blend resembling something between chocolate milk and a malt (depending on viscosity).

• The clay (called "shale" in its rock form) is usually a combination of native clays that are suspended in the fluid while drilling, or specific types of clay that are processed and sold as additives for the WBM system.

• The most common of these is bentonite, frequently referred to in the oilfield as "gel".

• Gel likely makes reference to the fact that while the fluid is being pumped, it can be very thin and free-flowing (like chocolate milk), though when pumping is stopped, the static fluid builds a "gel" structure that resists flow.

• When an adequate pumping force is applied to "break the gel", flow resumes and the fluid returns to its previously free-flowing state.

• Many other chemicals (e.g. potassium formate) are added to a WBM system to achieve various effects, including: viscosity control, shale stability, enhance drilling rate of penetration, cooling and lubricating of equipment.

Oil-based mud (OBM):

• Oil-based mud is a mud where the base fluid is a petroleum product such as diesel fuel.

• Oil-based muds are used for many reasons, including increased lubricity, enhanced shale inhibition, and greater cleaning abilities with less viscosity.

• Oil-based muds also withstand greater heat without breaking down.

• The use of oil-based muds has special considerations, including cost, environmental considerations such as disposal of cuttings in an appropriate place, and the exploratory disadvantages of using oil-based mud, especially in wildcat wells.

• Using an oil-based mud interferes with the geochemical analysis of cuttings and cores and with the determination of API gravity because the base fluid cannot be distinguished from oil returned from the formation.

Synthetic-based fluid (SBM)

• (Otherwise known as Low Toxicity Oil Based Mud or LTOBM): Synthetic-based fluid is a mud where the base fluid is a synthetic oil.

• This is most often used on offshore rigs because it has the properties of an oil-based mud, but the toxicity of the fluid fumes are much less than an oil-based fluid.

• This is important when men work with the fluid in an enclosed space such as an offshore drilling rig.

• Synthetic-based fluid poses the same environmental and analysis problems as oil-based fluid.

• On a drilling rig, mud is pumped from the mud pits through the drill string where it sprays out of nozzles on the drill bit, cleaning and cooling the drill bit in the process.

• The mud then carries the crushed or cut rock ("cuttings") up the annular space ("annulus") between the drill string and the sides of the hole being drilled, up through the surface casing, where it emerges back at the surface.

• Cuttings are then filtered out with either a shale shaker, or the newer shale conveyor technology, and the mud returns to the mud pits.

• The mud pits let the drilled "fines" settle; the pits are also where the fluid is treated by adding chemicals and other substances.

• The returning mud can contain natural gases or other flammable materials which will collect in and around the shale shaker / conveyor area or in other work areas.

• Because of the risk of a fire or an explosion if they ignite, special monitoring sensors and explosion-proof certified equipment is commonly installed, and workers are advised to take safety precautions.

• The mud is then pumped back down the hole and further re-circulated.

• After testing, the mud is treated periodically in the mud pits to ensure properties which optimize and improve drilling efficiency, borehole stability, and other requirements listed below.

Function

Remove cuttings from well• Drilling fluid carries the rock excavated by the drill bit up to

the surface. • Its ability to do so depends on cutting size, shape, and

density, and speed of fluid traveling up the well (annular velocity).

• These considerations are analogous to the ability of a stream to carry sediment; large sand grains in a slow-moving stream settle to the stream bed, while small sand grains in a fast-moving stream are carried along with the water.

• The mud viscosity is another important property, as cuttings will settle to the bottom of the well if the viscosity is too low.

Other properties include:

• Most drilling muds are thixotropic (viscosity increase during static conditions).

• This characteristic keeps the cuttings suspended when the mud is not flowing during, for example, maintenance.

• Fluids that have shear thinning and elevated viscosities are efficient for hole cleaning.

• Higher annular velocity improves cutting transport.

• Transport ratio (transport velocity / lowest annular velocity) should be at least 50%.

• High density fluids may clean hole adequately even with lower annular velocities (by increasing the buoyancy force acting on cuttings).

• But may have a negative impact if mud weight is in excess of that needed to balance the pressure of surrounding rock (formation pressure), so mud weight is not usually increased for hole cleaning purposes.

• Higher rotary drill-string speeds introduce a circular component to annular flow path.

• This helical flow around the drill-string causes drill cuttings near the wall, where poor hole cleaning conditions occur, to move into higher transport regions of the annulus.

• Increased rotation is the one of the best methods for increasing hole cleaning in high angle and horizontal wells.

Suspend and release cuttings• Must suspend drill cuttings, weight materials and additives under

a wide range of conditions.• Drill cuttings that settle can causes bridges and fill, which can

cause stuck-pipe and lost circulation.• Weight material that settles is referred to as sag, this causes a

wide variation in the density of well fluid, this more frequently occurs in high angle and hot wells.

• High concentrations of drill solids are detrimental to:– Drilling efficiency (it causes increased mud weight and

viscosity, which in turn increases maintenance costs and increased dilution)

– Rate of Penetration (ROP) (increases horsepower required to circulate)

– Mud properties that are suspended must be balanced with properties in cutting removal by solids control equipment

• For effective solids controls, drill solids must be removed from mud on the 1st circulation from the well.

• If re-circulated, cuttings break into smaller pieces and are more difficult to remove.

• Conduct a test to compare the sand content of mud at flow line and suction pit (to determine whether cuttings are being removed).

Control formation pressures

• If formation pressure increases, mud density should also be increased to balance pressure and keep the wellbore stable.

• The most common weighting material is barite. • Unbalanced formation pressures will cause an

unexpected influx (also known as a kick) of formation fluids in the wellbore possibly leading to a blowout from pressured formation fluids.

• Hydrostatic pressure = density of drilling fluid * true vertical depth * acceleration of gravity.

• If hydrostatic pressure is greater than or equal to formation pressure, formation fluid will not flow into the wellbore.

• Well control means no uncontrollable flow of formation fluids into the wellbore.

• Hydrostatic pressure also controls the stresses caused by tectonic forces, these may make wellbores unstable even when formation fluid pressure is balanced.

• If formation pressure is subnormal, air, gas, mist, stiff foam, or low density mud (oil base) can be used.

• In practice, mud density should be limited to the minimum necessary for well control and wellbore stability.

• If too great it may fracture the formation.

Seal permeable formation

• Mud column pressure must exceed formation pressure, in this condition mud filtrate invades the formation, and a filter cake of mud is deposited on the wellbore wall.

• Mud is designed to deposit thin, low permeability filter cake to limit the invasion.

• Problems occur if a thick filter cake is formed; tight hole conditions, poor log quality, stuck pipe, lost circulation and formation damage.

• In highly permeable formations with large bore throats, whole mud may invade the formation, depending on mud solids size;– Use bridging agents to block large opening, then mud

solids can form seal.– For effectiveness, bridging agents must be over the half

size of pore spaces / fractures.– Bridging agents (e.g. calcium carbonate, ground

cellulose).

• Depending on the mud system in use, a number of additives can improve the filter cake (e.g. bentonite, natural & synthetic polymer, asphalt and gilsonite).

Minimizing formation damage

• Skin damage or any reduction in natural formation porosity and permeability (washout) constitutes formation damage

• Skin damage is the accumulation of residuals on the perforations and that causes a pressure drop through them .

• Most common damage;– Mud or drill solids invade the formation matrix, reducing porosity

and causing skin effect– Swelling of formation clays within the reservoir, reduced 

permeability– Precipitation of solids due to mixing of mud filtrate and formations

fluids resulting in the precipitation of insoluble salts– Mud filtrate and formation fluids form an emulsion, reducing

reservoir porosity

• Specially designed drill-in fluids or workover and completion fluids, minimize formation damage.

Cool, lubricate, and support the bit and drilling assembly

• Heat is generated from mechanical and hydraulic forces at the bit and when the drill string rotates and rubs against casing and wellbore.

• Cool and transfer heat away from source and lower to temperature than bottom hole.

• If not, the bit, drill string and mud motors would fail more rapidly.

• Lubrication based on the coefficient of friction. Oil- and synthetic-based mud generally lubricate better than water-based mud (but the latter can be improved by the addition of lubricants).

• Amount of lubrication provided by drilling fluid depends on type & quantity of drill solids and weight materials + chemical composition of system.

• Poor lubrication causes high torque and drag, heat checking of the drill string, but these problems are also caused by key seating, poor hole cleaning and incorrect bottom hole assemblies design.

• Drilling fluids also support portion of drill-string or casing through buoyancy.

• Suspend in drilling fluid, buoyed by force equal to weight (or density) of mud, so reducing hook load at derrick.

• Weight that derrick can support limited by mechanical capacity, increase depth so weight of drill-string and casing increase.

• When running long, heavy string or casing, buoyancy possible to run casing strings whose weight exceed a rig's hook load capacity.

Transmit hydraulic energy to tools and bit

• Hydraulic energy provides power to mud motor for bit rotation and for MWD (measurement while drilling) and LWD (logging while drilling) tools.

• Hydraulic programs base on bit nozzles sizing for available mud pump horsepower to optimize jet impact at bottom well.

• Limited to:– Pump horsepower– Pressure loss inside drillstring– Maximum allowable surface pressure– Optimum flow rate– Drill string pressure loses higher in fluids higher densities, plastic

viscosities and solids.

• Low solids, shear thinning drilling fluids such as polymer fluids, more efficient in transmit hydraulic energy.

• Depth can be extended by controlling mud properties.• Transfer information from MWD & LWD to surface by pressure pulse.

Ensure adequate formation evaluation

• Chemical and physical mud properties and wellbore conditions after drilling affect formation evaluation.

• Mud loggers examine cuttings for mineral composition, visual sign of hydrocarbons and recorded mud logs of lithology, ROP, gas detection or geological parameters.

• Wireline logging measure – electrical, sonic, nuclear and magnetic resonance.

• Potential productive zone are isolated and performed formation testing and drill stem testing.

• Mud helps not to disperse of cuttings and also improve cutting transport for mud loggers determine the depth of the cuttings originated.

• Oil-based mud, lubricants, asphalts will mask hydrocarbon indications.• So mud for drilling core selected base on type of evaluation to be

performed (many coring operations specify a blend mud with minimum of additives).

Control corrosion (in acceptable level)

• Drill-string and casing in continuous contact with drilling fluid may cause a form of corrosion.

• Dissolved gases (oxygen, carbon dioxide, hydrogen sulfide) cause serious corrosion problems;– Cause rapid, catastrophic failure– May be deadly to humans after a short period of time

• Low pH (acidic) aggravates corrosion, so use corrosion coupons to monitor corrosion type, rates and to tell correct chemical inhibitor is used in correct amount.

• Mud aeration, foaming and other O2 trapped conditions cause corrosion damage in short period time.

• When drilling in high H2S, elevated the pH fluids + sulfide scavenging chemical (zinc).

Facilitate cementing and completion

• Cementing is critical to effective zone and well completion.

• During casing run, mud must remain fluid and minimize pressure surges so fracture induced lost circulation does not occur.

• Mud should have thin, slick filter cake, wellbore with no cuttings, cavings or bridges.

• To cement and completion operation properly, mud displace by flushes and cement. 

• For effectiveness;– Hole near gauges– Mud low viscosity– Mud non progressive gel strength

Minimize impact on environment

• Mud is, in varying degrees, toxic. • It is also difficult and expensive to dispose of it in

an environmentally friendly manner. • A Vanity Fair article described the conditions at 

Lago Agrio, a large oil field in Ecuador where drillers were effectively unregulated.

4.2 Drilling Fluids Circulation System

4.3 Main Factors Influencing Drilling Fluids Performance

• Silicate-Based Drilling FluidsIt has been known since the 1920s that water-based drilling fluids formulated with potassium or sodium silicate provide superior shale stability, regardless of shale type.  

• Eighty years later, silicates are still recognized as the most effective water-based shale inhibitor.  

• PQ silicates are non-toxic and one of the few oil field chemicals that can be beneficial to the environment both on-land and offshore. 

• PQ’s EcoDrill® line of sodium and potassium silicate products allows for service companies to further customize the drilling fluid to maximize performance and reduce drilling fluid costs.  

4.4 Drilling Fluids Programs

4.5 Loss Circulation Problem

Lost circulation

• Loss of circulation is the uncontrolled flow of whole mud into a formation, sometimes referred to as a “thief zone.”

• This article discusses causes, prevention, and remedial measures for lost circulation.

Lost-circulation zones

• Fig. LCZ shows partial and total lost-circulation zones. • In partial lost circulation, mud continues to flow to surface

with some loss to the formation. • Total lost circulation, however, occurs when all the mud

flows into a formation with no return to surface. • If drilling continues during total lost circulation, it is

referred to as blind drilling. This is not a common practice in the field, unless all of the following criteria are met:• The formation above the thief zone is mechanically stable.• There is no production.• The fluid is clear water.• It is economically feasible and safe.

Fig. LCZ—Lost-circulation zones.

Causes of lost-circulation zones

There are several situations that can result in lost circulation:• Formations that are inherently fractured,

cavernous, or have high permeability• Improper drilling conditions• Induced fractures caused by excessive downhole

pressures and setting intermediate casing too high

Module (05) Downhole Fundamentals

5.1 Loss Circulation Material

• The collective term for substances added to drilling fluids when drilling fluids are being lost to the formations downhole.

• Commonly used lost-circulation materials include are fibrous (cedar bark, shredded cane stalks, mineral fiber and hair), flaky (mica flakes and pieces of plastic or cellophane sheeting) or granular (ground and sized limestone or marble, wood, nut hulls, Formica, corncobs and cotton hulls).

• Laymen have likened lost-circulation materials to the "fix-a-flat" materials for repair of automobile tires.

5.2 Drilling Fluids System Components

5.3 Well Killing & Securing Methodologies

Well kill

• A well kill is the operation of placing a column of heavy fluid into a well bore in order to prevent the flow of reservoir fluids without the need for pressure control equipment at the surface.

• It works on the principle that the hydrostatic head of the "kill fluid" or "kill mud" will be enough to suppress the pressure of the formation fluids.

• Well kills may be planned in the case of advanced interventions such as workovers, or be contingency operations.

• The situation calling for a well kill will dictate the method taken.• Not all well kills are deliberate. • Sometimes, the unintended buildup of fluids, either from injection of chemicals like 

methanol from surface, or from liquids produced from the reservoir, can be enough to kill the well, particularly gas wells, which are notoriously easy to kill.

5.4 Formation Damage impact on Well Killing and Prevention

Formation damage

• Producing formation damage has been defined as the impairment of the unseen by the inevitable, causing an unknown reduction in the unquantifiable.

• In a different context, formation damage is defined as the impairment to reservoir (reduced production) caused by wellbore fluids used during drilling/completion and workover operations.

• It is a zone of reduced permeability within the vicinity of the wellbore (skin) as a result of foreign-fluid invasion into the reservoir rock.

• Typically, any unintended impedance to the flow of fluids into or out of a wellbore is referred to as formation damage.

• This broad definition includes flow restrictions caused by a reduction in permeability in the near-wellbore region, changes in relative permeability to the hydrocarbon phase, and unintended flow restrictions in the completion itself.

• Flow restrictions in the tubing or those imposed by the well partially penetrating a reservoir or other aspects of the completion geometry are not included in this definition because, although they may impede flow, they either have been put in place by design to serve a specific purpose or do not show up in typical measures of formation damage such as skin.

Preventing formation damage

Over the last five decades, a great deal of attention has been paid to formation damage issues for two primary reasons:• Ability to recover fluids from the reservoir is affected very

strongly by the hydrocarbon permeability in the near-wellbore region

• Although we do not have the ability to control reservoir rock properties and fluid properties, we have some degree of control over drilling, completion, and production operations

• Thus, we can make operational changes, minimize the extent of formation damage induced in and around the wellbore, and have a substantial impact on hydrocarbon production.

• Being aware of the formation damage implications of various drilling, completion, and production operations can help in substantially reducing formation damage and enhancing the ability of the well to produce fluids.

Formation skin damage

Fig. FSD: Formation skin damage

Fig. FSD illustrates formation skin damage

Damage mechanisms

Formation damage is a combination of several mechanisms including:• Solids plugging. Fig. FD shows that the plugging

of the reservoir-rock pore spaces can be caused by the fine solids in the mud filtrate or solids dislodged by the filtrate within the rock matrix.

• To minimize this form of damage, minimize the amount of fine solids in the mud system and fluid loss.

• See Drilling induced formation damage

Fig FD: Formation damage caused by solids plugging.

Clay-particle swelling or dispersion. • This is an inherent problem in sandstone that contains water-

sensitive clays. • When a fresh-water filtrate invades the reservoir rock, it will cause

the clay to swell and thus reduce or totally block the throat areas. • See Formation damage from swelling clays.Saturation changes. • Production is predicated on the amount of saturation within the

reservoir rock. • When a mud-system filtrate enters the reservoir, it will cause

some change in water saturation and, therefore, potential reduction in production. 

• Fig. FDS shows that high fluid loss causes water saturation to increase, which results in a decrease of rock relative permeability.

Fig. FDS—Formation damage caused by saturation.

Wettability reversal

• Reservoir rocks are water-wet in nature. • It has been demonstrated that while drilling with oil-

based mud systems, excess surfactants in the mud filtrate that enter the rock can cause wettability reversal.

• It has been reported from field experience and demonstrated in laboratory tests that as much as 90% in production loss can be caused by this mechanism.

• Therefore, to guard against this problem, the amount of excess surfactants used in oil-based mud systems should be kept at a minimum.

• See Additional causes of formation damage

• Emulsion blockage. Inherent in an oil-based system is the use of excess surfactants. These surfactants enter the rock and can form an emulsion within the pore spaces, which hinders production through emulsion blockage.

