Sample chapter_Oil and Gas Well Drilling Technology.pdf

July 10, 2017 | Author: David John | Category: Casing (Borehole), Reflection Seismology, Oil Well, Drilling Rig, Geotechnical Engineering
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CHAPTER-2: Oil and Gas Well Drilling Technology

CONTENT 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13.

Well planning Drilling method Drilling rigs Rig operating systems Drilling fluids function, properties and equipment Oil & gas well cementing operations Drill bit types and their applications Drill string function, operations, selection & design Casing string function, operations, selection & design Drilling problems, their control & remedies Directional drilling tools Directional survey Application of horizontal, multilateral, extended reach wells

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1. Well planning Introduction There are various steps involved in drilling of a well:       

Selection of drilling location based on geological/ seismic survey data Readying of drill-site/survey of sea-bed for moving rig Well planning Rig-move Rig building Spudding a well Drilling of well till hermetical testing of production casing.

Well Planning covers the following:      

Well Design Casing & Cement Design Drilling fluid design Drill bit selection Well control equipments Safety Equipments

Objective Well planning is an orderly process involving a number of steps. The flow path for well planning is given in fig.1.1. The objective of well planning is to formulate a drilling programme for many variables for drilling a well that has the following characteristics: (1) Safety (2) Minimum cost (3) Usable

Fig. 1.1 Flow path for well planning

Unfortunately, it is not always possible to accomplish these objectives on each well because of constraints based on: 


Drilling equipment


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Fig. 1.2 Well costs Vs. Well Planning efforts

Safety Safety should be the highest priority in well planning. Personnel considerations must be placed above all the other aspects of the plan. The second priority involves the safety of well and rig-equipment. The contingency plan for fire and blowout should form an integral part of well plan.

Minimum cost An important objective of well planning is to minimise the cost of the well without sacrificing or compromising on the safety aspects. In most cases, the cost of the well can be reduced to certain extent as additional effort is given to the well planning (fig. 1.2). Well costs can be reduced dramatically if proper well planning is implemented.

Usable holes Drilling a hole to the target depth is unsatisfactory if the final well configuration is not usable. In this case, the term “usable” implies the following: 

The hole diameter is sufficiently large so an adequate completion can be made.

The hole or producing formation is not irreparably damaged.

This requirement of the well planning process can be difficult to achieve in abnormal-pressure, deep zones that can cause hole-geometry or mud problems.

Activities before start of drilling operation Activities undertaken prior to start of drilling operation can be broken down into the following steps: (1) Release of location.


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(2) Survey of surface/subsea location. Sometimes the cost can be reduced by a small change in surface location. (3) Civil works and foundation for onshore drillsite and soil coring/sea bed survey in case of offshore well. (4) Preparation of Geo- Technical Order. (5) Preparation of complete well plan/programme. (6) Preparation of bill of material and initiation of purchase procedure, if required. (7) Procedures from obtaining sanction for purchase to receipt of material. (8) Rig allocation and its shifting to the new location.

Input data for well planning The information required for planning of a well are: (1) The objective of the well. (2) Well data package consisting of seismic data, location map, structural map, expected pore pressures, offset and correlation logs and information on formation type, top and thickness. (3) Offset and correlated drilled wells data consisting of bit record, mud reports. Mud logging data, drilling reports, well completion reports, complication reports and production/injection histories. (4) Proposed logging, testing and coring programmes. (5) Government reflection and Company's policy.

Geo- technical order The various input data are thoroughly analysed and the Geo- Technical Order (Go T .0) is prepared which provides broad guidelines for drilling of the well. G.T.O. furnishes the following details: (a) General data like well name, well number, area location, water depth, elevation, well type, category, objectives of the well etc. (b) Geological data consists of following details: (1) Depth

(2) Age (3) Formation

(5) Interval of coring

(4) Lithology

(6) Electro logging

(7) Collection of cuttings

(8) Angle of Dip

(9) Oil/gas shows (10) Formation pressure (11) Formation temperature (12) Mud loss/caving (c) Mud parameters consist of (1) Type of mud (4) pH

(2) Specific gravity

(5) Percentage of sand

(3) Viscosity (6) Filtration loss

(d) Drilling data includes (1) Casing policy and rise of cement

(2) Type of drilling

(3) Type and size of bit

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(4) Number of bits expected (7) RPM of rotary

(5) Meterage per bit

(6) Weight on bit

(8) Stand-pipe pressure (9) Pump discharge

(10) Bit nozzle details (11) Drilling time

(12) Remarks, if any

Drilling programme preparation The preparation of good Drilling Programme is very vital for safe and effective drilling operation. Drilling Programme can be broken down into 12 main sections: (1) Well details (2) Well objectives (5) BOP requirements

(3) Casing policy

(6) Cementing programme

(8) Survey requirements (9) Mud programme (11) Evaluation requirements

(4) Wellhead selection (7) Deviation programme

(10) Bit and Hydraulics programme

(12) Estimation of well cost

All Drilling Programmes will contain the above information in some form. These sections are covered in more detail below. Specialised wells could also contain other relevant data.

