mud programme
DESCRIPTION
Mud ProgrammeTRANSCRIPT
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Mud ProgramA comprehensive drilling program should always be included as part of the preparations for drilling a well. It is beyond the scope of this manual to include details of mud engineering and mud chemistry,
however, some of the options which have to be decided upon at the well planning stage will be discussed. Once the drilling engineer has
formulated the general parameters for the mud system he needs, specialist service companies are often used to define the detailed
specifications and material consumption for each interval.
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Mud ProgramThe engineer of course should always bear in mind the basic
requirements of mud system which are to:
1. Control formation pressures.
2. Carry cuttings to the surface.
3. Clean the bottom of the hole.
4. Cool and lubricate the bit.
5. Transmit hydraulic power to the bit.
6. Minimise formation damage.
7. Minimise torque, drag and pipe sticking.
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Mud Program
One system might not be able to perform these requirements throughout the course of drilling the well so it is quite possible that
several different systems are required. These might also, on occasions, be conflict between the different requirements. It is then up to the drilling engineer to use his experience and knowledge to
decide where the priority lies. The steps in preparing a mud program can generally be considered as follows:
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1. Establish the mud weight range required for each section of the hole with reference to the pore pressure and fracture gradient profiles and casing program.
2. Study the geological prognosis for potentially difficult formations.
3. Check the equivalent circulating densities, verify that the hydraulics are acceptable and determine a range of rheological parameters for each section.
4. Establish the maximum fluid loss for each interval and determine the other properties such as pH solids content.
5. Further considerations should enable optimum values to be assigned to the other parameters for the particular system to be used such as chlorides, hardness, salinity, clay content, or emulsion
stability.
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6. Review and refine the program.
7. Determine the requirements as regards surface equipment for treating and handling the mud.
8. Develop contingency plans, if thought necessary for potential hole problems such as lost circulation or stuck pipe.
9. Estimate the material requirements per interval.
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Mud Program
When good offset well information is available this planning process is made much easier and the emphasis then should be on improving previous programs. Careful study of all the relevant data should at
least result in the reduction of the mud system costs and could result in a significant reduction in drilling time.
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Water Based MudsThese are the most frequently used types of mud, often being based
on fresh water with the addition of weight material, clay or polymers and various other chemicals to produce the desired properties.
When drilling through some shale sections however, the use of fresh water can cause the shale to swell and hole problems due to
sloughing can follow. When this is anticipated an inhibited system can be built up with the addition of gypsum, lime or potassium
chloride. Salt water based muds, nearly always used offshore, could also be classed as inhibited muds. If large sections of salt are to be drilled then in order to eliminate the development of large cavities,
the mud system would need totally inhibited by initially saturating it with salt.
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Water Based MudsDispersed systems are often run especially when drilling through high
activity clays. These systems include thinners or dispersants to make
the clay platelets separate in the water phase and provide
better viscosity and filtration control. A gel-lignosulphonate is a
commonly used dispersed system. Typical viscosifiers for water based
systems are bentonite and polymers such as HEC and CMC.
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Water Based MudsTo great a viscosity caused by excessive colloids, undesirable drill
solids or contaminants such as cement can result in gel strengths and
yield points that are too high. This can be treated by the addition of
more water (which in turn might require the use of more barite and
other chemicals) or by adding thinners to the system if the other mud
properties are not restrictive.
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Water Based MudsAll muds will lose fluid to a permeable formation and create a filter
cake. To reduce the degree of invasion of the formation by mud filtrate,
fluid loss agents are added to the mud to help make the
filter cake thin and only semi-permeable. Due to the chemical make-
up of drilling fluids and the nature in which they react the pH or a
water-based fluid should be maintained in the alkaline range. This is
usually done with the addition of caustic soda to compensate for any
acidic chemicals or contaminated water.
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Water Based Muds
High density water based systems often give rise to solids control
problems. Extra solids will originate from the drilled formation, weight
material, gels and other chemicals. Simply diluting the system with
more water in order to restore the balance can be a very costly solution
since it often results in additional chemicals being consumed and a
wasteful volume of mud being built.
The proper solution to employ for when such problems are
anticipated is to plan for the use of good solids control equipment and
to plan in advance for suitable chemical additions to reduce the
hydration of formation clays and provide filtration control.
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Oil Based MudsMost modem oil base mud systems use a mineral oil phase that is more environmentally acceptable than previously used diesel oil
phases. These systems have been the cause of some very significant reductions of hole problems and improved drilling performances when used in sections containing hydratable formations. In such circumstances the water phase of the system (usually from 5% to
30%) needs to have a salinity level greater than that of the formation. This is controlled by additions of calcium chloride.