• See Additional causes of formation damage• Aqueous-filtrate blockage. While drilling with

water-based mud, the aqueous filtrate that enters the reservoir can cause some blockage that will reduce the production potential of the reservoir.

• See Additional causes of formation damage

• Mutual precipitation of soluble salts in wellbore-fluid filtrate and formation water. Any precipitation of soluble salts, whether from the use of salt mud systems or from formation water or both, can cause solids blockage and hinder production.

• Fines migration. Build up of fine particles, particularly in sandstone reservoirs, can significantly reduce well productivity.

• See Formation damage from fines migration

• Deposition of paraffins or asphaltenes. Paraffins and asphaltenes can deposit both in tubing and in the pores of the reservoir rock, significantly limiting well productivity.

• See Formation damage from paraffins and asphaltenes• Condensate banking. A buildup of condensate around

the wellbore can impede gas flow by reducing permeability.

• See Formation damage from condensate banking• Other causes. These can include bacterial plugging

and gas breakout. • See Additional causes of formation damage

Quantifying formation damage

• A commonly used measure of well productivity is the productivity index, J, in barrels per pounds per square inch:

• The most commonly used measure of formation damage in a well is the skin factor, S.

• The skin factor is a dimensionless pressure drop caused by a flow restriction in the near-wellbore region.

• It is defined as follows (in field units):

• Fig. P shows how flow restrictions in the near-wellbore region can increase the pressure gradient, resulting in an additional pressure drop caused by formation damage (Δpskin).

Fig. P—Pressure profile in the near-wellbore region for an ideal well and a well with formation damage.

• In 1970, Standing introduced the important concept of well flow efficiency, F, which he defined as

• Clearly, a flow efficiency of 1 indicates an undamaged well with Δpskin = 0, a flow efficiency > 1 indicates a stimulated well (perhaps because of a hydraulic fracture), and a flow efficiency < 1 indicates a damaged well.

• Note that, to determine flow efficiency, we must know the average reservoir pressure, pR, and skin factor, S.

• Methods to measure these quantities are discussed in Determination of flow efficiency and skin.

• The impact of skin on well productivity can be estimated by the use of inflow performance relationships(IPRs) for the well such as those proposed by Vogel, Fetkovich, and Standing. 

• These IPRs can be summarized as follows

where

• When x = 0, a linear IPR model is recovered; • when x = 0.8, we obtain Vogel's IPR; • and when x = 1, Fetkovich's IPR model is

obtained. • An example of a plot for the dimensionless

hydrocarbon production as a function of the dimensionless bottomhole pressure (IPR) is shown in Fig. IPR for different flow efficiencies.

• It is evident that, as flow efficiency decreases, smaller and smaller hydrocarbon rates are obtained for the same drawdown

Drawdown

Fig. IPR—Inflow performance relations for different flow efficiencies(F).

Vogel IPR

• The pressure can drop below the bubble point pressure. • As a result, the gas comes out of solution from the oil and a progressive

deterioration of the inflow performance relationship is found. • In the following picture, a straight line IPR and one with reduced

performance due to resistance are presented.

• The choice of the IPR used depends on the fluid properties and reservoir drive mechanism.

• Standing's IPR is most appropriate for solution-gas-drive reservoirs, whereas a linear IPR is more appropriate for waterdrive reservoirs producing at pressures above the bubblepoint and for hydrocarbons without substantial dissolved gas.

• A more detailed discussion of this is provided in Peters

Formation damage vs. pseudo damage

• It is important to clearly distinguish formation damage from well completion and reservoir effects that are a consequence of how the wellbore penetrates the reservoir and where the perforations are placed (sometimes referred to as pseudoskin effects) and permeability loss as a result of depletion. 

• Reservoir engineering models for limited-entry flow in partially penetrating wells are presented in several reservoir engineering texts such as Dake.

• The second major cause of pseudoskin is high-velocity flows near the wellbore, which induces turbulence or inertial effects.

• As discussed in the previous section, turbulence or inertial effects can lead to an additional turbulent pressure drop that needs to be clearly distinguished from the pressure drop induced by a reduction in permeability.

• Finally, flow restrictions in the wellbore itself such as chokes, scale buildup, wax, or asphaltene deposits can often result in tubing pressure drops that are substantially larger than anticipated.

• This reduction in well productivity is not commonly referred to as formation damage.

• Other types of production impairment caused within the tubing are collapsed tubing or flow restrictions caused by mechanical restrictions such as:

• Corrosion products• Poor cement jobs, resulting in commingling of

produced fluids from different zones• Insufficient tubing diameter or improper design

of artificial lift systems

• This partial list provides some examples of flow restrictions caused primarily in the tubing and should not typically be categorized as formation damage.

• They do not show up in measures of formation damage such as skin, which are primarily measures of flow restrictions in the near-wellbore region.

• Flow restrictions in the completion itself such as the compacted zone around perforation tunnels and plugged gravel packs are included in Determination of flow efficiency and skin because they typically are measured as a well skin.

Nomenclature

B = proportional to the non-Darcy coefficient, D

F = well flow efficiency

k = overall permeability, md

pR = average reservoir pressure

pwf = flowing bottomhole pressure

ΔPskin = additional pressure drop caused by formation damage

q = flow rate

qo = oil flow rate

S = skin factor

J = productivity index

See also

• Determination of flow efficiency and skin• Formation damage in injection wells• Formation damage from perforating and cem

enting• Formation damage from completion workover

fluids• Drilling induced formation damage• Drilling problems• PEH:Drilling Problems and Solutions• PEH:Formation Damage• Category: 1.8 Formation Damage

5.5 Pressure Basics and Basis

Fundamental concepts and terminology

• Pressure is a very important concept in the oil and gas industry.

Pressure can be defined as: • The force exerted per unit area. • Its SI unit is newtons per square metre or pascals. • Another unit, bar, is also widely used as a measure

of pressure, with 1 bar equal to 100 kilopascals. • Normally pressure is measured in the U.S.

petroleum industry in units of pounds force per square inch of area, or psi. 1000 q psi equals 6894.76 pascals.

Hydrostatic pressure

• Hydrostatic pressure (HSP), as stated, is defined as pressure due to a column of fluid that is not moving.

• That is, a column of fluid that is static, or at rest, exerts pressure due to local force of gravity on the column of the fluid.

• The formula for calculating hydrostatic pressure in SI units (kg/m²) is:

• Hydrostatic pressure = Height (m) × Density (kg/m³) × Gravity (m/s²).

• All fluids in a wellbore exert hydrostatic pressure, which is a function of density and vertical height of the fluid column.

• In US oil field units, hydrostatic pressure can be expressed as:

• HSP = 0.052 × MW × TVD', where MW (Mud Weight or density) is the drilling-fluid density in pounds per gallon (ppg), TVD is the true vertical depth in feet and HSP is the hydrostatic pressure in psi.

The 0.052 is needed as the conversion factor to psi unit of HSP.• To convert these units to SI units, one can use:• 1 ppg = ≈ 119.8264273 kg/m3

• 1 ft = 0.3048 metres• 1 psi = 0.0689475729 bar• 1 bar = 105 pascals

Pressure gradient

• The pressure gradient is described as the pressure per unit length.

• Often in oil well control, pressure exerted by fluid is expressed in terms of its pressure gradient.

• The SI unit is pascals/metre. • The hydrostatic pressure gradient can be written as:• Pressure gradient (psi/ft) = HSP/TVD = 0.052 × MW

(ppg).

Formation pressure

• Formation pressure is the pressure exerted by the formation fluids, which are the liquids and gases contained in the geologic formations encountered while drilling for oil or gas.

• It can also be said to be the pressure contained within the pores of the formation or reservoir being drilled.

• Formation pressure is a result of the hydrostatic pressure of the formation fluids, above the depth of interest, together with pressure trapped in the formation.

• Under formation pressure, there are 3 levels: normally pressured formation, abnormal formation pressure, or subnormal formation pressure.

Normally pressured formation

• Normally pressured formation has a formation pressure that is the same with the hydrostatic pressure of the fluids above it.

• As the fluids above the formation are usually some form of water, this pressure can be defined as the pressure exerted by a column of water from the formation's depth to sea level.

• The normal hydrostatic pressure gradient for freshwater is 0.433 pounds per square inch per foot (psi/ft), or 9.792 kilopascals per meter (kPa/m), and 0.465 psi/ft for water with dissolved solids like in Gulf Coast waters, or 10.516 kPa/m.

• The density of formation water in saline or marine environments, such as along the Gulf Coast, is about 9.0 ppg or 1078.43 kg/m³.

• Since this is the highest for both Gulf Coast water and fresh water, a normally pressured formation can be controlled with a 9.0 ppg mud.

• Sometimes the weight of the overburden, which refers to the rocks and fluids above the formation, will tend to compact the formation, resulting in pressure built-up within the formation if the fluids are trapped in place.

• The formation in this case will retain its normal pressure only if there is a communication with the surface.

• Otherwise, an abnormal formation pressure will result.

Abnormal formation pressure

• As discussed above, once the fluids are trapped within the formation and not allow to escape there is a pressure build-up leading to abnormally high formation pressures.

• This will generally require a mud weight of greater than 9.0 ppg to control.

• Excess pressure, called "overpressure" or "geopressure", can cause a well to blow out or become uncontrollable during drilling.

Subnormal formation pressure

• Subnormal formation pressure is a formation pressure that is less than the normal pressure for the given depth.

• It is common in formations that had undergone production of original hydrocarbon or formation fluid in them.

Overburden pressure

• Overburden pressure is the pressure exerted by the weight of the rocks and contained fluids above the zone of interest.

• Overburden pressure varies in different regions and formations. • It is the force that tends to compact a formation vertically. • The density of these usual ranges of rocks is about 18 to 22 ppg

(2,157 to 2.636 kg/m3). • This range of densities will generate an overburden pressure

gradient of about 1 psi/ft (22.7 kPa/m). • Usually, the 1 psi/ft is not applicable for shallow marine sediments

or massive salt. • In offshore however, there is a lighter column of sea water, and the

column of underwater rock does not go all the way to the surface. • Therefore, a lower overburden pressure is usually generated at an

offshore depth, than would be found at the same depth on land.

Mathematically, overburden pressure can be derived as:

S = ρb× D×gwhereg = acceleration due to gravityS = overburden pressureρb = average formation bulk densityD = vertical thickness of the overlying

sediments

The bulk density of the sediment is a function of rock matrix density, porosity within the confines of the pore spaces, and pore fluid density.

This can be expressed as:

ρb = φρf + (1 – φ)ρm whereφ = rock porosityρf = formation fluid densityρm = rock matrix density

Fracture pressure

• Fracture pressure can be defined as pressure required to cause a formation to fail or split.

• As the name implies, it is the pressure that causes the formation to fracture and the circulating fluid to be lost.

• Fracture pressure is usually expressed as a gradient, with the common units being psi/ft (kg/m) or ppg (kPa).

To fracture a formation, three things are generally needed, which are:• Pump into the formation. This will require a pressure in the

wellbore greater than formation pressure.• The pressure in the wellbore must also exceed the rock matrix

strength.• And finally the wellbore pressure must be greater than one of

the three principal stresses in the formation

Pump pressure (system pressure losses)

• Pump pressure, which is also referred to as system pressure loss, is the sum total of all the pressure losses from the oil well surface equipment, the drill pipe, the drill collar, the drill bit, and annular friction losses around the drill collar and drill pipe.

• It measures the system pressure loss at the start of the circulating system and measures the total friction pressure.

Slow pump pressure (SPP)

• Slow pump pressure is the circulating pressure (pressure used to pump fluid through the whole active fluid system, including the borehole and all the surface tanks that constitute the primary system during drilling) at a reduced rate.

• SPP is very important during a well kill operation in which circulation (a process in which drilling fluid is circulated out of the suction pit, down the drill pipe and drill collars, out the bit, up the annulus, and back to the pits while drilling proceeds) is done at a reduced rate to allow better control of circulating pressures and to enable the mud properties (density and viscosity) to be kept at desired values.

• The slow pump pressure can also be referred to as "kill rate pressure" or "slow circulating pressure" or "kill speed pressure" and so on.

Shut-in drill pipe pressure

• Shut-in drill pipe pressure (SIDPP), which is recorded when a well is shut in on a kick, is a measure of the difference between the pressure at the bottom of the hole and the hydrostatic pressure (HSP) in the drill pipe.

• During a well shut-in, the pressure of the wellbore stabilizes, and the formation pressure equals the pressure at the bottom of the hole.

• The drill pipe at this time should be full of known-density fluid.

• Therefore, the formation pressure can be easily calculated using the SIDPP.

• This means that the SIDPP gives a direct of formation pressure during a kick.

Shut-in casing pressure (SICP)

• The shut-in casing pressure (SICP) is a measure of the difference between the formation pressure and the HSP in the annulus when a kick occurs.

• The pressures encountered in the annulus can be estimated using the following mathematical equation:

• FP = HSPmud + HSPinflux + SICP, where

• FP = formation pressure (psi)• HSPmud = Hydrostatic pressure of the mud in the

annulus (psi)• HSPinflux = Hydrostatic pressure of the influx (psi)

• SICP = shut-in casing pressure (psi)

Bottom-hole pressure (BHP)

• Bottom-hole pressure (BHP) is the pressure at the bottom of a well. The pressure is usually measured at the bottom of the hole. This pressure may be calculated in a static, fluid-filled wellbore with the equation:

• BHP = D × ρ × C, where• D = the vertical depth of the well• ρ = density• C = units conversion factor• (or, in the English system, BHP = D × MWD × 0.052).

• In Canada the formula is depth in meters x density in kgs x the constant gravity factor (0.00981), which will give the hydrostatic pressure of the well bore or (hp) hp=bhp with pumps off.

• The bottom-hole pressure is dependent on the following:

• Hydrostatic pressure (HSP)• Shut-in surface pressure (SIP)• Friction pressure• Surge pressure (occurs when transient pressure

increases the bottom-hole pressure)• Swab pressure (occurs when transient pressure

reduces the bottom-hole pressure)• Therefore BHP can be said to be the sum of all pressures at

the bottom of the wellhole, which equals:• BHP = HSP + SIP + friction + Surge – Swab• Oil well control

Mathematically, overburden pressure can be derived as:

5.6 Case Study

• Deepwater Disaster - BP Oil Spill (Documentary)• 60 Minutes - BP Oil Disaster "Poison Tide“• Oil Spill LIVE feed: BP awaits 'Top Kill' results• Proposal to Kill Deepwater Horizon Well• Solution for Stopping the Gulf Oil Spill - Part 1:

How To Slow The BP Oil Slick• Top Kill Fails - Solution for Stopping the Gulf Oil

Spill - Part 2: How To Stop The BP Oil Leak

Module (06) Managed Pressure Drilling (MPD)

Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.

Managed pressure drilling

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underbalanced drilling.

* geophysical well logging * under reaming following multistage underbalanced drilling * cement plug placing * emergency and fishing operations * selection criteria for well bore candidates * job planning and risk analysis * CT ground equipment * coiled tubing pipes * coiled tubing machinery (capillary units, injectors, reels etc.) * equipment for flow control and completion (drilling motors, drilling jars, intensifiers, reamers, Collars, etc.) * high tech drilling bits 

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Nitrogen equipment application for coiled tubing drilling 

* gas liquid mixtures * nitrogen compressor stations * pumping units * vaporiser systems for CT * continuous circulation systems and agitators * management and control systems 

Separation systems for drilling fluids 

* centrifuges * hydrocyclones * shakers * pumps * management and control 

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Geophysical well logging

- Schlumberger brothers, Conrad and Marcel, are credited with inventing electrical well-logs.

- On September 5, 1927, the first “well-logA” was created in a small village named Pechelbroon in France.

- In 1931, the first SP (spontaneous potential) log was recorded. Discovered when the galvanometer began “wiggling” even though no current was being applied.

- The SP effect was produced naturally by the borehole mud at the boundaries of permeable beds. By simultaneously recording SP and resistivity, loggers could distinguish between permeable oil-bearing beds and impermeable nonproducing beds.

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Types of Logs

a) Gamma Rayb) SP (spontaneous potential)c) Resistivity (Induction) d) Sonice) Density/Neutronf) Caliper

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a) Gamma Ray

The gamma ray measures the natural radioactivity of the rocks, and does not measure any hydrocarbon or water present within the rocks.

Shales: radioactive potassium is a common component, and because of their cation exchange capacity, uranium and thorium are often absorbed as well.

Therefore, very often shales will display high gamma ray responses, while sandstones and limestone will typically show lower responses.

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The scale for GR is in API (American Petroleum Institute) and runs from 0-125 units. There are often 10 divisions in a GR log, so each division represents 12.5 units.

Typical distinction between between a sandstone/limestone and shale occurs between 50-60 units.

Often, very clean sandstones or carbonates will display values within the 20 units range.

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b) SP (Spontaneous Potential)

The SP log records the electric potential between an electrode pulled up a hole and a reference electrode at the surface.

This potenital exists because of the electrochemical differences between the waters within the formation and the drilling mud.

The potenital is measured in millivolts on a relative scale only since the absolute value depends on the properties of the drilling mud.

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In shaly sections, the maximum SP response to the right can be used to define a “shale line”.

Deflections of the SP log from this line indicates zones of permeable lithologies with interstitial fluids containing salinities differing from the drilling fluid.

SP logs are good indicators of lithology where sandstones are permeable and water saturated.

However, if the lithologies are filled with fresh water, the SP can become suppressed or even reversed. Also, they are poor in areas where the permeabilities are very low, sandstones are tighly cemented or the interval is completely bitumen saturated (ie- oil sands).

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c) Resistivity (Induction)

Resistivity logs record the resistance of interstitial fluids to the flow of an electric current, either transmitted directly to the rock through an electrode, or magnetically induced deeper into the formation from the hole.

Therefore, the measure the ability of rocks to conduct electrical currents and are scaled in units of ohm-meters.