Well details This is a brief summary of the well location, field/structure, type, depth, operatorship and ownership. A typical layout of this is shown below: Location

SP 1700 off line GK-2

Field/ Structure Kutch/GKH Well Name


Well Type

Exploratory '8' Expendable

Location Data

Latitude 220 27’ 19” N Longitude 670 36' 09.5" E

Water Depth

108 m

Target Tolerance


Total Depth

4515 m



Name of the rig Sagar Vijay Type of rig


Well objectives Well objectives are defined in the well release order issued by the exploration department. A typical format for setting out the objectives is given below: "To test hydrocarbon prospects of fore reef facies in Oligocene, Miocene and carbonate in Eocene section of GKH feature".

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Casing policy Functions of casing Casing pipes are put into a well bore for the following reasons: (1) To isolate troublesome or unstable formations which may include heaving shales, lost circulation zones and flowing halites. (2) To isolate different pressure or fluid regimes: (a) To protect fresh water horizons especially domestic water bearing sandstones in case of land wells. (b) To protect producing formations from mud and mud filtrate contamination. (c) To protect weaker zones from breakdown caused by heavy muds whose hydrostatic head is required for pressure control purposes in lower sections. (3) To control well pressure by containment of down hole pressures. (4) To provide a stable seat for packers, liner hangers etc. (5) To support the wellhead and BOP stack. (6) To confine produced fluid to the wellbore and provide a flow path for it.

Estimation of formation pore pressure Most of the decisions pertaining to casing policy are based on formation pore pressure. It is imperative, therefore, that pore pressures be known or estimated as accurately as possible. The two sources of well pressure data for well planning are geophysical/geological data and offset well data. Offset wells provide more accurate data, however I in the exploratory wildcat wells in new area, there will be no offset well data available. This means that pore pressure prediction has to be done by analysing seismic data. Seismic data is used in the exploration phase to locate potential reservoir traps and to estimate formation tops in the lithological column. It can be used to give a qualitative estimate of the formation pressure and hence arl indication of any pore pressure abnormalities. Seismic data is acquired by creating acoustic waves using some form of explosion or implosion and measuring the time taken for the wave to travel down to a subsurface reflecting bed and then back to the surface. The point of origin of the wave on the surface is called a shot point and the returning waves are detected at the surface by series of geophones or, if offshore, hydrophones, placed at known distances from the shot point. The velocity at which seismic or acoustic wave is propagated through a formation depends on the density and elasticity of the rock and the type of fluid occupying the pore space. The degree of compaction (i.e. relative depth) also determines the seismic velocity in a particular formation. Prior knowledge of seismic velocities, in particular formations over a range of depths, can therefore enable fairly reliable predictions of formation lithology to be encountered. The presence of overpressured formations and an estimate of the magnitude of the overpressure can be predicted by studying the seismic velocity data from shale sequences. As the density and elasticity of shale increases with depth and compaction, the seismic velocity will increase. Overpressured shales are undercompacted, which, at a particular depth, will result in a lower density and elasticity than 6|Pa ge