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Oil Based MudsEmulsifiers are used to form an oil film completely round the water
droplets. Their performance can be improved by ensuring the mud is
well "sheared" usually with mud guns. The water phase helps to
support barite, contributes to gel strengths and viscosity, acts as a fluid
loss agent and allows many of the other chemicals additives to dissolve.
The stability of the oil/water emulsion is measured by recording the
mud's electrical stability though if contaminants such as magnesium
chloride are present then this test can be invalid. In this case the HP/HT
fluid test can be performed and the filtrate checked for traces of water.
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Oil Based MudsSpecial additives to act as emulsifiers, viscosifiers, dispersants and
fluid-loss agents are available for use with oil based systems. Products are also provided for formulating cement spacers that promote the
water wetting of oil wet surfaces. The viscosity of clean oil muds is highly temperature sensitive and requires careful attention. It is also
usual to run excess lime as a contingency against acidic gasses such as hydrogen sulphide or carbon dioxide.
As stated modern oil based systems, although expensive to build and maintain can prove very cost efficient in the right circumstances. They
should always be considered for use, logistics and legislation permitting
in potentially troublesome or deviated holes.
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Oil Based MudsOne inconvenience is their readiness to completely absorb gas in
solution at even fairly low pressure and then release it suddenly when
the pressure is reduced. This can make a gas influx into the
wellbore very difficult to detect until it is circulated up nearly to
surface. Its presence then can often be felt very drastically.
The oil's ability to retain its temperature and cause ventilation
problems in enclosed shaker and pit rooms is another inconvenience as
might be the need to modify some of the rig's fluid handling and
treatment equipment if it is not already designed for working with oil
based systems.
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BrinesBrines are used extensively in completion and workover operations where a low solids content is important. They are used occasionally
in exploration or appraisal wells for the testing phase for similar reasons. In order to be effective they should be filtered prior to use.
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Treatment Equipment
Once the mud system has been planned it remains to make sure that the rig has suitable handling and treating equipment available. It would make little sense for example to design an expensive oil
based system and then find that its weight could only be controlled by dilution due to the rigs inadequate solids control equipment.
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Treatment Equipment
Most rigs have a standard circulating system however some tend to be more flexible and hence better than others. This is particularly true of offshore units. The problem concerning maintaining and conditioning mud properties always revolves around the solids control equipment. It should be designed to remove very small
particles down as small as one micron. The following are some of the solids control equipment essential to good operations:
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Shale ShakerThis is the most important component in the system since it removes the major portion of the drilled solids circulated out of the wellbore. The choice of a particular design of shaker can be critical when oil based muds are to be used due to the strict control on the amount of oil discharged with cuttings. Some designs are more successful in stripping oil off the cuttings than others .
Mud CleanersBy employing both desilting hydroclones and fine mesh vibrating screens, a mud cleaner can effectively remove fine drilled solids from weighted muds without losing excessive weighting material.
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CentrifugeThe last stage of 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 based muds.
Centrifuges are not designed to cope with very large through put volumes since in general they are only used intermittently to process
the mud being circulated.
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Bit & Hydraulics ProgramSelecting the right bit program for the well to be drilled involves
careful evaluation of the drilling conditions. Once again it is made a lot easier if good offset well data is available to provide a good
initial starting point. There is now a wide range of tricone and PDC bits to select from making correct programming that much harder. The bit program is an important part of the well planning process.
Remember minimum cost per foot is the criteria, once the bit selection has been made the hydraulic parameters need to be
optimised to complete the programme.
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Bit SelectionThe sequence of factors that have to be taken into account when selecting a bit for a particular section of hole are as follows:
1. Formation Hardness
2. Formation Abrasiveness
3. Mud System
4. Directional Considerations
5. Rotary System.
Although other parameters occasionally have to be taken into consideration these are the main factors.
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Formation TypesEven if no close offset well information is available the performance
of bits in similar formations elsewhere can sometimes give an indication of what to expect. All the major bit manufacturers carry
large data bases with this type of information.
Rock bits for soft formation are designed to drill by applying a shearing and twisting action. In such formations, the limiting factor
on rate of penetration is likely to be the ability to keep the hole clean rather than the cutting ability of the bit.