On most modern logs, there will be three curves, each measuring the resistance of section to the flow of electricity.

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Porous formations filled with salt water (which is very common) have very low resistivities (often only ranging from 1-10 ohms-meter).

Formations that contain oil/gas generally have much higher resisitivities (often ranging from 10-500 ohms-meter).

With regards to the three lines, the one we are most interested in is the one marked “deep”. This is because this curve looks into the formation at a depth of six meters (or greater), thereby representing the portion of the formation most unlikely undisturbed by the drilling process.

One must be careful of “extremely” high values, as they will often represent zones of either anhydrite or other non-porous intervals.

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d) Sonic

Sonic logs (or acoustic) measure the porosity of the rock. Hence, they measure the travel time of an elastic wave through a formation (measured in ∆T- microseconds per meter).

Intervals containing greater pore space will result in greater travel time and vice versa for non-porous sections.

Must be used in combination with other logs, particularly gamma rays and resistivity, thereby allowing one to better understand the reservoir petrophysics.

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e) Density/Neutron

Density logs measure the bulk electron density of the formation, and is measured in kilograms per cubic meter (gm/cm3 or kg/m3).

Thus, the density tool emits gamma radiation which is scattered back to a detector in amounts proportional to the electron density of the formation. The higher the gamma ray reflected, the greater the porosity of the rock.

Electron density is directly related to the density of the formation (except in evaporates) and amount of density of interstitial fluids.

Helpful in distinguishing lithologies, especially between dolomite (2.85 kg/m3) and limestone (2.71 kg/m3)

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Neutron Logs measure the amounts of hydrogen present in the water atoms of a rock, and can be used to measure porosity. This is done by bombarding the the formation with neutrons, and determing how many become “captured” by the hydrogen nuclei.

Because shales have high amounts of water, the neutron log will read quite high porosities- thus it must be used in conjunction with GR logs.

However, porosities recorded in shale-free sections are a reasonable estimate of the pore spaces that could produce water.

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It is very common to see both neutron and density logs recorded on the same section, and are often shown as an overlay on a common scale (calibrated for either sandstones or limestone’s).

This overlay allows for better opportunity of distinguishing lithologies and making better estimates of the true porosity.

* When natural gas is present, there becomes a big spread (or crossing) of the two logs, known as the “gas effect”.

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f) Caliper

Caliper Logs record the diameter of the hole. It is very useful in relaying information about the quality of the hole and hence reliability of the other logs.

An example includes a large hole where dissolution, caving or falling of the rock wall occurred, leading to errors in other log responses.

Most caliper logs are run with GR logs and typically will remain constant throughout

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Underbalanced drilling 

Though not as common as overbalanced drilling, underbalanced drilling is achieved when the pressure exerted on the well is less than or equal to that of the reservoir.

Performed with a light-weight drilling mud that applies less pressure than formation pressure, underbalanced drilling prevents formation damage that can occur during conventional, or overbalanced drilling processes.

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• The negative differential pressure obtained during underbalanced drilling between the reservoir and the wellbore encourages production of formation fluids and gases.

• In contrast to conventional drilling, flow from the reservoir is driven into the wellbore during underbalanced drilling, rather than away from it.

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underbalanced drilling.

Managed pressure drilling systems. Multilateral wells. Coiled tubing

underbalanced drilling.

Although initially more costly, underbalanced drilling, also known as managed-pressure drilling, reduces common conventional drilling problems, such as lost circulation, differential sticking, minimal drilling rates and formation damage.

Additionally, underbalanced drilling extends the life of the drill bit because the drilling gases cool the bit while quickly removing cuttings.

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To establish pressure control, a rotating control head with a rotating inner seal assembly is used in conjunction with the rotating table.

An important factor to successful underbalanced drilling, drilling and completion operations must remain underbalanced at all times during operations.

To accomplish this, pre-planning and onsite engineering are critical to the success of underbalanced drilling procedures.

Typically used for only a section of the entire drilling process, underbalanced drilling cannot be used in most shale environments

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Underbalance Gases

• Gases used for underbalance include air, nitrogen and natural gas. Although it is not typical, if natural gas is recovered from the well, it can be reinjected into the well to establish underbalance, resulting in the most cost-effective solution for underbalanced drilling.

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• Commonly used in under balance operations, nitrogen is preferred for its somewhat low cost of generation, scale of control and minimal potential for downhole fires.

• While pure nitrogen can be purchased, it is cost-prohibitive.

• Therefore, nitrogen is more commonly produced onsite with a membrane unit, resulting in a 95% level of purity.

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Underbalance Techniques

There are four main techniques to achieve underbalance, including using light weight drilling fluids, gas injection down the drill pipe, gas injection through a parasite string and foam injection.

Using lightweight drilling fluids, such as fresh water, diesel and lease crude, is the simplest way to reduce wellbore pressure.

A negative for this approach is that in most reservoirs the pressure in the wellbore cannot be reduced enough to achieve under balance.

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The method of injecting gas down the drillpipe involves adding air or nitrogen to the drilling fluid that is pumped directly down the drillpipe.

Advantages to this technique include improved penetration, decreased amount of gas required, and that the wellbore does not have to be designed specifically for underbalanced drilling.

On the other hand, disadvantages include the risk of overbalance conditions during shut-in and the requirement of rare MWD tools.

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• In performing the gas injection via parasite string, a second pipe is run outside of the intermediate casing.

• While the cost of drilling increases, as does the time it takes, this technique applies constant bottom hole pressure and requires no operational differences or unique MWD systems.

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A less common underbalanced application, nitrogen foam is less damaging to reserves that exhibit water sensitivities.

While the margin of safety is increased using foams, the additional nitrogen needed to generate stable foam makes this technique cost prohibitive.

Additionally, there are temperature limits to using foam in underbalanced drilling, limiting using the technique to wells measuring less than 12,000 feet deep.

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How Does Fishing Work?

There are a number of problems that can occur while drilling a well.

Whether a drill string breaks and falls to the bottom of the wellbore or a bit breaks, accidents happen.

Even pipe or a tool can fall from the rig floor into the bottom of the well.

This stray equipment that has fallen into the well is referred to as fishor junk, and regular drill bits cannot drill through it.

Should a fish fall into a well, fishing is required to remove it.

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Fishing tools

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underbalanced drilling.

In order to perform fishing on a well, drilling must be shelved and special fishing tools employed.

Each tool is specially crafted to perform a specific function, or retrieve a certain type of fish.

Most fishing tools are screwed into the end of a fishing string, similar to drillpipe, and lowered into the well.

There are two options to recover lost pipe. The first is a spear, which fits within the pipe and

then grips the pipe from the inside. On the other hand, an overshoot may be employed,

and this tool surrounds the pipe and grips it from the outside to carry it up the wellbore.

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When a fish is difficult to grip, a washover pipe or washpipe is used.

Made of large-diameter pipe with a cutting surface at the tip, washpipe is run in the well and then the cutting edge grinds the fish to a smooth surface.

Then drilling fluids are pumped into the well to remove debris, and another tool is used to retrieve the remaining fish.

Sometimes, a junk mill and boot basket are used to retrieve fish from the wellbore.

In this instance, a junk mill is lowered into the well and rotated to grind the fish into smaller pieces.

A boot basket, also known as a junk basket, is then lowered into the well.

Drilling fluid is pumped into the well, and the ground parts of the fish are raised into the basket and then to the surface by the boot basket.

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In order to recover casing that has collapsed within the well or irregularly shaped fish, a tapered mill reamer can be used.

Permanent and magnetic magnets are employed to reclaim magnetic fish, and a wireline spear uses hooks and barb to clasp broken wireline.

Additionally, an explosive might be detonated within the well to break the fish up into smaller pieces, and then a tool such as a junk bucket is used to retrieve the smaller items.

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• When a fishing professional is unable to determine which fishing tool might work best to retrieve the fish, an impression block is used to get an impression of the fish and allow the professional to know with what exactly he or she is dealing.

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• Fishing a well may take days to complete, and during this time, drilling cannot occur, although the operator is still responsible for drilling fees.

• Some drilling contractors offer fishing insurance, making operators not responsible for rig fees during fishing operations.

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Statoil records first successful North Sea HP/HT coiled tubing milling job

Telemetry proves critical for intervention at Kvitebjoern on Norwegian continental shelf

Statoil learned valuable lessons during the planning and execution of a high pressure/high-temperature (HP/HT) coiled tubing milling job on the Norwegian continental shelf (NCS) in the North Sea at Kvitebjørn field.

Kvitebjørn is a Statoil-operated gas and condensate field in block 34/11 with a reservoir at about 4,000 m (13,120 ft) with pressure of 770 bar (11,168 psi) and temperature of 160º C (320º F).

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Well 34/11-A-9 T2 was drilled as a gas producer and during the final completion phase, it was not possible through pressure cycling to open the HP/HT isolation ball valve set in the 9 7/8-in. liner at 6,245.7 m (20,486 ft) MD/3,795.8 m (12,450 ft) TVD.

After several failed attempts with wireline using mechanical override tools, it was decided to punch above it to allow well production passing the outside of the valve through the annulus between 9 7/8-in. liner and the 5½-in. tail pipe.

However, the production performance was poor. A feasibility study evaluated ways to open or mill

out the valve with the objective to improve the production characteristics and to allow access for future production logging.

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The decision was to mill the stuck-closed isolation ball valve using coiled tubing (CT).

Statoil had not performed any HP/HT CT operations and the available experience was limited.

To minimize uncertainty relating to depth determination during milling, a telemetry system ran at its operational pressure and temperature limits to provide real-time casing collar locator (CCL) readings in addition to downhole pressure and temperature data.

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The Super 13% chrome, 110 Kpsi yield isolation ball valve was stuck closed at a deviation of 57.8º. Its ID when open is 4.25-in with a drift ID = 4.151 in. The EOF seating nipple at 6,223 m (20,411 ft) MD from the rig kelly bushing was ID = 4.31 in., which represents the minimum wellbore restriction from surface down to the ball valve depth.

The 34/11-A-9 T2 well is in the Statfjord formation with the top of perforations at 4,313 m (14,147 ft) TVD. The original prognosed reservoir pressure was 770 +45/-14 bar (11,168 + 653/-203 psi) and the downhole temperature at reservoir was 160º C. The shut-in wellhead pressure was 571 bar (8,282 psi) in March 2011. The expected downhole temperature at the ball valve was 145º C (293º F). The H2S and CO2 concentrations in the produced gas were less than 5 ppm and a concentration of 3.477 mol %, respectively.

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A feasibility study including an onshore milling test evaluated the possibility of milling the isolation ball valve with an electrical mill assembly run on mono-conductor wireline cable. The report concluded with large uncertainty regarding the number of bailer runs necessary to remove debris above the valve and reach milling depth, as well as the lifetime for the electrical milling equipment at the very high downhole temperature. Based on this study and the low estimated likelihood of success (30 -- 40%), the Kvitebjørn license decided not to proceed with the wireline alternative.

New feasibility studies evaluated using CT, rig-assisted snubbing, and the rig for opening or milling out the isolation ball valve.

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Wellbore schematic.

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The CT alternative seemed to be feasible since similar jobs were performed at lower temperature and shallower depths, but the 15K psi well control equipment and CT string design would have to be specified and sourced specifically for the job.

The main drawbacks for the rig-assisted snubbing were the drilling crew's rig-assisted snubbing experience, rig-assisted snubbing personnel experience, ram-to-ram stripping experience, and HP/HT well conditions.

For the rig alternative, the main risks were gas migration to the surface in addition to more time and cost relating to killing the well.

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Well control stack as built

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• It was decided that the primary method to be further evaluated and developed for removal of the ball valve restriction from the well would be CT, the secondary method would be rig-assisted snubbing and the final method would be to use the rig.

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Concept selection

During the concept selection phase, the recommended method for deploying CT to remove the isolation ball valve from the wellbore consisted of the following steps:

Pre-CT job "pump and bleed“ operation. Displacing the wellbore from the current gas by repeatedly bullheading 1.044 sg 40/60% MEG/fresh water from the kill wing valve of the christmas tree and bleeding the gas that migrates to surface. The aim of this "pump and bleed" step was to reduce the surface shut-in wellhead pressure (SIWHP) to the minimum before running the CT. This had advantages in safety and operations.

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CT drift and cleanout run(s). The well was producing intermittently for few months through punched holes above the closed ball valve. It was suspected that fill and debris might have settled above the ball valve with the 11.5-m (38-ft) interval between the punched holes and top of the ball valve being particularly vulnerable. Offshore crane capacity limits and the long CT string needed to reach the ball valve at 6,245.7 m (20,492 ft) MD RKB, the maximum CT string size that could be shipped in one piece was 2- in. OD. The well completion from surface to approximately the ball valve depth was 7 in., 35 lb/ft tubing with a 6-in. ID. Therefore, it was impossible to generate enough turbulence in the annulus between the tubing and CT to lift any fill or debris when run in hole (RIH) with the milling bottom hole assembly (BHA) to mill the ball valve. It was decided to RIH first with a with venturi jet junk basket (VJJB) to drift and clean out the wellbore to the top of the ball valve.

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CT milling run(s). This was the ultimate run to achieve the job objective and mill the ball valve. The motor needed to provide enough torque to mill through the ball valve. In addition, its operating pump rate should be achievable through the specially designed 2-in. CT string. A yard test and a successful milling job of a similar ball valve in a well operated by Shell in the British section of the North Sea were on record. The mill was a 4.1-in. OD dome profile ball mill run with a hydraulically (pump rate) operated shifting tool and an anti-stall tool. All lessons learned during this Shell job were taken into account for this Kvitebjørn CT project. The mill was designed and tested to mill through the ball valve material. The mill size for this Kvitebjørn job was decided to be 4-in. OD to deploy the milling BHA through the 41⁄16-in. 15K psi CT BOP. This mill size is big enough to allow later production logging tools to run through the milled hole. This critical detailed planning phase took approximately five months. It consisted of organizing several meetings and coordinating between different departments, disciplines, and third parties.

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Offshore execution

• The job went as planned. The CT job was carried out through the drilling rig. The ball valve was successfully milled and drifted with the 4-in mill and the access to the lower wellbore was regained.

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CT equipment layout on pipe deck.

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No serious HSE & Q incidents were reported during this first HP/HT CT job in Statoil and the Norwegian continental shelf with a high operating factor of 96.2%.

The total job duration was 31.6 days with equipment rig up including "pump and bleed" of 10.9 days; one VJJB clean up run and three milling runs totaling 9.1 days; extra production test and one extra drift run with VJJB through and below the milled ball valve, 6.1 days; and equipment rig down and back load, 5.5 days.

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Operational risk analysis

An operational risk analysis log sheet and risk register covering the different steps of the operation was elaborated during detailed planning. This was important because this was the first HP/HT CT operation in Statoil and in the NCS.

The risk assessment involved representatives from all concerned disciplines within Statoil, including reservoir, well intervention, drilling and production, plus Statoil discipline advisors for CT, well intervention, well integrity, HP/HT, and well control, as well as third-parties representatives for CT services and the rig contractor.

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The probability and the potential impact for each initial risk were assessed using a standard risk tolerance matrix. Prevention and mitigation actions were identified for each risk with the objective of reducing the probability and/or the potential impact of the corresponding risk.

This resulted in a detailed operational risk register including 41 identified hazards and 84 risk prevention and/or mitigation measures that were implemented during the planning and execution phases.

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This risk register was sub-divided into 11 sections as following:

1. Mobilization and demobilization2. Spotting and equipment rig up3. "Pump and bleed" operation4. VJJB drift and cleanout run(s)5. Milling run(s)6. Well control stack up7. BHAs8. Fluids9. Contingency scenarios10. Rig down equipment11. Simultaneous contingency situations in A-9 T2 and a second well.

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Lessons learned

There were a number of lessons learned on this project. They key lessons are described below.

Telemetry tool performance. The telemetry tool provided valuable CCL data to correlate the depth down to the ball valve. The telemetry tool failed in three of four runs at a bottomhole temperature around 145ºC (293º F). However, the CCL logging signal failed after the initial depth correlation. The telemetry tool was running properly for its first few hours of exposure under extreme downhole pressure and temperature conditions before it failed. It was a known and accepted risk prior to operation that the tool might fail if exposed to downhole conditions close to or above its operational specifications of 8,000 psi/150º C (55 MPa/305º F) for a prolonged time. It could be concluded from the data that the telemetry tool operated properly up to 564 bar (8,180 psi) and 146º C (295º F) before failure.

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Equipment availability. The equipment availability for this special and non-frequent HP/HT CT job was a challenge. Early planning and ordering of some critical equipment was vital, especially knowing the day rate of the drilling derrick to be used. This critical equipment included both CT strings, the gas tested 71⁄16-in./15K psi gate valve, the safety head handler, the gas-tested christmas tree crossover, and the 21⁄16-in 15K psi gas tested gate valves. Weekly meetings to review critical items were held with the CT contractor. The need for long lead items was identified early in the project, and Statoil issued purchase orders for relevant equipment.

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Site surveys. Three site surveys were carried out by Statoil and CT contractor representatives to avoid conflict with platform interfaces, and to identify any limitations or special requirements.

Personnel HP/HT training. Two full-day sessions of CT awareness and HP/HT seminars were organized and presented by the CT contractor to all involved personnel before the job start up.

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Bleed off procedure. The bleed off needed to avoid explosive decompression of well control equipment elastomers was not provided by the CT contractor. Rather, the local platform best practice used during wireline operations was followed during this CT job. For future CT HP/HT operations, the bleed off procedure should be based on recommendations from the original equipment manufacturer for standard and high-pressure well conditions, respectively.

Pump and bleed operation. Liquid losses into formation were experienced during the "pump and bleed" phase and it was not possible to reduce the WHP. It was decided to abort the pump and bleed operation and to start running in the well while circulating through the CT. This alternative was effective in reducing the WHP.