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expected and therefore, a lower seismic velocity than expected. By analysing formation interval seismic velocities in normally pressured shales and comparing them with data from apparently overpressured shales at similar depth,the extent of overpressure can be estimated. Shallow gas sands present one of the most difficult well control problems in offshore drilling operations. They tend to be high pressure and low volume and can unload a well very quickly with risk of toppling jack-up rigs, sinking floaters and causing fire and explosion. In order to try and identify poterltial gas bearing zones at shallow depths, detailed high resolution seismic surveys are performed and analysed by what is known as the 'bright spot' technique. The fact that acoustic waves are severely impeded when travelling through gas charged formations produces strong seismic reflections. These show up as relatively high amplitude anomalies on the seismic section and are characterised by their visual appearance as bright spots. By mapping them on a horizontal section their spread can be studied and compared to the proposed well location. This high resolution seismic technique can detect gas charged sands as thin as one metre. The absence of bright spots does not necessarily mean there will be no shallow gas and conversely the presence of bright spots can be caused by an anomaly other than shallow gas. Even so, if shallow seismic surveys do indicate a bright spot at the intended well location, it would be prudent to change the location and avoid drilling into it. It is not possible to predict formation pressures in shallow gas sands from the seismic data but it is quite possible, though not normally the case, that they are overpressured and should be treated accordingly. Shallow gas tends to be contained in low volume pockets and if allowed to flow freely through a well-designed diverter system, should quickly deplete and exhaust itself . Structural maps are produced by the geologists from seismic and offset well data in order to evaluate the geology over large areas of interest. Interpretation of the seismic data can enable the geologist to identify subsurface structures that have the potontial to trap hydrocarbon accumulations. Furthermore, by correlating formation tops from the lithological columns of offset wells and interpolating at the point of interest, a geological prognosis can be made of the proposed well. If an offset well appears geologically similar to the well which is to be drilled, then preparing the Drilling Programmes should be relatively straightforward with all the appropriate data to hand. In heavily faulted areas however, even wells drilled fairly close to each other can exhibit quite different problems and should be treated as wildcats.

Estimation of formation fracture pressure Formation fracture pressure prediction can be based on anticipated geology and offset well records. Most rocks of a certain type will exhibit typical characteristics. This can be used to assist in fracture gradient estimation. It is vital to have an accurate assessment of this so that the casing seat can be selected in an effective manner. Once a leak-off test has been carried out in the well, equations such as 'Daines' are used by employing values of Poisson's Ratio for given formations to estimate probable fracture gradients at other depths in the well. In case of continuous depositional basins, Eaton's equation with suitable modification can be used for the estimation of fracture pressure gradient.

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After the pore pressure and fracture pressure charts have been constructed, the Drilling Engineer should liaise with Production Engineers to decide about the likely size of final production conduit so as to decide about the different casing sizes required to be lowered at various casing seats selected. The setting depth will depend on competent formations with high fracture gradients, lengths of open hole sections and requirements of cementing programmes and other anticipated down hole problems.

Casing design The following are the criteria which must be considered when carrying out casing design: (1) Burst (2) Collapse (3) Tension (4) Other loadings Burst is pipe failure which occurs when the pressure inside the pipe is greater than the internal yield value of the pipe plus the pressure outside the pipe. Both the strength of the formation at the shoe and the burst strength of the casing must be considered. The ideal situation is for both formation and casing to be able to withstand the pressures resulting from a full gas column to surface and the additional pressure resulting from circulating the gas out. However, in some cases, casing may have to be designed on a limited kick basis which has been discussed in the chapter on casing design. Collapse will occur when the external force on the pipe is greater than the combination of the internal pressure plus the collapse rating of the pipe. It occurs as a result of either or a combination of: (1) Reduction in hydrostatic head exerted by the fluid inside the pipe. (2) Increase in hydrostatic head exerted by the fluid outside the pipe. (3) Mechanical forces created by plastic formations, flowing salts etc. The above three factors can result from the following situations: (1) Inadequate fill up of casing when running (2) Lost circulation (3) Cementing (4) Casing wear (5) Air or foam drilling. The casing has to be designed for complete evacuation plus an allowance for wear due to loss of lubricity. (6) Halite sections (7) High drawdowns for testing purposes. It is generally accepted that a exploratory Well will not be subjected to high drawdowns but this should be considered for development wells. (8) Acidising or fracturing a horizon could result in an increase in external loading to a depth above the packer if a path of communication exists. (9) Similarly squeeze cementing could increase external loadings above or below packers. (10) Corrosion will eventually decrease the collapse strength of the pipe. For most wells, only the first three situations are usually considered.

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Tensile failure will occur if the pull exerted on the pipe is too great for the tensile strength of the pipe or coupling. For designing the pipe in tension,tensile loads on the casing should be calculated at the following stages : (1) When running the pipe (2) When cementing (3) When pressure testing (drilling phase)

Wellhead selection Having completed the casing design, we have all the information required to allow us to select a wellhead. The wellhead must be of the correct pressure rating, designed for the desired service like (H2S) and be capable of accommodating all designed and contingent casing strings. Having selected a wellhead, its specification should be included in the Drilling Programme along with a sectional view of its component stack up.

BOP requirement The BOP requirement for a given well will depend on company policy and anticipated bottom hole pressures. Surface holes have either no BOP requirement, or will need to use a diverter.

