2.3.1 Stabilisers
Full gauge stabilisers, provide a fixed stand-off distance from the wall of the hole and keep the drill collars concentric with the wellbore, thus reducing the buckling and bending. Stabilisers may however increase torque and drag.
2.3.1.1 Recommended Type of Stabiliser
• The integral blade stabiliser is the preferred type of stabiliser.
• Although integral blade stabilisers are generally preferred, welded blade stabilisers can be used for conductor and surface hole depending on the formation. Generally soft formations and in any cases, above the kick of point for directional wells.
• Replaceable sleeve stabilisers are to be used only in areas of the world where logistics is a real problem (economical considerations). Their main disadvantage is that they restrict the flow circulation in smaller size hole.
The position, size (full, under or Adjustable Gage Stabiliser) and number of the stabilisers in the bottom hole assembly are determined by the directional drilling requirement. In the vertical section their purpose is to maintain the drift angle as low as possible.
Note:
• The near bit stabiliser may be replaced by a full size roller reamer if excessive torque is experienced.
• Do not place a stabiliser at the transition from drill collars to HWDP.
• The use of stabilisers inside casing should be avoided as much as possible (or limited to a short period of time). e.g. while drilling out cement.
2.3.2 Roller Reamers
Roller reamers can be used for drill string stabilisation where it is difficult to maintain hole gauge and in hard, deep formation where torque presents a problem.
Roller reamers do not stabilise as well as integral blade stabilisers. More walk is experienced when they are used, especially if a near bit roller reamer is used. Used with a building assembly, they often increase the building rate.
The type of cutters, will depend on, the formation type. The same roller reamer body can be used for different applications.
2.4 Jars
Double acting hydraulic jars are preferred. Jars are generally used from below conductors or surface casing.
The number of drilling hours and jarring hours should be recorded to enable replacement at the recommended time (this must be provided by the manufacturer). This varies depending upon the manufacturer, hole size, size of jar and deviation.
2.4.1 Jar Position
Run a jar placement program, then optimise for position considering all aspect of the BHA:
• The location of the neutral point in the drillstring should be known and Jars kept out of this area.
• When appropriate (see below), place jars in the drill collar section above the top stabiliser.
Jars should not be run directly next to a stabiliser (minimum of one collar between them).
• Place a couple of drill collars above the jar for hammer weight where possible. HWDP are flexible and will not transmit a blow downwards as well as drill collars.
• The anticipated problem can also influence where to locate the jar:
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1. If it is differential sticking or keyseating, then the jar should be run in the HWDP to avoid being stuck with the rest of the BHA.
2. If it is stabilisers “balling-up” and/or hole swelling then the jars should be positioned in the collar above the top stabiliser.
3. When drilling in new area where common hole problems have not yet been identified, a good compromise is to run some smaller OD spiral drillcollars above the jar.
• Jars have a pump open force which must be overcome when cocking the jar.
Pump open force = Pressure drop below Jars x Washpipe Area The Washpipe area can be obtained from manufacturers data book.
2.5 Accelerators
Accelerators (also called Jar Boosters) are run in the string above jars, they are used to increase the impact force exerted by a jar.
They consist of a slip joint that, as extension of the tool occurs cause further compression of an inert gas (generally nitrogen) in a high pressure chamber. Then, the gas under pressure forces the tool back to its original length. It allows the drill collars below the booster to move rapidly up the hole.
Accelerators are useful in a fishing string or drilling assembly, particularly in high angle holes where the string is in contact with the side of the hole and large amounts of friction may be developed.
2.6 Shock Subs
Shock subs are placed in the drill string, ideally directly above the bit to absorb vibration and shock loads.
They are useful, especially at shallow depth, when drilling hard rocks, broken formations or intermittent hard and soft streaks to limit the wear and failure of the drill string components (MWD, bit, etc.).
2.7 Hole Openers and Under-Reamers
Hole Openers and under-reamers are used to enlarge holes. An under reamer is never as robust as a hole opener but can pass through obstructions (e.g. casing string) of a smaller diameter than the hole it will drill.
2.7.1 Hole Openers 2.7.1.1 Applications
Use to enlarge a pilot hole, which may have been required for one of the following reasons:
• A core was required, standard coring equipment size start at 12 ¼”.
• High quality of wireline log was required which is not likely to be achieved in big diameter hole.