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• CT weight simulations. A drag reduction by 25% (from 0.24 to 0.18) was observed when displacing the wellbore with metal-to-metal friction reducer while RIH from 4,200 m (13,776 ft) MD RKB to the ball valve. Data proves that the actual CT RIH and pick up weights were within the operating limit at 80% yield of CT string material.

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Milling through the ball valve. It was difficult to control the weight on bit (WOB) at 6,245 m (20,484 ft) MD while pumping 40/60% MEG/fresh water at 400 l/m pump rate and at 340 to 375 bar (4,931 to 5,439 psi) CT circulation pressure. During the first milling run, the WOB was set down gradually but the motor stalled 15 times. The first milling BHA was pulled to surface for inspection. During the second milling run, milling was carried out with patience for longer periods without increasing the WOB. Vibration and an anti-stall tool was expected to provide sufficient WOB. The top part of the ball valve was milled during the second run in approximately 12 hours and the bottom part in an additional 12 hours. The experience gained from the first milling run was used to optimize the milling parameters of the second and third milling runs, and succeeded to break through the ball valve with the 4-in. mill at the end.

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• Confirmed milled ball valve. A 3D multi-finger caliper log was run on wireline two months after the CT milling job to investigate the wellbore status, particularly the milled ball valve area. The ball valve was confirmed to be milled out with a minimum ID of 3.97 in. at 6,245.7 m MD.

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Conclusion

This CT project represents an excellent reference for future HP/HT CT operations for Statoil in Norway and worldwide. The job execution was performed as planned and in compliance with the relevant industry standards and local regulations. The stuck closed isolation ball valve was successfully milled and drifted with the 4-in. dome profile mill. No serious HSE&Q incidents were reported during this first HP/HT CT job in the Norwegian continental shelf, which had a high operating factor of 96.2%. Valuable lessons learned from the planning and execution phases of this challenging operation should be useful in future similar HP/HT CT applications.

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Coil tubing equipment

• Hydra Rig Trailer mounted 2” CT unit, two trailer design, 22,000 feet reel capacity, 80,000 lbs. pull injector and 50 ton crane

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• Hydra Rig 6100 CT Injector with tubing straightener and leveling lift bale

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• Offshore 1¼” CT Unit

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• Hydra Rig Trailer Mounted Sichuan CTU

• Hydra Rig Trailer Mounted CTU and pumper on location in Turkestan

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• Hydra Rig Intermediate size trailer-mounted CTU with crane, 635 injector

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• Hydra Rig’s new 55,000 sq. ft. final assembly and CTU maintenance facility

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• CTD horizontal re-entry project, with NOV Hydra Rig coiled tubing unit, nitrogen unit, and NOV Rolligon pumping unit. Also utilized are NOV Texas Oil Tools BOPs and NOV CTES DAS system.

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• Hydra Rig Mini Coil Drop In Drum

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• Hydra Rig Mini Coil 420C Injector Head

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• Hydra Rig Mini Coil Unit

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Snubbing UnitsNOV Hydra Rig Snubbing Units have earned a

reputation worldwide for high performance and versatility in

the field. Rig-up is fast due to lightweight, compact design

and the elimination of the need to “kill” the well.NOV Hydra Rig Snubbing Units are engineered to

work on any pressure well, with pipe sized up to 8s”, and

pulls up to 600,000 lbs.With over 200 units manufactured, our snubbing

units are the industry standard.

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Coring and drilling

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• Hydraulic fracturing

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• Shaker

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Module (07) Rig Inspection

7.1 Inspection Concept and Objectives

Shell Eco-marathon - Technical Inspection

Oil & Gas Rig Inspection

Drill Pipe Inspection - Electromagnetic Inspection (EMI)

In-Line Inspection of Unpiggable Pipelines - InVista

Tesoro - In Line Inspection

Oil & Gas Rig Inspection Checklist for Drilling & Well Servicing Operations

Inspection

• An inspection is, most generally, an organized examination or formal evaluation exercise.

• In engineering activities inspection involves the measurements, tests, and gauges applied to certain characteristics in regard to an object or activity.

• The results are usually compared to specified requirements and standards for determining whether the item or activity is in line with these targets, often with a Standard Inspection Procedure in place to ensure consistent checking.

• Inspections are usually non-destructive.

• Inspections may be a visual inspection or involve sensing technologies such as ultrasonic testing, accomplished with a direct physical presence or remotely such as a remote visual inspection, and manually or automatically such as an automated optical inspection.

• A 2007 Scottish Government review of scrutiny of public services (the Crear Review, 2007) defined inspection of public services as "... periodic, targeted scrutiny of specific services, to check whether they are meeting national and local performance standards, legislative and professional requirements, and the needs of service users."

• A surprise inspection tends to have different results than an announced inspection.

• Leaders wanting to know how others in their organization perform can drop in without warning, to see directly what happens.

• If an inspection is made known in advance, it can give people a chance to cover up or to fix mistakes.

• This could lead to distorted and inaccurate findings. • A surprise inspection, therefore, gives inspectors a

better picture of the typical state of the inspected object or process than an announced inspection.

• It also enhances external confidence in the inspection process. See section 4.12 of the Crear report.

Engineering, mechanics

• A mechanical inspection is usually undertaken to ensure the safety or reliability of structures or machinery.

• In Europe bodies involved in engineering inspection may be assessed by accreditation bodies according to ISO 17020 "General criteria for the operation of various types of bodies performing inspection".

• This standard defines inspection as "examination of a product, process, service, or installation or their design and determination of its conformity with specific requirements or, on the basis of professional judgment, with general requirements".

• Main article: nondestructive testing

• Non-destructive examination (NDE) or nondestructive testing (NDT) is a family of technologies used during inspection to analyze materials, components and products for either inherent defects (such as fractures or cracks), or service induced defects (damage from use).

• Some common methods are visual, industrial computed tomography scanning,microscopy, dye penetrant inspection, magnetic-particle inspection, X-ray or radiographic testing, ultrasonic testing, eddy-current testing, acoustic emission testing, and thermographic inspection.

• In addition, many non-destructive inspections can be performed by a precision scale, or when in motion, a checkweigher. 

• Stereo microscopes are often used for examining small products like circuit boards for product defects.

• Inspection and technical assistance during turnarounds helps to decrease costly downtime as well as ensures restart of operations quickly and safely.

7.2 Inspection Practices, Standards and Principles

OSHA Inspection Practices and Policies

• When the Occupational Safety and Health Administration (OSHA) comes knocking, what are the practices and policies a facility should expect?

• The OSHA inspector is there for one of two reasons: to conduct a programmed inspection or an un-programmed inspection.

• A programmed inspection is when the inspection is scheduled due to selection criteria by OSHA.

• This criteria may be injury rates, death rates, exposure to toxic substances or a high amount of lost workdays for the type of industry you are in.

• An un-programmed inspection can come from one of three prioritized occurrences.

• The first is imminent danger. • An imminent danger is any condition where there is reasonable

certainty that a danger exists that can be expected to cause death or serious harm immediately or before it can be eliminated through normal enforcement procedures.

• If a compliance officer finds an imminent danger situation, they would ask the employer to voluntarily abate the hazard and remove employees from exposure If the employer fails to do so, OSHA may apply to the Federal District Court for an injunction prohibiting further work as long as the hazardous conditions persist. 

• The second priority goes to the investigation of fatalities and accidents resulting in the death or hospitalization of 3 or more employees. 

• Such accidents must be reported to OSHA by the employer within 8 hours. 

• OSHA would then investigate the cause of the accident and whether or not any existing OSHA standards were violated. 

• The third priority is when an employee gives a formal complaint to OSHA regarding a possible unsafe working condition or if the employee feels he/she is in imminent danger at the workplace.

• When an OSHA inspection is going to be conducted, there are aspects of the OSHA inspection that you should know and understand.

• If the inspector does not have a warrant, you do not have to let the inspector into the facility.

• This is your 4th amendment constitutional right. • It is your decision whether to require a warrant or voluntarily consent

to an inspection.• OSHA issues an inspection checklist, but they also advise inspectors to

develop their own policies. • The topics a checklist may include are listed below. • It would be wise to prepare detailed area self-inspection lists for your

operations and have employees from that area take turns checking for any hazards they encounter on a weekly basis.

• This would help employees work safer and become familiar with any violations in their immediate work area.

• In addition, the facility would always be ready for an OSHA inspection.

This list is not all-inclusive, but these are the main topic areas that should be part of your

internal inspection:• EMPLOYEE POSTING• RECORDKEEPING• LOCKOUT TAGOUT PROCEDURES• HAZARD COMMUNICATION• SAFETY AND HEALTH PROGRAMS• MEDICAL SERVICES AND FIRST AID• FIRE PROTECTION• PERSONAL PROTECTIVE EQUIPMENT AND CLOTHING• GENERAL WORK ENVIRONMENT• WALKWAYS• FLOOR AND WALL OPENINGS• STAIRS AND STAIRWAYS• ELEVATED SURFACES• EXITING OR EGRESS• EXIT DOORS• PORTABLE LADDERS• HAND TOOLS AND EQUIPMENT• POWER-OPERATED TOOLS AND EQUIPMENT• ABRASIVE WHEEL EQUIPMENT• POWER-ACTUATED TOOLS

• MACHINE GUARDING• WELDING, CUTTING AND BRAZING• COMPRESSORS AND COMPRESSED AIR• COMPRESSED GAS CYLINDERS• HOIST EQUIPMENT• INDUSTRIAL TRUCKS/ FORKLIFTS• SPRAYING OPERATIONS• CONFINED SPACES• FLAMMABLE AND COMBUSTIBLE MATERIALS• HAZARDOUS CHEMICAL EXPOSURE• ELECTRICAL• NOISE• FUELING• IDENTIFICATION OF PIPING SYSTEMS• MATERIAL HANDLING• TRANSPORTING EMPLOYEES AND MATERIALS• VENTILATION• SANITIZING EQUIPMENT AND CLOTHING

• To prepare for an OSHA inspection, designate your representative prior to the inspector's arrival.

• Instruct the reception area to inform the representative when the inspector arrives.

• The representative should check the inspector's credentials bearing a photograph and serial number with the nearest OSHA office.

• The inspector should be accompanied by your representative at all times.

• The representative should be the same person throughout the inspection (two or more representatives could provide conflicting information).

• If at any time the representative has difficulty responding to a question, he/she should call for a "time out" and get help.

• The representative may then go to a telephone and call for advice from an attorney or trusted knowledgeable source.

• Once the inspector is in, the protocol that is followed will consist of an opening conference, a tour of the facility and a closing conference.

7.4 Inspection Procedures

Standard Inspection Procedure

• A standard inspection procedure (or sometimes just 'SIP') is a process by which a number of variables may be checked for compliance against a set of rules.

• SIPs are used by various organizations including the Commercial Vehicle Safety Alliance (CVSA) and the U.S. 

7.5 Inspection Checklists

http://www.ccohs.ca/oshanswers/hsprograms/list_gen.html

• Please see the following other OSH Answers for more specific examples:

• Inspection Checklists - Sample Checklist for Manufacturing Facilities

• Inspection Checklists - Sample Checklist for Offices

https://www.youtube.com/watch?v=3HXvsScqSi8

7.6 Types of Rig Inspection

• Rig Check was developed by the National Institute for Occupational Safety and Health (NIOSH) in partnership with safety experts from the oil and gas extraction industry.

• It is made up of 35 inspection forms. • The forms are designed to be used by rig workers

to document the inspection of tools and equipment commonly found on rotary and workover rigs.

• Each inspection form includes instructions for assessing and recording the condition of the equipment.

• When applicable, relevant federal regulations and industry recommended practices are included.

• The Rig Check inspection forms are an excellent training tool for short service employees, who may not be familiar with the tools and equipment found on oil and gas rigs.

• Small companies whose safety and health resources are limited may find Rig Check useful for enhancing their HSE programs.

• The forms can also be downloaded from the NIOSH website at: www.cdc.gov/niosh/programs/oilgas/products.html

https://www2.worksafebc.com/PDFs/Petroleum/RigInspectionChecklist.pdf

http://www.slideshare.net/LREnergy/rig-inspection-training-overview?next_slideshow=1

7.7 Qualifications Required for Rig Inspection

• Inspect the rig and all components mechanically and electrically, utilizing a comprehensive checklist to determine the condition of the equipment.

• Formulate a corrective action plan that can be implemented prior to startup and while on contract.

• Analyze the contractors maintenance policies and procedures to assess the effectiveness of the maintenance program.

• Ensure that the maintenance program is being implemented at the rig level. Evaluate critical spares inventory.

• Evaluate rig equipment and capabilities to assign a job rating based on your drilling program.

• Determination is made as to whether the rig can meet the operational requirements.

• Submit a detailed report and verbally review the finding with you and the contractor management.

• Perform rig equipment and acceptance testing.• Conduct pre hire and periodic surveys.• Assist you and the contractor in developing and implementing a plan to correct any

problems.• New construction Rig Commissioning and final acceptance.• Conduct detailed and comprehensive HSE survey using Rig QA checklists that are

presently being adopted as a standard by a major oil company.

7.8 Existing Practices Compared to Industrial Standards

• Occupational Health & Safety (OHSAS18001) • Environment Management System (ISO14001) • Quality Management System (ISO9001 & ISO/TS 29001)Preventive Maintenance Management System management system audits assess the following elements: • Leadership & Commitment • Policy & Strategic Objectives • Organization • Resources and Documentation • Evaluation and Risk Management • Planning & Procedures • Implementation & Monitoring • Auditing & Reviewing

OHSAS18001

ISO 14001 - the world's EMS standard (International Organization for Standardization)

ISO 9001:2015

ISO/TS 29001:2010

• Petroleum, petrochemical and natural gas industries

• Sector• Specific quality management systems• Requirements for product and service supply

organizations

Abstract

• ISO/TS 29001:2010 defines the quality management system for product and service supply organizations for the petroleum, petrochemical and natural gas industries.

• Boxed text is original ISO 9001:2008 text unaltered and in its entirety.

• The petroleum, petrochemical, and natural gas industry sector-specific supplemental requirements are outside the boxes.

Module (08) Rig Maintenance

8.1 Maintenance Concept and Objectives

Oil Rig Equipment Maintenance Plans and Job Plans

Offshore oil drilling companies require maintenance programs that meet client equipment requirements, safety requirements and the following regulatory and classification society requirements:• International Maritime Organizations (IMO)• American Bureau of Shipping (ABS)• United States Coast Guard (USCG)• DNV Classification• Health, Safety and Environmental (HSE)

Standards

• Collect rig equipment nameplate and configuration information

• Develop equipment inventory/hierarchy

• Develop Equipment Maintenance Plans (EMPs) for maintainable assets

• Develop maintenance plans/job plans, in agreed-upon format from finalized EMP

• Recommend any Predictive Maintenance (PdM) plans/job plans

• Review client comments and finalize maintenance plans/job plansSubmit finalized maintenance plans/job plans

• Generator Preventive Maintenance

8.2 Maintenance Practices and Standards

Rig inspection standards – onshore Queensland • AS/NZS standards, including AS/NZS 1020, 1418,

1470, 1768, 2319, 3000 • API standards • IEC/IEE/IEEE standards • NDT inspections and various certifications • Maintenance practices and records • Any internal standards possessed by the client

relevant to drilling • If authorized for release to Modu Spec, the technical

terms of the contract between the drilling contractor and operator.

• Equipment manufacturer's specifications and recommendations • ModuSpec catalogue of industry best practice, which includes

alerts and information from Cameron, Hydril, IADC, NOV etc. • Queensland Petroleum Acts (Queensland Petroleum Act 1923,

Production and Safety Act 2004 etc.) • Queensland Operating Plant Code of Practice 2008 • Availability of risk assessments for the rig’s safety management

plan • Queensland Workplace Health and Safety Regulation 1997 • Any Queensland mining regulations deemed relevant to coal

bed methane drilling (i.e. Coal Mining Safety & Health Act 1999, Mining and Quarrying Safety and Health Act 1999)

• Queensland Transport Operations (Road Use Management) Act 1995

8.3 Maintenance Procedures

• This Technical Measures Document refers to the maintenance procedures that are necessary to mitigate a major accident or hazard.

• See also Technical Measures Documents on:• Permit to Work systems• Inspection / Non-Destructive Testing (NDT)• Plant modification / Change procedures

General principles

The following aspects should be considered with respect to Maintenance Procedures:• Human factors;• Poorly skilled work force;• Unconscious and conscious incompetence;• Good maintainability principles;• Knowledge of failure rate and maintainability; and• Clear criteria for recognition of faults and marginal

performance.

The following issues may contribute towards a major accident or hazard:

• Failure of safety critical equipment due to lack of maintenance;

• Human error during maintenance;• Static or spark discharge during maintenance in an

intrinsically safe zone;• Incompetence of maintenance staff; and• Poor communication between maintenance and

production staff.