Cementing programme Cement is used for zonal isolation in the well. The effectiveness of this zonal isolation depends on three main factors all of which must be considered at the planning stage. (1) Slurry design

(2) Casing accessories selection (3) Displacement methods

Slurry design Oil well cement slurry consists of cement, water and additives. The first calculation that we must make in cement programming is to calculate the volumes required. This is proportional to the height to which the cement will be displaced to in the annulus. Secondly, we must know or estimate the bottom hole temperature so that we can predict slurry behavior downhole. Thirdly, we must look at the mud which is in use while drilling and consider what effects, if any, it could have on the cementing process. Fourthly, we look at the formations in which the casing is being cemented to see if these present any particular problem. Finally, we look at the hole geometry to see what annular space consideration might affect the quality of the cement job. Definitions of some of the important slurry properties are given below: Yield: The yield of the cement, in cubic metre per sack, is the volume of space the slurry will occupy after having been mixed with the water and additives as per design specifications. A high yield slurry is one that will contain relatively large amount of water and therefore be of relatively low density.

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Density: This is an important factor since the slurry must be dense enough to control formation pressures but not cause formation break-down. Light weight slurries can be produced by adding extenders such as' bentonite to the slurry mix water or by aerating the slurry. Weighting materials such as ilmeninte, hematite and barite can be added to increase slurry density. Thickening time: This determines how long the slurry remains pumpable and depends mainly upon the cement composition and downhole temperature. It can be manipulated by using retarders. Mix water: The amount of mix water used will depend on the programmed slurry density. The water type used is usually that which is most readily available i.e, sea water in offshore and freshwater in onshore wells. If casing is being cemented across salt or halite sections then the mix water should be salt saturated to prevent ionic exchange between the slurry and formation. Compressive strength: Cement must have compressive strength to support the casing and isolate zones. The speed at which cement slurry develops compressive strength depends to a great deal on down hole temperatures. If temperatures are too low to allow a particular slurry to reach sufficient compressive strength in a reasonable amount of time, chemicals can be added to a slurry. These accelerate hardening and promote strength development. Calcium chloride is the most common accelerator. Fluid loss: This is the amount of water lost from slurry to the formation for a given pressure differential. If this is not controlled, then fluid can be lost from the slurry causing premature or 'flash' setting. To combat this problem, fluid loss chemicals are used in the slurry for jobs which entail high pressure differentials between slurry hydrostatic pressure and formation pressure. Clearly the porosity of the formation will have a big influence on the need for fluid loss chemicals too. Flow characteristics: Good flow characteristics contribute to good formation bonding and less pumping difficulties. Additives are available to reduce cement friction and to encourage slurry turbulence at low pump rates.

Casing accessories selection Having designed the cement requirements for the well, we need now to look at the accessories that we will use to ensure good cementation. The main accessories used are listed below: A casing shoe is screwed or welded onto the lower end of the lowest joint of casing. These are of four types: (1) The guide shoe is the simplest. It merely serves as an aid to guiding the casing in the open hole and has a hole in the middle which allows the mud to pass freely through the string. The guide shoe is not widely used. (2) The float shoe is similar, externally, to the guide shoe but contains a non-return valve that allows fluid to flow out of the casing but not into it. The main reason for using this type of shoe is that it gives better well control during running casing. The casing should be filled from surface during casing runs. (3) A differential fill-up shoe uses a valve which allows mud to flow into the casing to keep it partially full. A steel ball can be dropped and pumped into the shoe to shear out a seat and convert the shoe into a regular float type.