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Formation TypesIn soft to medium formations that are not too sticky, PDC bits
have proved to be cost effective over long hole sections,
particularly in oil based muds. Sticky formations can best be
drilled by bits which have good interfitting teeth and the
provision of a centre jet nozzle. Hard and abrasive formations require a bit that drills by a crushing action that exceeds the compressive strength of the rock. Good gauge protection is
also needed.
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Formation Types
Since such formations are usually found deep in a well, where the cost
of a round trip becomes significant, they can best be drilled by journal
bearing rock bits with heavy gauge protection. Some PDC designs are
also very effective in these types of formations and can be very cost
effective. PDC bits can be very effective in drilling the harder
formations and they are preferred for the deep slim hole sections since
the have no moving parts which can fail prematurely.
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Mud Type
Whenever oil based muds are used PDC bits tend to produce faster rates of penetration than other types of bit, particularly in shale’s and mudstones. Non-sealed bearing bits are sometimes
prone to bearing failure if the mud contains a lot of fine abrasive solids. Sealed bearings are the obvious choice in such a situation.
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Directional ConsiderationsDirectional control of a well is achieved by selection of the
correct bottom hole assembly, bit selection however can also have a direct effect. High weight on bit can aggravate
directional problems.
As PDC bits use relatively low weight on bit to drill, they are often more suitable. PDC bits also tend to reduce azimuth
movement. Steerable downhole tools which reduce the number of trips once required to change BHA’s make the PDC bit
even more viable economically.
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Rotating SystemsBits can be turned either by rotary table, top drive or down hole motor such as turbines and positive displacement motors. The advantage of using a downhole motor is that torque is applied
directly to the bit and the amount of wear to the drill stem and casing is reduced. Turbines can rotate the bit at up to a 100 rpm
consequently they are well suited to running PDC and diamond bits. The speed is proportional to the flow rate and the torque
proportional to the square of the flow rate and the mud density.
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Rotating Systems
Several types of positive displacement motor are available depending on the rotary speed and torque combination required. The 5 stator 6 rotor design produces a low speed and high torque whilst the 1 stator 2 rotor and multi - lobe designs produce a higher speed but less torque. Their relatively low speeds ranging from 230 to 580
rpm make these motors suited both for rock bit and PDC.
General points to cover in a bit program would be to make a junk run prior to running a PDC bit. Even the smallest piece of junk can
quickly destroy a very expensive bit.
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HydraulicsOnce a mud program has been outlined then a full hydraulics study would cover the following points.
1. Flow regimes and control of hole erosion, wash outs, cuttings removal and hole cleaning.
2. Evaluation of friction pressures and control of swab and surge pressures.
3. Surface equipment requirements.
4. Transmission of hydraulic power to the bit, (turbine, positive displacement motor etc.)
5. Optimisation of bit hydraulics
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Flow Regimes Drilling fluids flow in either a laminar or turbulent manner or in a
state of transition between the two. Laminar flow is usually preferred in the annulus since this is less conducive to hole erosion. A high yield-point mud will help lift the cuttings. It is imperative to
exceed cutting slip velocity in the annulus without creating mass erosion. Critical velocity is that velocity which changes flow from
laminar to turbulent.
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Friction Pressure
The behaviour of a fluid under dynamic conditions can be described as a mathematical model; the ones most commonly used in the
oilfield are Bingham’s plastic and power law. To calculate friction losses the model to be used is chosen and the equation for the
appropriate flow regime applied i.e. laminar or turbulent. Separate equations are used to calculate pressure drop across the bit. When
calculating swab and surge pressures laminar flow equations should be used since pipe pulling and running speeds seldom cause the
critical velocity to be exceeded.
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Jet Optimisation A lot of research has been performed in an effort to optimise
bit hydraulics and achieve maximum hole cleaning and penetration rates. The variables commonly optimised are impact force and hydraulic horsepower. Many computer
programmes, tables and graphs are now readily available to help achieve an optimum program.
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Jet Optimisation It can be shown mathematically that the maximum jet impact force is obtained when circulation rates and nozzle sizes cause
48 of the pump pressure available to be lost at the bit. Similarly, hydraulic horsepower is optimised when 65 of the available pump pressure is applied across the bit. The correct application will depend on what is being run above the bit.
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Jet OptimisationNozzle selection is decided upon by determining a suitable pump rate and maximum operating pressure. By calculating the pressure drop in the surface equipment, drill stem and annulus, the amount of pressure drop across the bit can be
found. Solving the bit pressure drop equation for the flow area will then allow nozzle size to be determined.