• It is easier to control the trajectory of a smaller hole, especially in very soft formation.
• Drilling through what may be a pressure transition zone or a gas pocket. In small hole, circulation bottoms up take less time and kick are easier to control due to the reduced volume.
A hole opener may also be required if the diameter of the hole has been reduced by the formation expanding into it, so that the full size bit can no longer pass. It may happen in particular in sections containing plastic shales or salt.
2.7.1.2 Guidelines For Use
A hole opener is run either with a pilot bit or with a bull nose which guides the hole opener along the pilot hole. There is thus no need to steer a hole opener and no risk to drill away from the pilot
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hole. The bull nose can be fitted directly to the hole opener or one joint below to give more flexibility.
As an alternative to a hole opener, especially in hole sizes less than 17½”, a “common” bit may be used to enlarge the hole. This is not recommended in soft formation In harder formations the bit is more likely to follow the path of least resistance but it is necessary to measure the deviation of the well at frequent intervals to check that it is following the trajectory of the pilot hole.
The majority of hole openers still use roller cones, with either steel teeth or tungsten carbide inserts depending on the formation. These are available from 8 3/8” (6” pilot hole) to 48” (17 ½”
pilot hole). The number of cones (from 3 to 8) is a function of the size of the hole.
Fixed blade hole openers are available for smaller (less than 17½”) hole sections. They remove the risk of cones falling off and can cut in an upward direction as well should this become necessary (“squeezing formation”).
While using a hole opener:
• Cutter selection will depend on the formation based on the same consideration as for bits
• Soft Formations will normally respond better to higher RPM and lower WOB, while hard formation require higher WOB and less RPM.
• If fractured formations are encountered, adjust drilling parameter to avoid bouncing
• Use sufficient flowrate to obtain a good hole cleaning
• Always stabilise the lower end of the hole opener to prevent it from rotating off centre. A rock bit (i.e. if is not anticipated to be clean) or a bullnose half an inch to an inch smaller than the pilot hole should be efficient.
2.7.2 Under-Reamers
Typical applications include:• Opening the hole below a casing shoe, to provide a larger annular space for cementing the next casing string. This permits for example, the use of a larger intermediate casing string diameter than could be used otherwise.
• Overcome BOP or wellhead size diameter restriction.
• Enlarging the hole annulus within the producing zone for gravel pack completion.
• Opening a pocket to start a sidetrack.
• Reducing dog leg severity
• Enlarging “heaving areas” through problem fault zone.
Since the underreamer has to pass through a restricted bore, it incorporates expandable cutters which stay collapsed when the tool is RIH. The cutters are then expanded into the formation by utilising the differential pressure of the drilling fluid. Once the hole is undereamed to the desire depth, the pumps are turned off, allowing the arms to collapse back into the body for POOH.
Under reamers used to have rolling cones on extending arms, but nowadays, the tendency is to use extending arms fitted with PDC cutters. They can be run with a bullnose or a small drilling bit as for hole openers.
Should limited oversize be required, an alternative would be a bi-centered bit (e.g. 8 1/2” X 9 7/8”) which eliminates the risks associated with under-reamer.
3.0 Drill String Design 3.1 Objectives
The objective of drill string design is to:
• Ensure that the maximum stress at any point in the drill string is less than the down-rated yield strength
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• Ensure that the components and configuration of the drill string minimise the effects of fatigue
• Provide equipment that is resistant to H2S, if H2S is anticipated.
3.2 Assumptions
The following assumptions are made:
• In low angled holes, tension is approximated using the “buoyed weight” method. This ignores the effects of circulating pressure and hole angle on tension. Although not as exact as the “pressure – area” method, any errors are compensated for by selecting an appropriate margin of overpull. ERD and horizontal wells require computer modelling to evaluate torque and drag effects.
• In vertical holes, buckling is assumed to occur up to the point in the string where buoyed string weight equals weight on bit. This is incorrectly termed “neutral point in tension”. In practice, if pressure-area forces are considered, the actual neutral point will always occur below this point unless either the drill pipe becomes stuck or bit pressure drop is increased with the bit on bottom.
• In inclined holes, buckling is assumed to occur when the compressive load in a component exceeds the component’s critical buckling load.