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(4) The automatic fill shoe is also designed to avoid having to fill up the casing all the time from the surface. It incorporates wedges to hold the check valve open so that the mud can flow both into and out of the casing via the shoe. When required, the automatic fill shoe can be tripped to act like a regular float shoe by pumping down the string at a preset rate to pump the wedges out. Out of the four types mentioned above, float shoes are most commonly used. Float Collars are usually placed at one or two joints above the casing shoe. They serve as a stop for the cement wiper plug so that all the slurry is not displaced into the annulus. Float type collars provide backup for the float shoe. Differential type float collars are available and should only be run in conjunction with a differential float shoe. A baffle collar is merely a ring, usually set in a casing coupling, on which a wiper plug is designed to seat and seal to allow pressure testing of casing. Note: The pressure rating of shoes and collars must be at least the proposed test pressure of the casing. Multistage collars are used to locate two distinct separate columns of cement in the annulus when one continuous column would produce too much hydrostatic pressure on the formation, or specialised zonal isolation, or communication is required. After performing the first stage cement job an opening 'bomb' is allowed to free-fall and set in the opening sleeve of the multistage collar. The casing is then pressurised to shift the sleeve down and open the circulating ports. After the second stage slurry has been placed inside the casing, the wiper plug is pumped down and seated in the closing sleeve. A pressure increase then moves this sleeve down to cover the ports and renew casing integrity. Centralisers are placed on the outside of the casing to keep it concentric with the hole. Centralisers are of two types, spring and rigid. Rigid centralisers are used just below wellheads and inside casing shoes. All other applications demand spring centralisers. Centralisers are located over or between stop collars which are secured to the casing to ensure that they do not move. Plugs have hollow drillable alloy interior and rubber outer fins to wipe clean the casing walls. The bottom plug has a diaphragm that is ruptured by pressure after it seats on the collar. The top plug has solid alloy insert and is used to pressure test the casing against cementing. Plugs are available in sizes which cover various weights of a given casing size. When ordering them,the casing weight and size must be stipulated.

Displacement methods Displacement Cement should be displaced in a state of turbulent flow. Since displacement is usually done using rig pumps, achieving turbulent flow is usually not a problem. In case there is difficulty in achieving turbulent flow with the existing rig pump, the cement should be displaced in a plug flow regime. Preflushes, spacers and scavenger Any mixing of mud and cement will reduce the quality of the cement job. Preflushes, spacers and scavenger are used to separate mud and also to condition the hole to give better ultimate bonding between cement and formation. Preflushes and spacers are usually made up of a combination of cement, mix water, weighting material and additives designed to help remove wall cake to give better cement/formation bonding characteristics. The weighting material is to provide primary well control. Scavenger is a diluted form of the cement slurry used in the main job. Adding cement obviously brings up the weight of the mix and if primary well control is a potential problem then the scavenger weight can be controlled by the amount of cement used. The volume of preflush, spacers or scavenger used will depend on the perceived needs of the well. These should be sufficient to clean the hole and separate the mud and cement, but not to the extent that the hole will collapse. 11 | P a g e

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Deviation programme Directional drilling has now become an essential element in oilfield development, both onshore and offshore. The application of directional drilling can be grouped into the following categories:(a) Side tracking (b) Drilling to avoid geological problems (c) Controlling vertical holes (d) Drilling beneath inaccessible locations (e) Offshore development drilling, (f) Horizontal drilling (g) Relief well drilling. Assuming that a target rig site has been selected, for directional planning considerations, the values that must be identified are as follows; -Lateral or horizontal displacement from the target to a vertical line from the rig site. -Kick off point (KOP) -Desired build angle rate -Final drift angle -Plan type: Straight kick Vs Curve -Desired drop angle rate in case of 'S' curve.

Careful planning before the directional well is spudded can lead to substantial savings in the cost of drilling. There are many factors which influence the trajectory of the wellbore. Some of these may be difficult to estimate (eg. amount of bit walk which may occur in certain formations). The experience gained from drilling previous directional wells in the same area is, therefore, very useful and should be incorporated at the planning stage of the next well. A review of previous drilling practices and problems should give better guidelines for future directional drilling.

Highly deviated wells (extended reach) Highly deviated wells may be described as those wells whose inclination exceeds 60 degree for most of their length. The most obvious advantage to be gained by drilling high angled wells is the increase in horizontal reach from a central platform. Another potential benefit of drilling highly deviated wells is the increased length of the completion zone through the reservoir . The major technical problems in drilling highly deviated wells are related to the effect of gravitational forces as the angle of inclination increases. As the angle of the hole increase, the axial component of gravitational force reduces, while the lateral component increases. As a result of this: * there is increased frictional resistance against the bore hole, making it more difficult to run and pull tools. * the tendency for solids to settle out from the drilling fluid and cement slurries. * it becomes more difficult to control direction and apply WOB.

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It is possible to extend directional drilling techniques to increase the inclination to 60 -90 degrees, although certain alterations may have to be made to drilling practices.

Horizontal drilling A horizontal well is one where the inclination reaches 900 through the reservoir section. Most of the horizontal wells drilled have employed basically the same techniques as used in conventional directional wells, Careful attention must be paid to the planning of trajectory, directional surveying, use of down hole motors and turbines, selection of casing seats, choice of mud type and mud properties. With the help of horizontal drilling technique, it is now possible to profitably exploit heavy oil reservoirs, marginal oil fields and thin bed reservoirs. Additionally the ever troublesome water/gas coning problem is substantially minimised. Depleted reservoirs, the production from which has gone down much below economic value, have now been revived to be a good producers by drilling sufficiently longer intervals horizontally in the pay beds. The extra cost of drilling the horizontal well must be justified by the potential benefits of additional production.