Contributory factors for an assessor to consider concerning maintenance procedures

The Safety Report should address the following points:• Whether the company maintenance regimes (planned,

risk-based, reliability centred, condition based or breakdown maintenance) are adequate for each plant item which has a safety function;

• Whether proof check periods quoted for safety critical items are adequate to ensure risks are within acceptable limits;

• Whether the procedures to ensure quoted proof check periods for safety critical items are adhered to;

• Whether the company Safety Management System includes adequate consideration of maintenance of plant, instrumentation and electrical systems;

• Whether maintenance staff have been sufficiently trained to recognise plant or equipment failing during maintenance inspections;

• Whether maintenance staff have been sufficiently informed, instructed, trained and supervised to minimise a potential human failing during maintenance;

• Whether maintenance schedules are managed and regularly inspected and reviewed;

• Whether Human factors (stress, fatigue, shift work, attitude) are addressed;

• Whether sufficient precautions are taken prior to maintenance of hazardous plant and equipment (isolation, draining, flushing, environmental monitoring, risk assessments, permits to work, communication, time allotted for the work);

• Whether the maintenance staff are aware of the type of environment they are working in (flammable, corrosive, explosive, zones 0, 1 & 2);

• Whether the maintenance staff use the correct equipment in the workplace during re-conditioning, replacement and re-commissioning (static free, intrinsically safe, flameproof, PPE/RPE);

• Whether sufficient maintenance systems are in place during productive assistance, servicing, running of plant, plant shutdown and plant breakdown;

• Whether procedures are in place to provide detailed operating instructions for re-commission plant after maintenance, which have been subjected to risk assessments (see Technical Measures Document on Plant Modification / Change Procedures);

• Whether sufficient reporting systems are in place so that corrective maintenance can be applied to mitigate a major accident or hazard.

8.4 Maintenance Checklists

Maintenance Checklist

• Maintain your equipment to prevent future problems and unwanted costs.

• Keep your cooling and heating system at peak performance by having a contractor do annual pre-season check-ups.

• Contractors get busy once summer and winter come, so it's best to check the cooling system in the spring and the heating system in the fall.

• To remember, you might plan the check-ups around the time changes in the spring and fall.

A typical maintenance check-up should include the following.

• Check thermostat settings to ensure the cooling and heating system keeps you comfortable when you are home or at work and saves energy while you are away.

• Tighten all electrical connections and measure voltage and current on motors. Faulty electrical connections can cause unsafe operation of your system and reduce the life of major components.

• Lubricate all moving parts. Parts that lack lubrication cause friction in motors and increases the amount of electricity you use.

• Check and inspect the condensate drain in your central air conditioner, furnace and/or heat pump (when in cooling mode). A plugged drain can cause water damage in the house and affect indoor humidity levels.

• Check controls of the system to ensure proper and safe operation. Check the starting cycle of the equipment to assure the system starts, operates, and shuts off properly.

Cooling Specific

• Clean evaporator and condenser air conditioning coils. Dirty coils reduce the system's ability to cool your home and cause the system to run longer, increasing energy costs and reducing the life of the equipment.

• Check your central air conditioner's refrigerant level and adjust if necessary. Too much or too little refrigerant will make your system less efficient increasing energy costs and reducing the life of the equipment.

• Clean and adjust blower components to provide proper system airflow for greater comfort levels. Airflow problems can reduce your system's efficiency by up to 15 percent.

Heating Specific

• Check all gas (or oil) connections, gas pressure, burner combustion and heat exchanger. Improperly operating gas (or oil) connections are a fire hazard and can contribute to health problems. A dirty burner or cracked heat exchanger causes improper burner operation. Either can cause the equipment to operate less safely and efficiently.

• Actions: Inspect, clean, or change air filters once a month in your central air conditioner, furnace, and/or heat pump. Your contractor can show you how to do this. A dirty filter can increase energy costs and damage your equipment, leading to early failure.

8.5 Types of Rig Maintenance

Types of maintenance

• 1. Breakdown maintenance It means that people waits until equipment fails and repair it. Such a thing could be used when the equipment failure does not significantly affect the operation or production or generate any significant loss other than repair cost.

• 2. Preventive maintenance (1951) It is a daily maintenance ( cleaning, inspection, oiling and re-tightening ), design to retain the healthy condition of equipment and prevent failure through the prevention of deterioration, periodic inspection or equipment condition diagnosis, to measure deterioration. It is further divided into periodic maintenance andpredictive maintenance. Just like human life is extended by preventive medicine, the equipment service life can be prolonged by doing preventive maintenance.

• 2a. Periodic maintenance ( Time based maintenance - TBM) Time based maintenance consists of periodically inspecting, servicing and cleaning equipment and replacing parts to prevent sudden failure and process problems.

• 2b. Predictive maintenance This is a method in which the service life of important part is predicted based on inspection or diagnosis, in order to use the parts to the limit of their service life. Compared to periodic maintenance, predictive maintenance is condition based maintenance. It manages trend values, by measuring and analyzing data about deterioration and employs a surveillance system, designed to monitor conditions through an on-line system.

• 3. Corrective maintenance ( 1957 ) It improves equipment and its components so that preventive maintenance can be carried out reliably. Equipment with design weakness must be redesigned to improve reliability or improving maintainability

• 4. Maintenance prevention ( 1960 ) It indicates the design of a new equipment. Weakness of current machines are sufficiently studied ( on site information leading to failure prevention, easier maintenance and prevents of defects, safety and ease of manufacturing ) and are incorporated before commissioning a new equipment.

8.6 Existing Practices Compared to Industrial Standards

• Checklists and working instructions are developed in compliance with applicable standards upon request (API, IADC, ISO)

• Standards and regulations database with alerts for any standard revision Monitoring of ISO TC 67 publications

• Update of checklists and working instructions accordingly• Formal and on-the-job training of inspectors on standard

changes• Auditing of management systems as per applicable

standards (ISO 9001:2000, ISO 29001:2003, OHSAS 18001, ISO 14001:2004)

• Preventive maintenance system audits are developed with industry best practices and manufacturer recommendations.

Module (09) Basics of Well Intervention

9.1 Drilling Fluids Circulation System/Components

The main part in the picture:

• 1. Shale shaker• 8. Desander• 9. Desilter• 10. Centrifuge• 12. Mud pump• 20. Sludge pump• 23. Mud agitator• 27. Submersible pump.

9.2 Well Control Theory

Well control

• Well control is the technique used in oil and gas operations such as drilling, well work over, and well completions to maintaining the fluid column hydrostatic pressure and formation pressure to prevent influx of formation fluids into the wellbore.

• This technique involves the estimation of formation fluid pressures, the strength of the subsurface formations and the use of casing and mud density to offset those pressures in a predictable fashion.

• Understanding of pressure and pressure relationships are very important in well control.

Fluid Pressure• Fluid is any substance that flows; e.g. oil, water, gas, and ice

are all examples of fluids. • Under extreme pressure and temperature almost anything will

become fluid. • Fluid exerts pressure and this pressure is as a result of the

density and the height of the fluid column. • Most oil companies usually represent density measurement in

pounds per gallon (ppg) or kilograms per cubic meter (kg/m3) and pressure measurement in pounds per square inch (psi) or bar or pascal (Pa).

• Pressure increases as the density of the fluid increases. • To find out the amount of pressure a fluid of a known density

exerts for each unit of length, the pressure gradient is used. • A pressure gradient is defined as the pressure increase per unit

of the depth due to its density and it is usually measured in pounds per square inch per foot or bars per meter.

• It is expressed mathematically as; pressure gradient = fluid density × conversion factor.

• The conversion factor used to convert density to pressure is 0.052 in English system and 0.0981 in Metric system.

Hydrostatic pressure

• Hydro means water, or fluid, that exerts pressure and static means not moving or at rest.

• Therefore, hydrostatic pressure is the total fluid pressure created by the weight of a column of fluid, acting on any given point in a well.

• In oil and gas operations, it is represented mathematically as; • Hydrostatic pressure = pressure gradient × true vertical

depth • Hydrostatic pressure = fluid density × conversion factor

× true vertical depth .• Well X has measured depth of 9800 ft and a true vertical depth

of 9800 ft while well Y has measured depth of 10380 ft and its true vertical depth is 9800 ft.

• To calculate the hydrostatic pressure of the bottomhole, the true vertical depth is used because gravity acts (pulls) vertically down the hole. The figure also illustrates the difference between true vertical depth (TVD) and measured depth (MD).

Formation pressure

• Formation pressure is the pressure of the fluid within the pore spaces of the formation rock.

• This pressure can be affected by the weight of the overburden (rock layers) above the formation, which exerts pressure on both the grains and pore fluids.

• Grains are solid or rock material, and pores are spaces between grains.

• If pore fluids are free to move, or escape, the grains lose some of their support and move closer together.

• This process is called consolidation. • Depending on the magnitude of the pore pressure, it

can be described as being normal, abnormal or subnormal. 

• Normal pore pressure or formation pressure is equal to the hydrostatic pressure of formation fluid extending from the surface to the surface formation being considered.

• In other words, if the formation was opened up and allowed to fill a column whose length is equal to the depth of the formation, then the pressure at the bottom of the column will be equal to the formation pressure and the pressure at surface is equal to zero.

• Normal pore pressure is not a constant. • Its magnitude varies with the concentration of dissolved

salts, type of fluid, gases present and temperature gradient.

• When a normally pressured formation is raised toward the surface while prevented from losing pore fluid in the process, it will change from normal pressure (at a greater depth) to abnormal pressure (at a shallower depth).

• When this happens, and then one drill into the formation, mud weights of up to 20 ppg (2397 kg/m ³) may be required for control.

• This process accounts for many of the shallow, abnormally pressured zones in the world. In areas where faulting is present, salt layers or domes are predicted, or excessive geothermal gradients are known, drilling operations may encounter abnormal pressure. 

• Abnormal pore pressure is defined as any pore pressure that is greater than the hydrostatic pressure of the formation fluid occupying the pore space.

• It is sometimes called overpressure or geo pressure. • An abnormally pressured formation can often be predicted using well history,

surface geology, downhole logs or geophysical surveys. • Subnormal pore pressure is defined as any formation pressure that is less

than the corresponding fluid hydrostatic pressure at a given depth. • Subnormally pressured formations have pressure gradients lower than fresh

water or less than 0.433 psi/ft (0.0979 bar/m). • Naturally occurring subnormal pressure can be developed when the overburden

has been stripped away, leaving the formation exposed at the surface. • Depletion of original pore fluids through evaporation, capillary action and

dilution produces hydrostatic gradients below 0.433 psi/ft (0.0979 bar/m). • Subnormal pressures may also be induced through depletion of formation

fluids. • If Formation Pressure < Hydrostatic pressure then it is under pressured. • If Formation Pressure > Hydrostatic pressure then it is over pressured .

Fracture pressure• Fracture pressure is the amount of pressure it takes to permanently deform

the rock structure of a formation. • Overcoming formation pressure is usually not sufficient to cause fracturing. • If pore fluid is free to move, a slow rate of entry into the formation will not

cause fractures. • If pore fluid cannot move out of the way, fracturing and permanent

deformation of the formation can occur. • Fracture pressure can be expressed as a gradient (psi/ft), a fluid density

equivalent (ppg), or by calculated total pressure at the formation (psi). • Fracture gradients normally increase with depth due to increasing 

overburden pressure. • Deep, highly compacted formations can require very high fracture

pressures to overcome the existing formation pressure and resisting rock structure.

• Loosely compacted formations, such as those found offshore in deep water, can fracture at low gradients (a situation exacerbated by the fact that some of total "overburden" up the surface is sea water rather than the heavier rock that would be present in an otherwise-comparable land well).

• Fracture pressures at any given depth can vary widely because of the geology of the area.

Bottom hole pressure

• Bottom hole pressure is used to represent the sum of all the pressures being exerted at the bottom of the hole.

• Pressure is imposed on the walls of the hole. • The hydrostatic fluid column accounts for most of the pressure,

but pressure to move fluid up the annulus also acts on the walls.

• In larger diameters, this annular pressure is small, rarely exceeding 200 psi (13.79 bar).

• In smaller diameters it can be 400 psi (27.58 bar) or higher. • Backpressure or pressure held on the choke also increases

bottomhole pressure, which can be estimated by adding up all the known pressures acting in, or on, the annular (casing) side.

• Bottomhole pressure can be estimated during the following activities;

• Static well• If no fluid is moving, the well is static. The bottomhole pressure (BHP)

is equal to the hydrostatic pressure (HP) on the annular side. If shut in on a kick, bottomhole pressure is equal to the hydrostatic pressure in the annulus plus the casing (wellhead or surface pressure) pressure.

• Normal circulation• During circulation, the bottomhole pressure is equal to the hydrostatic

pressure on the annular side plus the annular pressure loss (APL).• Rotating head• During circulating with a rotating head the bottomhole pressure is

equal to the hydrostatic pressure on the annular side, plus the annular pressure loss, plus the rotating head backpressure.

• Circulating a kick out• Bottomhole pressure is equal to hydrostatic pressure on the annular

side, plus annular pressure loss, plus choke (casing) pressure. For subsea, add choke line pressure loss.

Formation integrity test• An accurate evaluation of a casing cement job as well as of the formation

is extremely important during the drilling of a well and for subsequent work.

• The Information resulting from Formation Integrity Tests (FIT) is used throughout the life of the well and also for nearby wells.

• Casing depths, well control options, formation fracture pressures and limiting fluid weights may be based on this information.

• To determine the strength and integrity of a formation, a Leak Off Test (LOT) or a Formation Integrity Test (FIT) may be performed.

• This test is first: a method of checking the cement seal between casing and the formation, and second: determining the pressure and/or fluid weight the test zone below the casing can sustain.

• Whichever test is performed, some general points should be observed. • The fluid in the well should be circulated clean to ensure it is of a known

and consistent density. • If mud is used for the test, it should be properly conditioned and gel

strengths minimized. • The pump used should be a high-pressure, low-volume test or cementing pump. • Rig pumps can be used if the rig has electric drives on the mud pumps, and they

can be slowly rolled over. • If the rig pump must be used and the pump cannot be easily controlled at low rates,

then the leak-off technique must be modified. It is a good idea to make a graph of the pressure versus time or volume for all leak-off tests.

The main reasons for performing formation integrity test (FIT) are:• To investigate the strength of the cement bond around

the casing shoe and to ensure that no communication is established with higher formations.

• To determine the fracture gradient around the casing shoe and therefore establish the upper limit of the primary well control for the open hole section below the current casing.

• To investigate well bore capability to withstand pressure below the casing shoe in order to validate or invalidate the well engineering plan regarding the casing shoe setting depth.

U-tube concepts• It is often helpful to visualize the well as a U-tube as in Figure

beside. Column Y of the tube represents the annulus and column X represents the pipe (string) in the well.

• The bottom of the U-tube represents the bottom of the well. • In most cases, there are fluids creating hydrostatic pressures in

both the pipe and annulus. • Atmospheric pressure can be omitted, since it works the same on

both columns. • If the fluid in both the pipe and annulus are of the same density,

hydrostatic pressures would be equal and the fluid would be static on both sides of the tube.

• If the fluid in the annulus is heavier, it will exert more pressure downward and will flow into the string, displacing some of the lighter fluid out of the string causing a flow at surface.

• The fluid level will fall in the annulus, equalizing pressures. • When there is a difference in the hydrostatic pressures, the fluid will try to

reach balance point. • This is called U-tubing, and it explains why there is often flow from the pipe

when making connections. • This is often evident when drilling fast because the effective density in the

annulus is increased by cuttings.

Pipe surge/swab• The total pressure acting on the wellbore is affected by pipe movement upwards or

downwards.• Tripping pipe into and out of a well is one other common operation during completions and

workovers. • Unfortunately, statistics indicate that most kicks occur during trips. • Therefore, understanding the basic concepts of tripping is a major concern in

completion/workover operations. • Downward movement of tubing(tripping in) creates a pressure that is exerted on the

bottom of a well. • As the tubing is being run into a well, the fluid in the well must move upward to exit the

volume being entered by the tubing.• The combination of the downward movement of the tubing and the upward movement of

the fluid (or piston effect) results in an increase in pressure at any given point in the well.• This increase in pressure is commonly called Surge pressure. • Upward movement of the tubing(tripping out) also affects the pressure which is imposed at the bottom of

the well. • When pulling pipe from the well,fluid must move downward and replace the volume which was occupied

by the tubing. The net effect of the upward movement of the tubing and the downward movement of the fluid creates a decrease in bottomhole pressure.

• This decrease in pressure is referred to as Swab pressure. 

Both surge and swab pressures are affected by the following parameters:

• Velocity of the pipe, or tripping speed• Fluid density• Fluid viscosity• Fluid gel strength• Well bore geometry (annular clearance between tools and casing,

tubing open ended or closed off)• The faster pipe is tripped, the higher the surge and swab pressure

effects will be. • Also, the greater the fluid density, viscosity and gel strength, the

greater the surge and swab tendency. • Finally, the downhole tools such as packers and scrapers,which have

small annular clearance, also increase surge and swab pressure effects.

• Determination of actual surge and swab pressures can be accomplished with the use of WORKPRO and DRILPRO calculator programs or hydraulics manuals.

• Differential pressure• In well control,it is defined as the difference

between the formation pressure and the bottomhole hydrostatic pressure. These are classified as overbalanced, underbalanced and balanced.

• Overbalanced differential pressure• It means the hydrostatic pressure exerted on the

bottom of the hole is greater than the formation pressure. i.e. HP > FP

• Underbalanced differential pressure• It means the hydrostatic pressure exerted on the

bottom of the hole is less than the formation pressure. i.e. HP < FP

• Balanced differential pressure• It means the hydrostatic pressure exerted on the bottom of

the hole is equal to the formation pressure. i.e. HP = FP

• Cuttings change: shape, size, amount, type• Cuttings are rock fragments chipped, scraped or crushed

away from a formation by the action of the bit. • The size, shape and amount of cuttings depend largely on

formation type, weight on the bit, bit dullness and the pressure differential (formation versus fluid hydrostatic pressures).

• The size of the cuttings usually decreases as the bit dulls during drilling if weight on bit, formation type and the pressure differential, remain constant.

• However, if the pressure differential changes (formation pressure increase), even a dull bit could cut more effectively, and the size, shape and amount of cuttings could increase.

Kick

• Kick is defined as an undesirable influx of formation fluid in to the wellbore.

• If left unchecked, a kick can develop into blowout (an uncontrolled influx of formation fluid in to the wellbore).

• The result of failing to control a kick leads to loss operation time, loss of well and quite possibly, the loss of the rig and lives of personnel.