• The tension calculations in the vertical and low angle holes assume a vertical hanging string i.e. a worst case with no hole support. If the hole is not vertical, then the design is a conservative one which is meant to offset the higher tensile drag as the hole angle and step out increase.
• In the ERD designs, tensile drag is ignored for calculations in rotary drilling mode. Errors are small unless rotating very slowly with high penetration rates. Under normal drilling conditions, rotating speed will exceed axial speed.
• Drill string torsional load capacity is fixed at tool joint make-up torque.
• Material yield strength for all components is the specified minimum for the component being considered.
• Drill pipe tube wall thickness is the minimum for the stated drill pipe weight and class.
• Connection torsional strength and make-up torque are calculated using the A.P.Farr formula from API RP 7G.
3.3 Design Factors
Design factors are used to down rate the load capacities of components to provide additional margin for error caused by differences between the assumptions made in design and the real world.
Tension (DFT)
This is used to reduce the drill pipe tensile capacity to establish the maximum allowable tensile load. DFT is typically 1.15
Margin of Overpull (MOP)
The desired excess tension above the normal hanging / working load to account for contingencies such as hole drag, stuck pipe etc. May be any positive amount but typically specified from 50,000 to 150,000 lbs depending on hole conditions.
Excess BHA Weight (DFBHA)
Defines the amount of BHA weight in excess of bit weight that a given BHA will contain. This excess weight provides an extra margin to keep the neutral point below the top of the BHA.
Recommended DFBHA is 1.15 Torsion
Applied torsion is limited to tool joint make-up torque. Standard make-up torque is 60% of tool joint torsional yield strength and standard tool joints are weaker in torsion than the tubes to which they are attached. Therefore, a design factor is not required.
Collapse pressure (DFC)
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Collapse pressure capacities are first down rated to account for the effect of any tension and then further down rated by dividing by the collapse design factor. The DFC is typically 1.1 to 1.15.
Burst pressure (DFBP)
This is used to reduce a component’s burst pressure capacity to give a maximum permissible burst pressure that can be applied. Burst capacity is increased when tension is applied but this is normally ignored.
Buckling (DFB)
This is the high angle well safety factor equivalent to the excess BHA factor for vertical wells.
Both serve to prevent drill pipe from buckling in rotary mode. The difference is that DFBHA
increases BHA length in vertical wells while DFB decreases allowable bit weight in ERD and horizontal wells where the traditional BHA is absent.
4.0 Design for Vertical to Moderate Angle Wellbores 4.1 Design Stages
Working from the bit to surface:
• Choose drill collar size, connection and connection features.
• Determine torsional strength of drill collar connections.
• Determine minimum lengths of drill collar and HWDP sections.
• Check slip-crushing forces.
• Set design factors and margin of overpull in tension.
• Calculate allowable and working tension loads
• Calculate maximum permissible length of each drill pipe section
• Calculate de-rated collapse pressure capacities of drill pipe tubes under tensile loading.
4.2 Drill Collar Size
• Unless mechanical hole sticking is a problem, the largest diameter BHA consistent with other needs should be used.
• The increased stiffness translates into better directional control.
• Presence of collars means fewer connections for a specified weight on bit.
• Larger collars means reduced BHA length and hence reduced differential sticking risk.
• Larger collars have less lateral freedom of movement. This reduces the magnitude of the cyclic stresses generated by buckling and lateral vibration and thus increases connection fatigue life.
• Other considerations include:
• ability to fish
• effective range of pipe handling equipment
• directional control requirements
• hydraulics
• desired features (spiral grooves, elevator groove etc)
4.3 BHA Connections / Features
The following points are applicable to all BHA components including crossovers, stabilisers, motors, LWD and MWD tools, hole openers, under-reamers, jars etc.
4.3.1 Bending Strength Ratio (BSR)
This is the ratio of the relative stiffness of the box to the pin for a given connection.
High BSR’s can cause accelerated pin failure.
Low BSR’s can cause box failures.
Field experience suggests that larger OD collars suffer predominantly from box fatigue cracks even when at or near the optimum BSR of 2.5. This suggests that higher BSR’s might be a more
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appropriate guideline for large OD collars. Conversely, 4¾” collars with BSR’s of 1.8 are rarely found to exhibit box fatigue cracks. This serves to highlight the importance of field experience when choosing BSR’s for particular collar sizes.