Drain hole drilling or short radius drilling In this type of profile,the well is drilled vertically using conventional techniques. After logs or DSTs have been carried out to evaluate the formation,the well is plugged back to a point above the oil-water contact. A special BHA is then run which is used to build up angle rapidly along a circular arc of about 6-12 m (corresponding to a build up rate of 2-3 degree per foot drilled) reaching almost horizontal after drilling only 15-18 m of hole. The achieved angle is then held using a stabilised BHA through the reservoir section. These small diameter holes are generally left uncased. The same technique can be repeated further up the hole for multiple zone exploration and production from single wellbore. It is also possible to drill out of a cased hole (side track) after a window has been cut This type of profile can be used for producing from tight formations and reducing gas or water coning problems.

Survey requirements In order of increasing complication, the five different methods of survey are as follows: Totcos are clockwork units which measure hole angle by using a pendulum mechanism with a pin on the end. They are crude but effective and since they only measure hole angle there is no need for monel drill collars in the BHA to overcome magnetic influences. A baffle plate is placed just above the bit inside the drill collars and the survey barrel is run in on sand line, slick line or dropped and recovered. Totco instruments are typically available in 0-8 degree units & 0-90 degree units and are unaffected by hole temperature. Magnetic single shots have magnetic compasses built into them. in addition to the angle measuring units. Information is gathered using a small camera in the instrument, which takes a photograph of the compass heading and attitude. It is run in the same manner as the Totco, but does need monel drill 13 | P a g e

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collars to reduce magnetic influences. Furthermore, it is sensitive to down hole temperature and unless 'heatshield' type units are used, the photographs or survey discs can burn up before they can be recovered and developed. Magnetic multishots are similar in principle to the magnetic single shot but with the additional ability to record magnetic inclination and direction on a film strip at regular depth intervals. A magnetic multishot barrel is dropped down to the BHA before it is tripped out of the hole. The BHA must have a non-magnetic drill collar installed. Electronic multishots measure survey data using triaxial magnetometers which measure components of the earth's magnetic field and triaxial accelerometers which measure components of the force of gravity. These components are then interpreted to give inclination and direction. The housing for these sensors is identical to that of the magnetic multishots with the exception of the outer diameter of the barrel being larger. They are used in a similar fashion, that is dropped into the BHA before pulling out of the hole. Directional MWD in the form of drill collar, is a part of the BHA and measures survey data while drilling. The sensors (magnometer and accelerators) used in these tools are identical to the ones used in the electronic multishots. These are toughened and made suitable for the drilling environment. Such device can be used with a high degree of accuracy, particularly when the data is computed at surface. This allows for the application of stringent calibration factors and temperature compensation. The data from these tools is transmitted to the surface in real-time. Anyone of three types of transmission system (positive or negative mud pulses or the continuous wave system) can be used. This choice depends on the service companies.

Mud programme In practice, mud programming can be broken down as follows: (1) Determination of mud weight requirement to maintain primary well control. (2) Determination of suitable 'trip margin' which is added to the primary well control mud weight to give a programmed mud weight. (3) Confirmation that this mud weight does not exceed formation fracture strengths when considered in a dynamic mode. (4) Analysis of formations to be drilled and the likely reaction of these to the available drilling fluid alternatives. Using this information. select a basic mud type such as: Water-based: * freshwater mud * seawater mud * calcium mud * lignosulphonate mud * polymer mud Oil-based: * invert oil emulsion mud * environmentally sensitive oil-based mud * true oil mud (5) Determination of fluid loss requirements (6) Determination of pH requirements (7) Determination of viscosity requirements (8) Determination of temperature stability requirements (9) Analysis of rig mud treatment equipment to meet hole requirements with selected mud types 14 | P a g e

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Having decided on the mud system required for a well, the mud treatment equipment available on the rig should be appraised to check compatibility with the selected system. The treatment equipment falls into four main groups: Shale shakers: These are the single most important component in the system since they are the initial cuttings removal system and remove the major portion of drilled solids circulated out of the well. Double-deck shakers are fairly standard these days and they allow a coarse upper and fine lower screen to increase cutting removal efficiency. Mud cleaners: By employing both de-silting hydrocyclones and fine mesh vibrating screen, mud cleaners effectively remove fine drilled solids from weighted muds without excessive barite loss. De-sanders and De-silters: They employ hydrocyclones to remove drilled solids. The smaller the hydrocyclone, the finer will be size of the solids that can be removed. Centrifuge: The last stage in the treatment process is usually the decanting centrifuge which can remove solids down to 1 or 2 microns in size. They are particularly important when using oil-base muds. Barites can be recovered for reuse in the mud system.