Causes of kick

• Once the hydrostatic pressure is less than the formation pore pressure, formation fluid can flow into the well. This can happen when one or a combination of the following occurs;

• Not keeping the hole full• Insufficient Mud density• Swabbing/Surging• Lost circulation• Poor well planning

Deepwater Horizon drilling rig blowout, 21 April 2010

Not keeping the hole full

• When tripping out of the hole, the volume of the steel pipe being removed results in a corresponding decrease in wellbore fluid.

• Whenever the fluid level in the hole decreases, the hydrostatic pressure exerted by the fluid also decreases and if the decrease in hydrostatic pressure falls below the formation pore pressure, the well may flow.

• Therefore the hole must be filled to maintain sufficient hydrostatic pressure to control formation pressure.

• During tripping, the pipe could be dry or wet depending on the conditions.

• The API7G illustrates the methodology for calculating accurate pipe displacement and gives correct charts and tables. To calculate the volume to fill the well when tripping dry pipe out is given as;

• Barrel to fill=pipe displacement(bbl/ft) × length pulled (ft)

• To calculate the volume to fill the well when tripping wet pipe out is given as;

• Barrel to fill=( pipe displacement(bbls/ft) + pipe capacity(bbls/ft) )×length pulled(ft)

• In some wells, monitoring fill –up volumes on trips can be complicated by loss through perforations.

• The wells may stand full of fluid initially, but over a period of time the fluid seeps in to the reservoir.

• In such wells, the fill up volume will always exceed the calculated or theoretical volume of the steel removed from the well.

• In some fields, wells have low reservoir pressures and will not support a full column of fluid.

• In these wells filling the hole with fluid is essentially impossible unless sort of bridging agent is used to temporarily bridge off the subnormally pressured zone.

• The common practice is to pump the theoretical fill up volume while pulling out of the well.

Insufficient mud (fluid) density

• The mud in the wellbore must exert enough hydrostatic pressure to equal the formation pore pressure.

• If the fluid’s hydrostatic pressure is less than formation pressure the well can flow.

• The most common reason for insufficient fluid density is drilling into unexpected abnormally pressured formations.

• This situation usually arises when unpredicted geological conditions are encountered.

• Such as drilling across a fault that abruptly changes the formation being drilled. Mishandling mud at the surface accounts for many instances of insufficient fluid weight.

• Such as opening wrong valve on the pump suction manifold and allowing a tank of light weight fluid to be pumped; bumping the water valve so more is added than intended; washing off shale shakers; or clean-up operations. All of these can affect mud weight.

Swabbing /Surging

• Swabbing is as a result of the upward movement of pipe in a well and results in a decrease in bottomhole pressure.

• In some cases, the bottomhole pressure reduction can be large enough to cause the well to go underbalanced and allow formation fluids to enter the wellbore.

• The initial swabbing action compounded by the reduction in hydrostatic pressure(from formation fluids entering the well) can lead to a significant reduction in bottomhole pressure and a larger influx of formation fluids.

• Therefore, early detection of swabbing on trips is critical to minimizing the size of a kick.

• Many wellbore conditions increase the likelihood of swabbing on a trip. Swabbing (piston) action is enhanced when pipe is pulled too fast.

• Poor fluid properties, such as high viscosity and gel strengths, also increase the chances of swabbing a well in.

• Additionally, large outside diameter (OD) tools (packers, scrapers, fishing tools, etc.) enhance the piston effect.

• These conditions need to be recognized in order to decrease the likelihood of swabbing a well in during completion/workover operations.

• As mentioned earlier, there are several computer and calculator programs that can estimate surge and swab pressures.

• Swabbing is detected by closely monitoring hole fill-up volumes during trips.

• For example, if three barrels of steel (tubing) are removed from the well and it takes only two barrels of fluid to fill the hole, then a one barrel kick has probably been swabbed into the wellbore.

• Special attention should be paid to hole fill-up volumes since statistics indicate that most kicks occur on trips.

• Lost circulation• Another cause of kick during completion/workover

operations is lost circulation. Loss of circulation leads to a drop of both the fluid level and hydrostatic pressure in a well.

• If the hydrostatic pressure falls below the reservoir pressure, the well kicks.

Three main causes of lost circulation are:• Excessive pressure overbalance• Excessive surge pressure• Poor formation integrity• Poor well planning• The fourth cause of kick is poor well planning. The

mud and casing programs have a great bearing on well control. These programs must be flexible enough to allow progressively deeper casing strings to be set; otherwise a situation may arise where it is not possible to control kicks or lost circulation. Well control is an important part of well planning.

Well control methods

• During drilling operations, kicks are usually killed using the Driller’s, Engineer’s or a combination of both called Concurrent Method while forward circulating.

• The selection of which to use will depend upon the amount and type of kick fluids that have entered the well, the rig's equipment capabilities, the minimum fracture pressure in the open hole, and the drilling and operating companies well control policies.

• For workover or completion operations, other methods are often used.

• Bullheading is a common way to kill a well during workovers and completions operations but is not often used for drilling operations.

• Reverse circulation is another kill method used for workovers that is not used for drilling.

Conclusion

• The aim of oil operations is to complete all tasks in a safe and efficient manner without detrimental effects to the environment.

• This aim can only be achieved if control of the well is maintained at all times.

• The understanding of pressure and pressure relationships is important in preventing blowouts.

• Blowouts are prevented by experienced personnel that are able to detect when the well is kicking and take proper and prompt actions to shut-in the well.

See also

• Blowout (well drilling)• Blowout preventer• Oil well• Oil well control

9.3 Well Intervention Operations

Well intervention vessel Skandi Constructor (former Sarah) with X-bow.

Well intervention

• A well intervention, or well work, is any operation carried out on an oil or gas well during or at the end of its productive life, which alters the state of the well and/or well geometry, provides well diagnostics, or manages the production of the well.

Types of well work

• Pumping• Main article: Pumping (oil well)• Pumping is the simplest form of intervention as it does not

involve putting hardware into the well itself. • Frequently it simply involves rigging up to the kill wing valve

on the Christmas tree and pumping the chemicals into the well.

• Wellhead and Christmas tree maintenance• Main article: Well integrity• The complexity of Wellhead and Christmas tree maintenance

can vary depending on the condition of the wellheads. Scheduled annual maintenance may simply involve greasing and pressure testing the valve on the hardware.

• Sometimes the downhole safety valve is pressure tested as well.

• Slickline• Main article: Wireline (cabling)• Slickline operations may be used for fishing, gauge cutting,

setting or removing plugs, deploying or removing wireline retrievable valves, and memory logging.

• Braided line• Main article: Wireline (cabling)• Braided line is more complex than slickline due to the need for

a grease injection system in the rigup to ensure the BOP can seal around the braided contours of the wire. It also requires an additional shear-seal BOP as a tertiary barrier as the upper master valve on the Christmas tree can only cut slickline. Braided line includes both the core-less variety used for heaving fishing and electric-line used for logging and perforating.

• Coiled tubing• Main article: Coiled tubing• Coiled tubing is used when it is desired to pump chemicals

directly to the bottom of the well, such as in a circulating operation or a chemical wash. It can also be used for tasks normally done by wireline if the deviation in the well is too severe for gravity to lower the toolstring and circumstances prevent the use of a wireline tractor.

• Snubbing• Main article: Snubbing• Snubbing, also known as hydraulic workover, involves

forcing a string of pipe into the well against wellbore pressure to perform the required tasks. The rig up is larger than for coiled tubing and the pipe more rigid.

• Workover• Main article: Workover• In some older wells, changing reservoir conditions or

deteriorating condition of the completion may necessitate pulling it out to replace it with a fresh completion.

• Subsea well Intervention• Main article: Subsea• Subsea well intervention offers many challenges and requires

much advance planning. The cost of subsea intervention has in the past inhibited the intervention but in the current climate is much more viable. These interventions are commonly executed from light/medium intervention vessels or mobile offshore drilling units (MODU) for the heavier interventions such as snubbing and workover drilling rigs.

See also

• Blowout preventer• Coiled tubing• Drilling rig• Helix Energy Solutions Group• List of oilfield service companies• Oil well• Petroleum industry• Snubbing• Well services• Well stimulation• Wellhead• Wireline• Xmas tree• Riserless Light Well Intervention• Baker Hughes

• External links• Defining Well Intervention• IWCF Well Intervention Pressure Control syllabus (

pdf)

9.4 Barrier requirements for Well Intervention Operations

Practical Intervention Barriers

• A barrier is defined as a means of containing wellbore pressure and fluids.

• Two effective barriers are required for most intervention operations.

• Consider when barriers are effective (and when they are not) and how to back them up for safety.

• Must be rated to the maximum pressure that can be encountered.

Common Barriers • Kill weight fluid column (not just a fluid column) –

monitored and tested • Pipe rams when pipe is in the well • Blind/Blind-Shear when no pipe is in the well • Master valve when pipe is not in the well • CT Flapper valves (dual flappers = one barrier) • Stuffing box/Stripper Rubber • Downhole plugs • Grease seal/ram for braided line (both are one

barrier)

Kill Weight Fluid• KWF = Formation Pore Pressure (psi) / (0.052 *

TVD to mid perfs (ft)) • where: KWF = kill weight fluid in ppg • TVD The kill weight fluid must occupy both the

annulus and the tubing with no voids or other fluids involved.

• If the density and level of the fluid are not monitored, can the fluid be an effective barrier?

Difference between Surface and Downhole Barriers

• A surface barrier prevents escape of fluids from the well.

• A downhole barrier may also prevent crossflow between formations.

• The barrier during drilling is a well control barrier that has both hydrostatic and mechanical control points.

• A column of kill weight fluid, monitored and tested, is a common active barrier.

• During wireline intervention, the control method is pressure control with two or more barriers.

The barriers for wireline include: • 1. Grease or oil seal on the wire (for dynamic

sealing); 2. Packoff for static application • 3. Blind/Shear rams • 4. Master valve (can cut some wire, but poses a

risk of valve damage).

• Barriers for Intervention with Coiled Tubing Barriers include:

• 1. Stuffing Box • 2. Coiled Tubing BOP • 3. Annular Preventer (for sealing around BHA

string) • 4. Pipe ram below circulating cross or Tee. • 5. Master Valves – when CT and BHA are above

the top Master Valve.

Barriers for Producing Wells – usually only one barrier for many areas: • 1. Almost all flow/gathering lines, separators and

pipelines. • 2. The flow cross, choke body and other areas

above the tubing hanger • 3. Below the tubing hanger for gas lift supply • 4. At any open shoe with gas lift supply • 5. Uncemented casing below the packer

Live Well Workovers

• Top Hole - plug (WL or CT) set at or below packer - top of well is isolated.

• Used for: press test pickle/cleanout tubing replacement fluid unload/swap

Typical Conditional Barriers

• Considered a barrier during certain operations but not at other times.

Examples: • Pipe rams • Barrier only when pipe is in the well • Blind ram• Master valve• Stripper rubber • Barrier only when pipe is out of the well • Braided line rams – barrier only with grease

injection

• Unusual Cases • When running a BHA that cannot be sealed with a

pipe ram or cut with a blind shear. • Is a special barrier needed for the BHA? • When changing the elements on a ram or stripper

rubber• Is a backup needed?

The Two Barrier Rule • Barriers may be the same in some instances. • Both must be capable of controlling the full well

pressure. • Many barriers are conditional – may need back-

up.

• Some Special Cases • Snubbing or hydraulic workover • The two (minimum) pipe rams are barriers, but a

blind-shear is required for a second barrier while pipe is in the well.

• What is needed when an pipe ram element has to be changed?

• A second blind or blind-shear or master valve or other device is required when pipe is out of the well.

• Special cases, continued • Large BHA or BHA that cannot be cut. • Annular preventer? • Downhole valves (SSSV as a barrier????) • SSSV’s are not a good barrier if an object can be

dropped from the tool. • A dropped object can breach/break the seal

offered by flapper type SSSV. • Pressure operated downhole valves

• Special cases, continued • Fracturing Tree Saver • Hydraulic deployment • Second set of valves • temporarily replaces wellhead valve control • Stinger with seal isolates and “locks-out”

wellhead valves

Special Cases, continued • What is stability of the barrier? • To outgassing (seal face failure) • To high or low temperatures (does it weaken

barrier?)• To corrosion (components weakened by attack?) • To erosion – erosion of sealing surfaces • To high or low pressure spikes – To high or low

tensile loads

• Special Example • Inflatable Packers • Are they barriers? • What is the reliability? • Do they stay put? • Has a great deal to do with how much they are expanded

and where they are placed. • Good reliability when set in pipe • Good reliability when placement “slide” is short (less than

1000 ft) • Good reliability when expansion from initial to set is

3/14/2009less than 2x.• Well Intervention Pressure Control Syllabus

9.6 Barrier Types

9.7 Well Killing & Securing Methodologies

Well kill

• A well kill is the operation of placing a column of heavy fluid into a well bore in order to prevent the flow of reservoir fluids without the need for pressure control equipment at the surface.

• It works on the principle that the hydrostatic head of the "kill fluid" or "kill mud" will be enough to suppress the pressure of the formation fluids.

• Well kills may be planned in the case of advanced interventions such as workovers, or be contingency operations.

• The situation calling for a well kill will dictate the method taken.• Not all well kills are deliberate. • Sometimes, the unintended buildup of fluids, either from

injection of chemicals like methanol from surface, or from liquids produced from the reservoir, can be enough to kill the well, particularly gas wells, which are notoriously easy to kill.

Principles

• The principle of a well kill revolves around the weight of a column of fluid and hence the pressure exerted at the bottom.

Where P is the pressure at depth h in the column, g is the acceleration of gravity and ρ is the density of the fluid. It is common in the oil industry to use weight density, which is the product of mass density and the acceleration of gravity. This reduces the equation to:

• Where γ is the weight density. Weight density may also be described as the pressure gradient because it directly determines how much extra pressure will be added by increasing depth of the column of fluid.

• The objective in a well kill, is to make the pressure at the bottom of the kill fluid equal (or slightly greater) than the pressure of the reservoir fluids.

• Example• The pressure of the reservoir fluids at the

bottom of the hole is 38MPa. • We have a kill fluid with a weight density

of 16kN.m−3. • What will need to be the height of the

hydrostatic head in order to kill the well?• From the equation:

• Therefore, a column of 2375m of this fluid is needed. This refers to the true vertical depth of the column, not the measured depth, which is always larger than true vertical depth due to deviations from vertical.

• Math in the oil field• In the oil industry, a pure SI system is far from being

used. Weight densities are commonly either given as specific gravity or in pounds per gallon.

• Simple conversion factors (0.433 for specific gravity and 0.052 for ppg) convert these values to a pressure gradient in psi per foot. Multiplying by the depth in feet gives the pressure at the bottom of the column.

Methods of well kill

• Reverse circulation• This is often the tidiest way of making a pre-planned well kill. It involves

pumping kill fluid down the 'A' annulus of the well, through a point of communication between it and theproduction tubing just above the production packer and up the tubing, displacing the lighter well bore fluids, which are allowed to flow to production.

• The point of communication was traditionally a device called a sliding sleeve, or sliding side door, which is a hydraulically operated device, built into the production tubing.

• During normal operation, it would remain closed sealing off the tubing and the annulus, but for events such as this, it would be opened to allow the free flow of fluids between the two regions.

• These components have fallen out of favour as they were prone to leaking. • Instead, it is now more common to punch a hole in the tubing for circulation

kills. • Although this permanently damages the tubing, given that most pre-planned

well kills are for workovers, this is not an issue, since the tubing is being pulled for replacement anyway.

Bullheading

• This is the most common method of a contingency well kill. • If there is a sudden need to kill a well quickly, without the

time for rigging up for circulation, the more blunt instrument of bullheading may be used.

• This involves simply pumping the kill fluid directly down the well bore, forcing the well bore fluids back into the reservoir.

• This can be effective at achieving the central aim of a well kill; building up a sufficient hydrostatic head in the well bore.

• However, it can be limited by the burst-pressure capabilities of the tubing or casing, and can risk damaging the reservoir by forcing undesired materials into it.

• The principal advantage is that it can be done with little advanced planning.

• Forward circulation• This is similar to reverse circulation, except the kill fluid is

pumped into the production tubing and circulated out through the annulus. Though effective, it is not as desirable since it is preferred that the well bore fluids be displaced out to production, rather than the annuls.

• Lubricate and bleed• This is the most time consuming form of well kill. It

involves repeatedly pumping in small quantities of kill mud into the well bore and then bleeding off excess pressure. It works on the principle that the heavier kill mud will sink below the lighter well bore fluids and so bleeding off the pressure will remove the latter leaving an increasing quantity of kill mud in the well bore with successive steps.

• Well kills during drilling operations• During drilling, pressure control is maintained

through the use of precisely concocted drilling fluid, which balances out the pressure at the bottom of the hole. In the event of suddenly encountering a high pressure pocket of, say, gas (called a "kick"), it can become necessary to kill the well.

• This is done by pumping kill mud down the drill pipe, where it circulates out the bottom and into the well bore.

Reversing a well kill

• The intention of a well kill (or the reality of an unintentional well kill) is to stop reservoir fluids flowing to surface. This of course creates problems when it is desirable to get the well flowing again. In order to reverse the well kill, the kill fluid must be displaced from the well bore. This involves injecting a gas at high pressure, usually nitrogen since it is inert and cheap. A gas can be put under sufficient pressure to allow it to push heavy kill fluid, but will then expand and become light once pressure is removed. This means that having displaced the kill fluid, it will not itself kill the well. The reservoir fluids should be able to flow to surface, displacing the gas.