The recommended BSR for typical drill collar sizes is shown in the table below. These numbers should be adjusted as determined by local operating conditions.
Recommended BSR ranges
Drill Collar OD Traditional BSR range Recommended BSR range
< 6” 2.25 – 2.75 1.8 – 2.5
6” – 7 7/8” 2.25 – 2.75 2.25 – 2.75
= or > 8” 2.25 – 2.75 2.5 – 3.2
Transitions between sections of different stiffness act as stress concentrators. This problem is worsened by short, straight crossovers. If a straight (non-bottleneck) crossover is used and its OD is larger than the HWDP tool joint OD, the resulting BSR of the upper crossover connection may be very high, resulting in accelerated pin fatigue. Bottleneck subs alleviate this problem by providing a smooth change in cross section.
The equations used in the calculation of BSR are given in Appendix 1.
4.3.2 BHA Connection Thread Form
Thread forms with full root radii should be used in all BHA connections to maximise fatigue resistance. API regular, NC and Full Hole connections all meet this requirement although the API NC thread form (V-038R) is superior to the others. The H-90 thread form is also considered acceptable even though it does not have a full root radius.
All connections that employ a “standard” V-065 thread form, except PAC, are obsolete. The
“NC” thread form should be specified instead of the obsolete “IF” or “XH” names as this will eliminate the possibility of receiving the fatigue prone V-065 thread form.
4.3.3 Stress Relief Features
Stress relief features should be specified on all BHA connections NC-38 and larger. These features include the “stress relieved pin” and “bore-back box”. Both extend connection fatigue life by eliminating disengaged thread roots, which act as stress concentrators. Stress relief features are beneficial on all HWDP connections. Pin stress relief grooves are not recommended for connections smaller than NC-38 because they may weaken the connection’s tensile and torsional strength and because fatigue is often less of a problem than non-cyclic loads on small connections. Bore-back could be used on smaller connections without weakening them and should be considered if box fatigue is occurring.
4.3.4 Cold Rolling
Cold rolling BHA (and HWDP) thread roots and stress relief surfaces increases fatigue life by placing a residual compressive stress in the thread roots. Not beneficial on normal weight drill pipe where fatigue is rarely a problem due to the relative stiffness of the tool joint compared to the tube.
4.3.5 BHA Connection Torsional Strength
Since torsion is transmitted from the top down, BHA connections are usually subjected to lower torsional loads than the connections above. However, if "stick / slip" is occurring or a tapered assembly is being used, torsional strength should be checked to confirm that it is greater than the torsion expected within the operating BHA. Tool joint torsional strength tables cannot be used directly for this purpose because tool joint and drill collar materials have different yield strengths. Drill collar connection torsional strength can be calculated as follows:
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f TS =MUT
where TS - DC connection torsional strength (ft lbs) MUT - DC make-up torque (ft lbs)
f - factor from table below
Factors for converting drill collar MUT to Torsional Strength Connection Type OD < or = 6-7/8” OD > 6-7/8”
PAC f = 0.795 n/a
H-90 f = 0.511 f = 0.562
Other f = 0.568 f = 0.625
4.4 Stabiliser and Jar Placement 4.4.1 Stabilisers
The number, size and position of stabilisers is often determined by directional considerations.
However, they also have an impact on other design aspects.
1. While rotary drilling vertical wells, the lower part of the BHA will suffer buckling and be supported by the sides of the hole. Stabilisers reduce connection stress/ increase fatigue life by restricting the freedom of lateral drill collar movement.
2. If mechanical sticking is a concern, more or larger stabilisers may increase the likelihood of getting stuck. Conversely, when differential sticking is a concern, the presence of stabilisers can reduce this risk by keeping the collars off the sides of the wellbore.
4.4.2 Jars
Jar placement is dictated by the need to have maximum impact should the BHA become stuck while attempting to ensure that fatigue failure does not occur. Until recently, the rule of thumb was to run the jars in tension. More recently, in high angle wells, it has become acceptable to run jars in compression. This has led to confusion regarding placement of jars i.e. whether to run
Jar placement is dictated by the need to have maximum impact should the BHA become stuck while attempting to ensure that fatigue failure does not occur. Until recently, the rule of thumb was to run the jars in tension. More recently, in high angle wells, it has become acceptable to run jars in compression. This has led to confusion regarding placement of jars i.e. whether to run