Bit and hydraulics programme Bit selection and hydraulics optimisation is discussed in detail in chapter 6 and 8 respectively. Bit selection: To select a bit the following factors are considered: * formation drillability and characteristics * directional implications

* mud system in use

* availability

Formation drillability: The best indication of formation drillability is bit performance in nearby wells. If this information is available then selection is made easy. On wildcat wells, however some assumptions have to be made and then the results of actual runs analysed. Tricone bits for soft formations drill by gouging and scrapping action. They gouge their way into the formation and sometimes can drill so fast that the penetration rate must be controlled to allow efficient hole cleaning. In soft to medium -soft formations that are not too sticky, PDC bits offer the best alternative, especially in oil-base mud. Harder formations will be drilled by using insert bits with journal bearings and gauge protection or alternatively diamond bits. Selecting exactly the right bit requires field experience, however, it will usually be worth the effort of trial and error to determine the correct PDC bit and premium bit especially for development drilling. Mud systems in use: If oil-base mud is being used, it is probably to control shale problems. In this case, PDC bits will probably offer the best choice of bit. PDC bits do also work effectively in waterbase mud but perform better in oil-base muds. Sealed bearing bits should be used, if the drilling fluid contains abrasive particles, to prevent premature bearing failure. Directional implications: Most tricone bits used for rotary drilling will exhibit some right-hand walk tendency. PDC bits on the other hand due to their symmetrical cutting action tend to drill straight

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ahead. If the well is planned to be drilled with tricone bits, then it is advisable to lead the well to the left and allow the natural tendency of the bits to pull the well back on course. Hydraulics programme: Once the mud has been programmed, the hydraulics implications of using this mud should be considered. 'Hydraulics' in this case, just means looking at the mud dynamically rather than statically. Annular Velocity (A V): A certain minimum annular velocity is required for a given mud type to prevent cuttings slippage through the mud and to effectively lift the cuttings out of the hole to the mud treatment equipment. Bit and hole cleaning: Drilling fluids flow in either a laminar or turbulent manner (or in a combination of these). Laminar flow will cause less hole erosion, however, turbulent flow is likely to clean the hole better. In practice, both laminar flow and turbulent flow are acceptable in the annulus depending upon the bore hole condition. There are two main theories concerning how much hydraulic horsepower should be expended at the bit to gain maximum cleaning efficiency. The first theory is the maximum hydraulic horsepower theory, which in practice means expending 2/3rd of the available HHP at the bit. The alternative theory is the maximum jet impact theory which in practice means expending around 50 % of the available HHP at the bit. It is difficult to answer which of these theories is the best one to use for a given set of circumstances If the bit is performing effectively and the hole is being cleaned, then the hydraulics is adequate. In practice, this will mean that the HHP being expended at the bit is probably in the range of 50-60 percent.

Evaluation requirements In this part of the programme, the evaluation requirements necessary to meet the well objectives should be formatted as follows: (1) Drilling log requirements (2) Mud logging requirements (3) Coring requirements (4) MWD requirements (5) Electric logging requirements (6) Testing requirements

Well cost estimation Preparing cost estimates for well is the final step in well planning. A properly prepared well cost may require as much engineering work as the actual well design. After the technical aspects are established, the expected time required to drill the well must be determined. The actual well cost is obtained by integrating expected drilling and completion times with the well design. Elements of well cost: The cost of well is based on 8 main elements which are as follows: (1) Preparatory: This includes the cost of land, approach road, rig foundation and all other civil works. (2) Manpower: This is the cost incurred on the drilling crew in form of salaries, allowances and other payments. (3) Services: This includes the cost on services namely geology, geophysics, cementing, transport, workshop, production testing, catering, sea bed surveys etc.