• The cheapest way to do it is similar to bullheading, where the nitrogen is pumped in under high pressure to force the kill fluid into the reservoir. This, of course, runs a high risk of causing well damage. The most effective way is to use coiled tubing, pumping the gas/diesel down the coil and circulating out the bottom into the well bore, where it will displace the kill mud to production.

• See also• Blowout preventer• Coiled tubing• Oil well• Top kill• Well drilling• Well intervention

Module (10) Drilling Operational Problems & Troubleshooting

10.1 Well Kick

https://www.youtube.com/watch?v=3oAmVjKUUno

Kicks

• A kick is a well control problem in which the pressure found within the drilled rock is higher than the mud hydrostatic pressure acting on the borehole or rock face.

• When this occurs, the greater formation pressure has a tendency to force formation fluids into the wellbore.

• This forced fluid flow is called a kick. • If the flow is successfully controlled, the kick is

considered to have been killed. • An uncontrolled kick that increases in severity

may result in what is known as a “blowout.”

Factors affecting kick severity

• Several factors affect the severity of a kick. • One factor, for example, is the “permeability” of rock, which is its ability to

allow fluid to move through the rock. • Another factor affecting kick severity is “porosity.” Porosity measures the

amount of space in the rock containing fluids. • A rock with high permeability and high porosity has greater potential for a

severe kick than a rock with low permeability and low porosity. • For example, sandstone is considered to have greater kick potential than

shale, because sandstone has greater permeability and greater porosity than shale.

• Yet another factor affecting kick severity is the “pressure differential” involved.

• Pressure differential is the difference between the formation fluid pressure and the mud hydrostatic pressure.

• If the formation pressure is much greater than the hydrostatic pressure, a large negative differential pressure exists.

• If this negative differential pressure is coupled with high permeability and high porosity, a severe kick may occur.

Kick labels

A kick can be labeled in several ways, including one that depends on the type of formation fluid that entered the borehole. Known kick fluids include:• Gas• Oil• Salt water• Magnesium chloride water• Hydrogen sulfide (sour) gas• Carbon dioxide

• If gas enters the borehole, the kick is called a "gas kick." Furthermore, if a volume of 20 bbl (3.2 m3) of gas entered the borehole, the kick could be termed a 20-bbl (3.2-m3) gas kick.

• Another way of labeling kicks is by identifying the required mud weight increase necessary to control the well and kill a potential blowout.

• For example, if a kick required a 0.7-lbm/gal (84-kg/m3) mud weight increase to control the well, the kick could be termed a 0.7-lbm/gal (84-kg/m3) kick.

• It is interesting to note that an average kick requires approximately 0.5 lbm/gal (60 kg/m3), or less, mud weight increase.

Causes of kicks

• Kicks occur as a result of formation pressure being greater than mud hydrostatic pressure, which causes fluids to flow from the formation into the wellbore. In almost all drilling operations, the operator attempts to maintain a hydrostatic pressure greater than formation pressure and, thus, prevent kicks; however, on occasion the formation will exceed the mud pressure and a kick will occur. Reasons for this imbalance explain the key causes of kicks:

• Insufficient mud weight.• Improper hole fill-up during trips.• Swabbing.• Cut mud.• Lost circulation.

Insufficient mud weight

• Insufficient mud weight is the predominant cause of kicks.

• A permeable zone is drilled while using a mud weight that exerts less pressure than the formation pressure within the zone.

• Because the formation pressure exceeds the wellbore pressure, fluids begin to flow from the formation into the wellbore and the kick occurs.

• These abnormal formation pressures are often associated with causes for kicks. Abnormal formation pressures are greater pressures than in normal conditions.

• In well control situations, formation pressures greater than normal are the biggest concern. Because a normal formation pressure is equal to a full column of native water, abnormally pressured formations exert more pressure than a full water column.

• If abnormally pressured formations are encountered while drilling with mud weights insufficient to control the zone, a potential kick situation has developed.

• Whether or not the kick occurs depends on the permeability and porosity of the rock. A number of abnormal pressure indicators can be used to estimate formation pressures so that kicks caused by insufficient mud weight are prevented (some are listed in Table 1).

•Table 1- Abnormal Pressure Indicators

• An obvious solution to kicks caused by insufficient mud weights seems to be drilling with high mud weights; however, this is not always a viable solution.

• First, high mud weights may exceed the fracture mud weight of the formation and induce lost circulation.

• Second, mud weights in excess of the formation pressure may significantly reduce the penetration rates.

• Also, pipe sticking becomes a serious consideration when excessive mud weights are used.

• The best solution is to maintain a mud weight slightly greater than formation pressure until the mud weight begins to approach the fracture mud weight and, thus, requires an additional string of casing.

• Improper hole fill-up during trips• Improperly filling up of the hole during trips is

another prominent cause of kicks. As the drillpipe is pulled out of the hole, the mud level falls because the pipe steel no longer displaces the mud. As the overall mud level decreases, the hole must be periodically filled up with mud to avoid reducing the hydrostatic pressure and, thereby, allowing a kick to occur.

• Several methods can be used to fill up the hole, but each must be able to accurately measure the amount of mud required.

• It is not acceptable—under any condition—to allow a centrifugal pump to continuously fill up the hole from the suction pit because accurate mud-volume measurement with this sort of pump is impossible.

• The two acceptable methods most commonly used to maintain hole fill-up are the trip-tank method and the pump-stroke measurements method.

• The trip-tank method has a calibration device that monitors the volume of mud entering the hole.

• The tank can be placed above the preventer to allow gravity to force mud into the annulus, or a centrifugal pump may pump mud into the annulus with the overflow returning to the trip tank.

• The advantages of the trip-tank method include that the hole remains full at all times, and an accurate measurement of the mud entering the hole is possible.

• The other method of keeping a full hole—the pump-stroke measurement method—is to periodically fill up the hole with a positive-displacement pump.

• A flowline device can be installed with the positive-displacement pump to measure the pump strokes required to fill the hole. This device will automatically shut off the pump when the hole is full.

Swabbing

• Pulling the drillstring from the borehole creates swab pressures.

• Swab pressures are negative, and reduce the effective hydrostatic pressure throughout the hole and below the bit.

• If this pressure reduction lowers the effective hydrostatic pressure below the formation pressure, a potential kick has developed. Variables controlling swab pressures are:

• Pipe pulling speed• Mud properties• Hole configuration• The effect of “balled” equipment

Cut mud

• Gas-contaminated mud will occasionally cause a kick, although this is rare. The mud density reduction is usually caused by fluids from the core volume being cut and released into the mud system. As the gas is circulated to the surface, it expands and may reduce the overall hydrostatic pressure sufficient enough to allow a kick to occur.

• Although the mud weight is cut severely at the surface, the hydrostatic pressure is not reduced significantly because most gas expansion occurs near the surface and not at the hole bottom.

• Lost circulation• Occasionally, kicks are caused by lost

circulation. A decreased hydrostatic pressure occurs from a shorter mud column. When a kick occurs from lost circulation, the problem may become severe. A large volume of kick fluid may enter the hole before the rising mud level is observed at the surface. It is recommended that the hole be filled with some type of fluid to monitor fluid levels if lost circulation occurs.

Warning signs of kicks

• Warning signs and possible kick indicators can be observed at the surface. Each crew member has the responsibility to recognize and interpret these signs and take proper action. All signs do not positively identify a kick; some merely warn of potential kick situations. Key warning signs to watch for include the following:

• Flow rate increase• Pit volume increase• Flowing well with pumps off• Pump pressure decrease and pump stroke

increase• Improper hole fill-up on trips• String weight change• Drilling break• Cut mud weight

• Each is identified below as a primary or secondary warning sign, relative to its importance in kick detection.

• Flow rate increase (primary indicator)• An increase in flow rate leaving the well, while

pumping at a constant rate, is a primary kick indicator. The increased flow rate is interpreted as the formation aiding the rig pumps by moving fluid up the annulus and forcing formation fluids into the wellbore.

• Pit volume increase (primary indicator)• If the pit volume is not changed as a result of

surface-controlled actions, an increase indicates a kick is occurring. Fluids entering the wellbore displace an equal volume of mud at the flowline, resulting in pit gain.

• Flowing well with pumps off (primary indicator)

• When the rig pumps are not moving the mud, a continued flow from the well indicates a kick is in progress. An exception is when the mud in the drillpipe is considerably heavier than in the annulus, such as in the case of a slug.

• Pump pressure decrease and pump stroke increase (secondary indicator)

• A pump pressure change may indicate a kick. Initial fluid entry into the borehole may cause the mud to flocculate and temporarily increase the pump pressure. As the flow continues, the low-density influx will displace heavier drilling fluids, and the pump pressure may begin to decrease. As the fluid in the annulus becomes less dense, the mud in the drillpipe tends to fall and pump speed may increase.

• Other drilling problems may also exhibit these signs. A hole in the pipe, called a “washout,” will cause pump pressure to decrease. A twist-off of the drillstring will give the same signs. It is proper procedure, however, to check for a kick if these signs are observed.

• Improper hole fill-up on trips (primary indicator)

• When the drillstring is pulled out of the hole, the mud level should decrease by a volume equivalent to the removed steel. If the hole does not require the calculated volume of mud to bring the mud level back to the surface, it is assumed a kick fluid has entered the hole and partially filled the displacement volume of the drillstring. Even though gas or salt water may have entered the hole, the well may not flow until enough fluid has entered to reduce the hydrostatic pressure below the formation pressure.

• String weight change (secondary indicator)

• Drilling fluid provides a buoyant effect to the drillstring and reduces the actual pipe weight supported by the derrick. Heavier muds have a greater buoyant force than less dense muds. When a kick occurs, and low-density formation fluids begin to enter the borehole, the buoyant force of the mud system is reduced, and the string weight observed at the surface begins to increase.

Drilling break (secondary indicator)

• An abrupt increase in bit-penetration rate, called a “drilling break,” is a warning sign of a potential kick. A gradual increase in penetration rate is an abnormal pressure indicator, and should not be misconstrued as an abrupt rate increase.

• When the rate suddenly increases, it is assumed that the rock type has changed. It is also assumed that the new rock type has the potential to kick (as in the case of a sand), whereas the previously drilled rock did not have this potential (as in the case of shale). Although a drilling break may have been observed, it is not certain that a kick will occur, only that a new formation has been drilled that may have kick potential.

• It is recommended when a drilling break is recorded that the driller should drill 3 to 5 ft (1 to 1.5 m) into the sand and then stop to check for flowing formation fluids. Flow checks are not always performed in tophole drilling or when drilling through a series of stringers in which repetitive breaks are encountered. Unfortunately, many kicks and blowouts have occurred because of this lack of flow checking.

• Cut mud weight (secondary indicator)• Reduced mud weight observed at the flow line has

occasionally caused a kick to occur. Some causes for reduced mud weight are:

• Core volume cutting• Connection air• Aerated mud circulated from the pits and down the drillpipe• Fortunately, the lower mud weights from the cuttings effect

are found near the surface (generally because of gas expansion), and do not appreciably reduce mud density throughout the hole. Table 3 shows that gas cutting has a very small effect on bottomhole hydrostatic pressure.

• An important point to remember about gas cutting is that, if the well did not kick within the time required to drill the gas zone and circulate the gas to the surface, only a small possibility exists that it will kick. Generally, gas cutting indicates that a formation has been drilled that contains gas. It does not mean that the mud weight must be increased.

• Kick detection and monitoring with MWD tools

• During circulation and drilling operations, measurement while drilling (MWD) systems monitor:

• Mud properties• Formation parameters• Drillstring parameters

• The system is widely used for drilling, but it also has applications for well control, including the following:

• Drilling-efficiency data, such as downhole weight on bit and torque, can be used to differentiate between rate of penetration changes caused by drag and those caused by formation strength. Monitoring bottomhole pressure, temperature, and flow with the MWD tool is not only useful for early kick detection, but can also be valuable during a well-control kill operation. Formation evaluation capabilities, such as gamma ray and resistivity measurements, can be used to detect influxes into the wellbore, identify rock lithology, and predict pore pressure trends.

• The MWD tool enables monitoring of the acoustic properties of the annulus for early gas-influx detection. Pressure pulses generated by the MWD pulser are recorded and compared at the standpipe and the top of the annulus. Full-scale testing has shown that the presence of free gas in the annulus is detected by amplitude attenuation and phase delay between the two signals. For water-based mud systems, this technique has demonstrated the capacity to consistently detect gas influxes within minutes before significant expansion occurs. Further development is currently under way to improve the system’s capability to detect gas influxes in oil-based mud.

• Some MWD tools feature kick detection through ultrasonic sensors. In these systems, an ultrasonic transducer emits a signal that is reflected off the formation and back to the sensor. Small quantities of free gas significantly alter the acoustic impedance of the mud. Automatic monitoring of these signals permits detection of gas in the annulus. It should be noted that these devices only detect the presence of gas at or below the MWD tool.

• The MWD tool offers kick-detection benefits, if the response time is less than the time it takes to observe the surface indicators. The tool can provide early detection of kicks and potential influxes, as well as monitor the kick-killing process. Tool response time is a function of the complexity of the MWD tool and the mode of operation. The sequence of data transmission determines the update times of each type of measurement. Many MWD tools allow for reprogramming of the update sequence while the tool is in the hole. This feature can enable the operator to increase the update frequency of critical information to meet the expected needs of the section being drilled. If the tool response time is longer than required for surface indicators to be observed, the MWD only serves as a confirmation source.

• Kick identification• When a kick occurs, note the type of influx (gas,

oil, or salt water) entering the wellbore. Remember that well-control procedures developed here are designed to kill all types of kicks safely. The formula required to make this kick influx calculation is as follows:

where gi = influx gradient, psi/ft; gmdp = mud gradient in drillpipe, psi/ft; and hi = influx height, ft.

• Kill-weight mud calculation• It is necessary to calculate the mud weight

needed to balance bottomhole formation pressure. “Kill-weight mud” is the amount of mud necessary to exactly balance formation pressure. It will be later shown that it is safer to use the exact required mud weight without variation

• Because the drillpipe pressure has been defined as a bottomhole pressure gauge, the psidp can be used to calculate the mud weight necessary to kill the well. The kill mud formula follows:

• where ρkw = kill-mud weight, lbm/gal 19.23 = conversion constant Dtv = true vertical-bit depth, ft ρo = original mud weight, lbm/gal.

• Because the casing pressure does not appear in Eq. 2, a high casing pressure does not necessarily indicate a high kill-weight mud. The same is true for pit gain because it does not appear in Eq. 2. Example 1 uses the kill-weight mud formula.

• Example 1• What will the kill-weight mud density be for the

kick data given below?

https://www.youtube.com/watch?v=3oAmVjKUUno

• See also• Well control• Variables affecting kill procedures• Production logs to assess gas kick• PEH:Well Control: Procedures and Principles• Category: 1.6 Drilling Operations

10.2 Well Kick Control Methodologies

• Well Control Methods:

1. Driller's Method2. Wait and Weight3. Dynamic Volumetric4. Static Volumetric - Migration / Bleed5. Static Volumetric - Lubricate / Bleed – Top Kill

10.3 Work-over Operations

A workover rig. Workover Rig doing a Snub Job

Workover

• The term workover is used to refer to any kind of oil well intervention involving invasive techniques, such as wireline, coiled tubing or snubbing.

• More specifically though, it will refer to the expensive process of pulling and replacing a completion.

• Reason to perform a workover• Workovers rank among the most complex,

difficult and expensive types of wellwork. They are only performed if the completion of a well is terminally unsuitable for the job at hand. The production tubing may have become damaged due to operational factors like corrosion to the point where well integrity is threatened. Downhole components such as tubing, retrievable downhole safety valves, or electrical submersible pumps may have malfunctioned, needing replacement.

• Operation• Before any workover, the well must first be killed. • Since workovers are long planned in advance, there would be much time to

plan the well kill and so the reverse circulation would be common. • The intense nature of this operation often requires no less than the

capabilities of a drilling rig.• The workover begins by removing the wellhead and possibly the flow line,

then lifting the tubing hanger from the casing head, thus beginning to pull the completion out of the well.

• The string will almost always be fixed in place by at least one production packer. If the packer is retrievable it can be released easily enough and pulled out with the completion string.

• If it is permanent, then it is common to cut the tubing just above it and pull out the upper portion of the string.

• If necessary, the packer and the tubing left in hole can be milled out, though more commonly, the new completion will make use of it by setting a new packer just above it and running new tubing down to the top of the old.

• Workovers on casing• Although less exposed to wellbore fluids, 

casing strings too have been known to lose integrity. On occasion, it may be deemed economical to pull and replace it. Because casing strings are cemented in place, this is significantly more difficult and expensive than replacing the completion string. If in some instances the casing cannot be removed from the well, it may be necessary to sidetrack the offending area and recomplete, also an expensive process. For all but the most productive well, replacing casing would never be economical.

• Oil well• Well intervention• Well kill• Completion (oil well)

10.4 Production Platform

(in the oil industry) a platform from which development  wells aredrilled that also houses a processing plant and other equipmentnecessary to keep an oilfield in production

The World’s Deepest Offshore Oil Drilling and Production Platform (Perdido)

10.5 Types of Blowouts/ Causes of Blowouts

The Lucas Gusher at Spindletop,Texas (1901)

Blowout (well drilling)

• A blowout is the uncontrolled release of crude oil and/or natural gas from an oil well or gas well after pressure control systems have failed.

• Prior to the advent of pressure control equipment in the 1920s, the uncontrolled release of oil and gas from a well while drilling was common and was known as an oil gusher, gusher or wild well. An accidental spark during a blowout can lead to a catastrophic oil or gas fire.

• History• Gushers were an icon of oil exploration during the late

19th and early 20th centuries. During that era, the simple drilling techniques such as cable-tool drilling and the lack of blowout preventers meant that drillers could not control high-pressure reservoirs. When these high pressure zones were breached, the oil or natural gas would travel up the well at a high rate, forcing out the drill string and creating a gusher. A well which began as a gusher was said to have "blown in": for instance, the Lakeview Gusher blew in in 1910. These uncapped wells could produce large amounts of oil, often shooting 200 feet (60 m) or higher into the air. A blowout primarily composed of natural gas was known as agas gusher.