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HydrocarbonZ Educational Services

Petroleum Engineering Gate – 2016

(4) Materials: This covers the cost on casing pipes, bits, wellhead, cement, mud chemicals, POL (Petroleum Oil Lubricants) and other consumable materials. (5) Project overheads: The project overheads include all the other costs on drilling at the project level which are incurred towards drilling except the cost of depreciation. (6) Regional and Headquarter overheads: This includes the cost incurred at Regional and Headquarter level towards drilling activity as apportioned for a given well. (7) Depreciation of rig equipment: Depreciation is worked out on straight line method and the cost is assigned to well in proportion to the rig days taken. (8) Depreciation of drillpipes: This element of well cost is based on per meter depreciation which is worked out centrally for different regions depthwise, based on the replacement cost of the pipes during the preceding year. In the above elements some of the costs are determined in terms of the rig days (cycle days) spent on the well, while others can be determined separately for the well itself.

Well-type classification The drilling engineer is required to plan a variety of well types, including: 


Exploratory holes




Table 1.1-Well-Type Characteristics

Generally, wildcats require more planning than the other types. Infill wells and re-entries require minimum planning in most cases. Wildcats are drilled where little or no known geological information is available. The site may have been selected because of wells drilled some distance from the proposed location but on a terrain that appeared similar to the proposed site. The term “wildcatter” was originated to describe the bold frontiersman willing to gamble on a hunch. Rank wildcats are seldom drilled in today’s industry. Well costs are so high that gambling on wellsite selection is not done in most cases. In addition, numerous drilling prospects with reasonable productive potential are available from several sources. However, the romantic legend of the wildcatter will probably never die. Characteristics of various well types are shown in Table 1.1.

Formation pressure The formation, or pore, pressure encountered by the well significantly affects the well plan. The pressures may be normal, abnormal (high), or subnormal (low). Normal-pressure wells generally do not create planning problems. The mud weights are in the range of 8.5 to 9.5 lbm/gal. Kicks- and blowout-prevention problems should be minimized but not eliminated altogether. Casing requirements can be stringent even in normal-pressure wells deeper than 20,000 ft because of tension/collapse design constraints.

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HydrocarbonZ Educational Services

Petroleum Engineering Gate – 2016

Subnormal-pressure wells may require setting additional casing strings to cover weak or low-pressure zones. The lower-than-normal pressures may result from geological or tectonic factors or from pressure depletion in producing intervals. The design considerations can be demanding if other sections of the well are abnormal pressured. Abnormal pressures affect the well plan in many areas, including: 1) Casing and tubing design

2) Mud-weight and type-selection

3) Casing-setting-depth selection

4) Cement planning

In addition, the following problems must be considered as a result of high formation pressures: 1) Kicks and blowouts

2) Differential-pressure pipe sticking

3) Lost circulation resulting from high mud weights

4) Heaving shale

Well costs increase significantly with geopressures. Because of the difficulties associated with well planning for high-pressure exploratory wells, many design criteria, publications, and studies have been devoted to this area. The amount of effort expended is justified. Unfortunately, the drilling engineer still must define the planning parameters that can be relaxed or modified when drilling normal-pressure holes or well types such as step-outs or infills.

Planning costs The costs required to plan a well properly are insignificant in comparison to the actual drilling costs. In many cases, less than U.S. $1,000 is spent in planning a U.S. $1 million well. This represents 1/10 of 1%; of the well costs. Unfortunately, many historical instances can be used to demonstrate that well planning costs were sacrificed or avoided in an effort to be cost conscious. The end result often is a final well cost that exceeds the amount required to drill the well, if proper planning had been exercised. Perhaps the most common attempted shortcut is to minimize data-collection work. Although good data can normally be obtained for small sums, many well plans are generated without the knowledge of possible drilling problems. This lack of expenditure in the early stages of the planning process generally results in higher-than-anticipated drilling costs. Bit programming can be done at any time in the plan after the historical data have been analyzed. The bit program is usually based on drilling parameters from offset wells. However, bit selection can be affected by the mud plan [i.e., the performance of polycrystalline-diamond (PCD) bits in oil muds]. Casing-drift-diameter requirements may control bit sizing. Casing and tubing should be considered as an integral design. This fact is particularly valid for production casing. A design criterion for tubing is the drift diameter of the production casing, whereas the packer-to-tubing forces created by the tubing’s tendencies for movement can adversely affect the production casing. Unfortunately, these calculations are complex and often neglected. The completion plan must be visualized reasonably early in the process. Its primary effect is on the size of casing and tubing to be used if oversized tubing or packers are required. In addition, the plan can require the use of high-strength tubing or unusually long seal assemblies in certain situations.

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HydrocarbonZ Educational Services

Petroleum Engineering Gate – 2016


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