• Despite being symbols of new-found wealth, gushers were dangerous and wasteful. They killed workmen involved in drilling, destroyed equipment, and coated the landscape with thousands of barrels of oil; additionally, the explosive concussion released by the well when it pierces an oil/gas reservoir has been responsible for a number of oilmen losing their hearing entirely; standing too near to the drilling rig at the moment it drills into the oil reservoir is extremely hazardous. The impact on wildlife is very hard to quantify, but can only be estimated to be mild in the most optimistic models—realistically, the ecological impact is estimated by scientists across the ideological spectrum to be severe, profound, and lasting.

• To complicate matters further, the free flowing oil was—and is—in danger of igniting. One dramatic account of a blowout and fire reads,

• With a roar like a hundred express trains racing across the countryside, the well blew out, spewing oil in all directions. The derrick simply evaporated. Casings wilted like lettuce out of water, as heavy machinery writhed and twisted into grotesque shapes in the blazing inferno.

• The development of rotary drilling techniques where the density of the drilling fluid is sufficient to overcome the downhole pressure of a newly penetrated zone meant that gushers became avoidable. If however the fluid density was not adequate or fluids were lost to the formation, then there was still a significant risk of a well blowout.

• In 1924 the first successful blowout preventer was brought to market. • The BOP valve affixed to the wellhead could be closed in the event of

drilling into a high pressure zone, and the well fluids contained. Well control techniques could be used to regain control of the well. As the technology developed, blowout preventers became standard equipment, and gushers became a thing of the past.

• In the modern petroleum industry, uncontrollable wells became known as blowouts and are comparatively rare. There has been significant improvement in technology, well control techniques, and personnel training which has helped to prevent their occurring. From 1976 to 1981, 21 blowout reports are available.

• Notable gushers• Although it didn't actually happen when drilling for oil, an attempt in 1815

to drill for salt produced the earliest known oil gusher. Joseph Eichar and his team were digging for salt west of the town of Wooster, Ohio, along Killbuck Creek, when they struck oil. In a written retelling by Eichar's daughter, Eleanor, the strike produced "a spontaneous outburst, which shot up high as the tops of the highest trees!"

• The Shaw Gusher in Oil Springs, Ontario, was North America's (and possibly the world's) first oil gusher when actually drilling for oil. On January 16, 1862, it shot oil from over 60 metres (200 ft) below ground to above the treetops at a rate of 3,000 barrels (480 m3) per day, triggering the oil boom in Lambton County.

• Lucas Gusher at Spindletop in Beaumont, Texas in 1901 flowed at 100,000 barrels (16,000 m3) per day at its peak, but soon slowed and was capped within nine days. The well tripled U.S. oil production overnight and marked the start of the Texas oil industry.

• Masjed Soleiman, Iran in 1908 marked the first major oil strike recorded in the Middle East.[

• Dos Bocas in the State of Veracruz, Mexico, was a famous Mexican blowout that formed a large crater, and leaked oil from the main reservoir for many years, even after Pemex nationalized the Mexican oil industry in March 1938.

• Lakeview Gusher on the Midway-Sunset Oil Field in Kern County, California of 1910 is believed to be the largest-ever U.S. gusher. At its peak, more than 100,000 barrels (16,000 m3) of oil per day flowed out, reaching as high as 200 feet (60 m) in the air. It remained uncapped for 18 months, spilling over 9 million barrels (1,400,000 m3) of oil, less than half of which was recovered.

• A short-lived gusher at Alamitos #1 in Signal Hill, California in 1921 marked the discovery of the Long Beach Oil Field, one of the most productive oil fields in the world.

• The Barroso 2 well in Cabimas, Venezuela in December 1922 flowed at around 100,000 barrels (16,000 m3) per day for nine days, plus a large amount of natural gas.

• Baba Gurgur near Kirkuk, Iraq, an oilfield known since antiquity, erupted at a rate of 95,000 barrels (15,100 m3) a day in 1927.

• The Wild Mary Sudik gusher in Oklahoma City, Oklahoma in 1930 flowed at a rate of 72,000 barrels (11,400 m3) per day.

• The Daisy Bradford gusher in 1930 marked the discovery of the East Texas Oil Field, the largest oilfield in the contiguous United States.

• The largest known 'wildcat' oil gusher blew near Qom, Iran on August 26, 1956. The uncontrolled oil gushed to a height of 52 m (170 ft), at a rate of 120,000 barrels (19,000 m3) per day. The gusher was closed after 90 days' work by Bagher Mostofi and Myron Kinley (USA).

• One of the most troublesome gushers happened on June 23, 1985 at the well #37 at the Tengiz field in Atyrau, Kazakh SSR, Soviet Union, where the deep, 4209 metre well blew out and the 200-metres high gusher self-ignited two days later. Oil pressure up to 800 atm and high hydrogen sulfide content had led to the gusher being capped only on 27 July 1986 when the well was closed by the shaped charge. The total volume of erupted material measured at 4.3 millions metric tons of oil, 1.7 bn m³ of natural gas, and the burning gusher resulted in 890 tons of various mercaptans and more than 900,000 tons of soot released into atmosphere.

• The largest underwater blowout in U.S. history occurred on April 20, 2010, in the Gulf of Mexico at the Macondo Prospect oil field. The blowout caused the explosion of theDeepwater Horizon, a mobile offshore drilling platform owned by Transocean and under lease to BP at the time of the blowout. While the exact volume of oil spilled is unknown, as of June 3, 2010, the United States Geological Survey (USGS) Flow Rate Technical Group has placed the estimate at between 35,000 to 60,000 barrels (5,600 to 9,500 m3) of crude oil per day. See also Volume and extent of the Deepwater Horizon oil spill

Cause of blowouts

• Reservoir pressure• Petroleum or crude oil is a naturally occurring, flammable liquid

consisting of a complex mixture of hydrocarbons of various molecular weights, and other organic compounds, that are found in geologic formations beneath the Earth's surface.

• Because most hydrocarbons are lighter than rock or water, they often migrate upward through adjacent rock layers until either reaching the surface or becoming trapped within porous rocks (known as reservoirs) by impermeable rocks above.

• However, the process is influenced by underground water flows, causing oil to migrate hundreds of kilometres horizontally or even short distances downward before becoming trapped in a reservoir. When hydrocarbons are concentrated in a trap, an oil field forms, from which the liquid can be extracted by drilling and pumping.

• The down hole pressures experienced at the rock structures change depending upon the depth and the characteristic of the source rock.

• Formation kick• The downhole fluid pressures are controlled in modern wells through the

balancing of the hydrostatic pressure provided by the mud used. Should the balance of the drilling mud pressure be incorrect then formation fluids (oil, natural gas and/or water) begin to flow into the wellbore and up the annulus (the space between the outside of the drill string and the walls of the open hole or the inside of the last casing string set), and/or inside the drill pipe. This is commonly called a kick.

• If the well is not shut in (common term for the closing of the blow-out preventer valves), a kick can quickly escalate into a blowout when the formation fluids reach the surface, especially when the influx contains gas that expands rapidly as it flows up the wellbore, further decreasing the effective weight of the fluid.

• In other petroleum engineering words, the formation pore pressure gradient exceeds the mud pressure gradient, even in some cases when the Equivalent Circulating Density ECD is imposed with the mud pumps on the rig.

• Additional mechanical barriers such as blowout preventers (BOPs) can be closed to isolate the well while the hydrostatic balance is regained through circulation of fluids in the well.

Early warning signs of a well kick are:• Sudden change in drilling rate;• Change in surface fluid rate;• Change in pump pressure;• Reduction in drillpipe weight;• Surface mud cut by gas, oil or water;• Connection gases, high background gas units,

and high bottoms up gas units in the mudlogging unit.

• The primary means of detecting a kick is a relative change in the circulation rate back up to the surface into the mud pits. The drilling crew or mud engineer keeps track of the level in the mud pits and/or closely monitors the rate of mud returns versus the rate that is being pumped down the drill pipe.

• Upon encountering a zone of higher pressure than is being exerted by the hydrostatic head of the drilling mud at the bit, an increase in mud returns would be noticed as the formation fluid influx pushes the drilling mud toward the surface at a higher rate. Conversely, if the rate of returns is slower than expected, it means that a certain amount of the mud is being lost to a thief zone somewhere below the last casing shoe.

• This does not necessarily result in a kick (and may never become one); however, a drop in the mud level might allow influx of formation fluids from other zones if the hydrostatic head at depth is reduced to less than that of a full column of mud.

• Well control• The first response to detecting a kick would be to isolate the wellbore

from the surface by activating the blow-out preventers and closing in the well. Then the drilling crew would attempt to circulate in a heavier kill fluid to increase the hydrostatic pressure (sometimes with the assistance of a well control company). In the process, the influx fluids will be slowly circulated out in a controlled manner, taking care not to allow any gas to accelerate up the wellbore too quickly by controlling casing pressure with chokes on a predetermined schedule.

• This effect will be minor if the influx fluid is mainly salt water. And with an oil-based drilling fluid it can be masked in the early stages of controlling a kick because gas influx may dissolve into the oil under pressure at depth, only to come out of solution and expand rather rapidly as the influx nears the surface. Once all the contaminant has been circulated out, the casing pressure should have reached zero.

• Capping stacks are used for controlling blowouts. The cap is an open valve that is closed after bolted on.

Types of blowouts

• Well blowouts can occur during the drilling phase, during well testing, during well completion, during production, or during workover activities.

Surface blowouts

• Blowouts can eject the drill string out of the well, and the force of the escaping fluid can be strong enough to damage thedrilling rig. In addition to oil, the output of a well blowout might include sand, mud, rocks, drilling fluid, natural gas, water, and other substances.

• Blowouts will often be ignited by an ignition source, from sparks from rocks being ejected, or simply from heat generated by friction. A well control company will then need to extinguish the well fire or cap the well, and replace the casing head and hangars. The flowing gas may contain poisonous hydrogen sulfide and the oil operator might decide to ignite the stream to convert this to less hazardous substances.[citation needed]

• Sometimes, blowouts can be so forceful that they cannot be directly brought under control from the surface, particularly if there is so much energy in the flowing zone that it does not deplete significantly over the course of a blowout. In such cases, other wells (called relief wells) may be drilled to intersect the well or pocket, in order to allow kill-weight fluids to be introduced at depth. When first drilled in the 1930s relief wells were drilled to inject water into the main drill well hole. Contrary to what might be inferred from the term, such wells generally are not used to help relieve pressure using multiple outlets from the blowout zone.

Subsea blowouts

• Subsea wells have the wellhead and pressure control equipment located on the seabed. They vary from depths of 10 feet (3.0 m) to 8,000 feet (2,400 m). It is very difficult to deal with a blowout in very deep water because of the remoteness and limited experience with this type of situation.

• The Deepwater Horizon well blowout in the Gulf of Mexico in April 2010, in 5,000 feet (1,500 m) water depth, is the deepest subsea well blowout to date

Underground blowouts

• An underground blowout is a special situation where fluids from high pressure zones flow uncontrolled to lower pressure zones within the wellbore. Usually this is from deeper higher pressure zones to shallower lower pressure formations. There may be no escaping fluid flow at the wellhead.

Ixtoc I oil well blowout Deepwater Horizon drilling rig blowout,21 April 2010

• Blowout control expertise• Myron M. Kinley was a pioneer in fighting oil well fires and

blowouts. He developed many patents and designs for the tools and techniques of oil firefighting. His father, Karl T. Kinley, attempted to extinguish an oil well fire with the help of a massive explosion — a method that remains a common technique for fighting oil fires. The first oil well put out with explosives by Myron Kinley and his father, was in 1913. Kinley would later form the M.M. Kinley Company in 1923. Asger "Boots" Hansen and Edward Owen "Coots" Matthews also begin their careers under Kinley.

• Paul N. "Red" Adair joined the M.M. Kinley Company in 1946, and worked 14 years with Myron Kinley before starting his own company, Red Adair Co., Inc., in 1959.

• Red Adair co. has helped in controlling many offshore blowouts, including;

• CATCO fire in the Gulf of Mexico in 1959• "The Devil's Cigarette Lighter" in 1962 in Gassi Touil,

Algeria, in the Sahara Desert• The Ixtoc I oil spill in Mexico's Bay of Campeche in 1979• The Piper Alpha disaster in the North Sea in 1988• The Kuwaiti oil fires following the Gulf War in 1991.[24]

• In 1994, Adair retired and sold his company to Global Industries. Management of Adair's company left and created International Well Control (IWC). In 1997, they would buy the company Boots & Coots International Well Control, Inc., which was founded by two former lieutenants of Red Adair in 1978.

• Methods of quenching blowouts• Although several experimental methods exist

which attempt to capture as much oil as possible from a blown out well, they are very far from perfect, capturing between 20% - 50% of the leaking oil, by optimistic estimates. Ideally, the well could be made to stop gushing oil entirely - thus putting a stop to the cumulating pollution.

• Use of nuclear explosions• On Sep. 30, 1966 the Soviet Union in Urta-Bulak, an area about 80

kilometers from Bukhara, Uzbekistan, experienced blowouts on five natural gas wells. It was claimed in Komsomoloskaya Pravda that after years of burning uncontrollably they were able to stop them entirely.[ The Soviets lowered a specially made 30 kiloton nuclear bomb into a 6 kilometres (20,000 ft) borehole drilled 25 to 50 metres (82 to 164 ft) away from the original (rapidly leaking) well. A nuclear explosive was deemed necessary because conventional explosive both lacked the necessary power and would also require a great deal more space underground. When the bomb was set off, it proceeded to crush the original pipe that was carrying the gas from the deep reservoir to the surface, as well as to glassify all the surrounding rock. This caused the leak and fire at the surface to cease within approximately one minute of the explosion, and proved over the years to have been a permanent solution. A second attempt on a similar well was not as successful and other tests were for such experiments as oil extraction enhancement (Stavropol, 1969) and the creation of gas storage reservoirs (Orenburg, 1970).

10.6 Offshore Blowouts

• See also• Petroleum geology• Oil well fire• Drilling mud• Drilling rig• Oil platform• Oil well• List of oil spills• Underbalanced drilling• Oil well control

Module (11) Well Control Basics

11.1 Well Control Operations

• Intro to Well Control 1• Intro to Well Control 2• Intro to Well Control 3• Intro to Well Control 4• Intro to Well Control 5• Intro to Well Control 6• Intro to Well Control 7• ADC Well control simulation Simlator

Control Video

• Well control is the technique used in oil and gas operations such as drilling, well workover, and well completions to maintaining the fluid column hydrostatic pressure and formation pressure to prevent influx of formation fluids into the wellbore. This technique involves the estimation of formation fluid pressures, the strength of the subsurface formations and the use of casing and mud density to offset those pressures in a predictable fashion. Understanding of pressure and pressure relationships are very important in well control.

11.2 Factors Governing Well Control Success

11.3 Oil Spill Types

11.4 Oil Classes

11.5 Calculating the amount of Spilled Oil

oil spill volume compared to san francisco victorian

How we determine oil spill volume

• Computing Volume• An oil slick in the open ocean is typically a very thin layer of

oil covering a large area, often many square miles in extent.  So in order to calculate the volume of a slick we need to measure or estimate the area it covers, then estimate the average thickness over that area.  Then we multiply the area times the thickness to get the volume.

• Estimating Surface Area• Measuring the area is a fairly straight-forward and accurate

process with satellite imagery - we simply trace a line around the visible edges of the slick and compute the area inside that boundary.  For oil spill reports where we do not have imagery, we use the reported length and width of the slick to compute the rectangular area which contains the slick.

• Estimating Thickness• Estimating thickness, however, is another matter.  One way to estimate the thickness of an

oil slick is to observe it's "color" and assign a thickness based on established guidelines for the range of thicknesses that can produce a slick of that color (e.g. "Rainbow sheen").  Tables and guidelines for visual estimation of oil spill volumes are published by the National Oceanic and Atmospheric Administration (NOAA) on their response and restoration website.

• Unfortunately, when using satellite imagery, especially radar (SAR) imagery, we are not able to observe the spectral characteristics that create the apparent color of a typical oil slick, so we cannot use this method. Instead, we use a rule of thumb that provides a reasonable estimation of the minimum average thickness that makes an oil slick at sea visible on satellite imagery.Based on past experience, and the judgment of other experts, SkyTruth has determined that a good rule of thumb for estimating the thickness of an oil slick visible in a SAR image is that the total area is on average at least 1µm (one micron, or 1 millionth of a meter) thick. The actual thickness varies across the whole area, as some parts of the slick may be thicker than the average, and other parts thinner. 

• By measuring the area of the visible oil slick in a SAR image, and assuming the average thickness of the oil across that area is at least 1µm, the minimum volume of oil in the slick can be calculated.

• Calculations

• If there is an observed slick of oil covering 1 km2, then the minimum volume of the oil covering this surface can be calculated in meters:

1000m x 1000m x 0.000001m = 1x106 m2  x  1x10-

6 m = 1 m3

Conveniently, one square kilometer of oil covering the water, multiplied by a 1 µm thickness, is equal to 1 m3  (one cubic meter).Converting to gallons, 1 m3 is equal to 264.17 US gallons, so an oil slick covering 1 km2 a at an average thickness of 1µm contains 264.17 US gallons of oil.  

• Conversion Chart for 1µm Oil Slick

ExampleIf an image shows a slick that covers 50 mi2, then the minimum volume assuming average thickness of at least 1 µm is calculated:

(683.76 Gallons/mi2)x(50 mi2) =  34,188 Gallons of Oil